Southwest Power Pool REGIONAL STATE COMMITTEE Southwest ... · the Office of Electric Reliability...

Southwest Power Pool REGIONAL STATE COMMITTEE

Southwest Power Pool Campus, Little Rock, AR October 29, 2012

• M I N U T E S •

Administrative Items: The following members were in attendance:

Kevin Gunn, Missouri Public Service Commission (MOPSC) Patrick Lyons, New Mexico Public Regulation Commission (NMPRC) Dana Murphy, Oklahoma Corporation Commission (OCC) Donna Nelson, Public Utility Commission of Texas (PUCT) Olan Reeves, Arkansas Public Service Commission (APSC) Mike Siedschlag, Nebraska Power Review Board (NPRB) Thomas Wright, Kansas Corporation Commission (KCC)

President Olan Reeves called the Regional State Committee (RSC) meeting to order at 1:00 p.m. with roll call and a quorum was declared. He then requested a round of introductions. There were 105 in attendance either in person or via phone (Attendance & Proxies – Attachment 1). President Reeves asked for approval of the July 30, 2012 meeting minutes (RSC Minutes 7/30/12 - Attachment 2). Tom Wright moved to approve the minutes as presented; Patrick Lyons seconded the motion. The minutes were approved. UPDATES

RSC Financial Report Paul Suskie provided the RSC Financial Report (Financial Report – Attachment 3). Mr. Suskie reported that the Seams Cost Allocation line item is for cost budgeted in 2011 but expended in 2012. He also reported that travel costs were over budget but not significantly. SPP Report Nick 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 presented a high level update on the Integrated Marketplace. He stated that SPP had benefited from lessons learned in talks with the Electric Reliability Council of Texas (ERCOT) and thanked Trip Dogget for his assessment report. The SPP program is being monitored utilizing an outside consultant and SPP’s Internal Audit staff, all reporting directly to Mr. Brown. The current status of the seven areas of the program is: four green, two yellow and one orange. Regarding the orange status, SPP is working with the vendor at issue (Alstom) to address delays. A more detailed report will be provided at the October 30 SPP Board meeting. Mr. Brown stated that the Arkansas Public Service Commission had issued an order on October 26 approving Entergy’s request to join the Midwest ISO. Mr. Brown reported that SPP will continue to argue

Regional State Committee October 29, 2012

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that SPP is the better choice; will be aggressive in protecting its Members interest; and will work to help make the integration fair to all. RSC will need to continue to help with regional cost allocation, which will take on a whole new meaning. SPP is reviewing the order and will have recommendations for the RSC in the near future. FERC 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.

BUSINESS MEETING

Election of Officers for 2013 President Reeves requested nominations for the annual election of officers. Kevin Gunn nominated the following RSC officers for 2013: Tom Wright for President, Dana Murphy for Vice President and Donna Nelson for Secretary/Treasurer. Michael Siedschlag seconded the motion, which passed unanimously. Approval of 2013 RSC Budget Paul Suskie presented the 2013 RSC Budget for approval (20113 Budget – Attachment 4). Dana Murphy moved to approve the 2013 RSC budget and that the RSC establish a subcommittee of RSC members to look at consultant contacts on a go forward basis to deal with various upcoming issues facing the RSC. Tom Wright seconded the motion; the motion passed unanimously. President Reeves assigned a subcommittee to consist of: Dana Murphy, Tom Wright and Michael Siedschlag. REPORTS/PRESENTATIONS Cost Allocation Working Group Report Pat Mosier provided the Cost Allocation Working Group report (CAWG Report – Attachment 5). Ms. Mosier presented an overview of the group’s activities. She then presented the following recommendations:


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• In order to provide the best support for each rotating President of the RSC, the CAWG considered and recommends that:

The CAWG Chairman position be appointed each year by the RSC, such that, the Chairman

of the CAWG is from the same state as that of the President of the RSC. Tom Wright moved to approve; Kevin Gunn seconded the motion. The motion passed unanimously.

• An observation was made at the July RSC meeting that Attachment J is very unclear as to when

the required 15 days notice for a waiver of the Safe Harbor Limits is to occur. The CAWG therefore recommends approval of BPR 25 as amended by the Markets and Operations Policy Committee (MOPC):

A customer may submit a waiver request for waiver of the Safe Harbor Limit, pursuant to

Attachment J Section III.C.1, at any time after the posting of the first iteration of the aggregate study, but not later than 15 days after being notified that the aggregate study is final. Kevin Gunn moved to approve BPR 25 as amended; Dana Murphy seconded the motion. The motion passed unanimously.

• MOPC directed the Business Practices Working Group (BPWG) to identify a non-discriminatory

method that the Transmission Provider will use to calculate the amount of costs that are eligible for consideration for waivers to the Safe Harbor provisions of Attachment J. Addressing the five-year commitment period, the CAWG recommends the BPR 32 recommendation for calculation: ...by multiplying the number of years which the Duration of the Transmission Customer’s commitment to the new or changed Designated Resource exceeds the five year minimum commitment period, by 2.5%, multiplied by $180,000 per MW. Tom Wright moved to approve BPR 32; Kevin Gunn seconded the motion. The motion passed unanimously.

Ms. Mosier provided an update of the RSC position of support regarding the SPP Order 1000 filing. RSC issued a letter specifically supporting SPP’s regional filing as well as providing individual state support.

Order 1000 Regional Update

Paul Suskie provided an update of Order 1000 analysis of both regional and interregional requirements (Order 1000 Update – Attachment 6). Mr. Suskie also provided information regarding the elimination of the Right of First Refusal (ROFR) and as a result, 4 limitations that would be added to Commission approved tariffs and agreements.

Order 1000 Regional Compliance Filing

Mr. Suskie reviewed TRR 077 revisions for the SPP Regional Compliance Filing for Order 1000, which will be presented to the SPP Board of Directors for approval on October 30, 2012. The filing will be submitted in two weeks.

Order 1000 Interregional Update Seams Steering Committee (SSC) Update Paul Malone presented a SSC update including an overview of responsibilities, SPP’s proposed interregional coordinated planning process, and a compliance timeline (SSC Report – Attachment 7).

Interregional Cost Allocation Task Force Update Sam Loudenslager reported on interregional cost allocation efforts of the Interregional Cost Allocation Task Force (ICATF Efforts – Attachment 8). The group approved principles and guidelines to use in discussions with seams neighbors, developed projects and will try to reach agreement with neighbors.


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CAWG’s Recommendation of Cost Allocation of Interregional Project Costs Pat Mosier provided CAWG background regarding interregional cost allocation and offered cost assignment options presented to the CAWG as: 1) Assign all seams costs to the Regional Rate (i.e. Highway) and 2) Allocate seams costs pursuant to currently approved allocation methods (i.e. Highway/Byway dependent upon voltage of Seams Project) (CAWG’s Interregional Cost Allocation Recommendation – Attachment 9). Ms. Mosier stated that the CAWG passed the following recommendation with New Mexico and Texas voting against: CAWG recommends that the Regional State Committee adopt a 100% Regional allocation of costs related to interregional projects selected pursuant to interregional planning processes.

Following much discussion, Patrick Lyons moved to approve:

Adopt current Highway/Byway treatment of SPP’s portion of costs for interregional projects, with the option to seek waiver of that treatment if the interregional project can be shown to provide regional benefits. Donna Nelson seconded the motion, which failed with New Mexico and Texas for and five votes against.

Kevin Gunn moved to approve the CAWG recommendation:

CAWG recommends that the Regional State Committee adopt a 100% Regional allocation of costs related to interregional projects selected pursuant to interregional planning processes. Tom Wright seconded the motion. All voted in favor with New Mexico and Texas against.

Michael Siedschlag requested that the CAWG continue to monitor cost allocation and that the RSC revisit at the January 2013 meeting if circumstances warrant.

Waiver Request Lanny Nickell provided an overview of the transformer waiver process and presented background for the Nebraska Public Power District’s Neligh Waiver Request (NPPD Waiver Request – Attachment 10). Mr. Nickell stated that the MOPC recommends approval of the NPPD Neligh Transformer Waiver Request.

CAWG’s Recommendation on Waiver Requests Pat Mosier reviewed the CAWG discussion and recommendation regarding the NPPD waiver request. She then requested the following for endorsement from the RSC: The CAWG recommends that the RSC endorse the recommendation for the SPP Board to approve the NPPD Neligh Transformer Waiver Request. Tom Wright moved to endorse; Kevin Gunn seconded the motion. The motion passed unanimously.

Update on Balanced Portfolio Lanny Nickell provided an update on the Balanced Portfolio (Balanced Portfolio – Attachment 11). Special Studies Update for the Mississippian Dana Murphy provided information regarding the Mississippian oil play (Mississippian – Attachment 12). Ms. Murphy stressed that it is extremely important to bridge the gap between producers, utilities, the Oklahoma and Kansas Corporation Commissions and SPP. Ms. Murphy thanked Carl Monroe, Paul Suskie and Tom Wright in helping with this effort. Mr. Monroe provided information on provisions for abnormal load growth in the SPP Tariff (Load Growth – Attachment 13). Integrated Marketplace Update Bruce Rew provided an update on the Integrated Marketplace (IM Report – Attachment 14). Mr. Rew stated that there is an Integrated Market Forum on November 7 for state regulators.


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Future RSC Matters President Reeves thanked everyone for their help during his tenure as President of the RSC. This will be his last meeting as President. Scheduling of Next Regular Meeting, Special Meetings or Events: President Reeves noted that the next regularly scheduled meeting is on January 28, 2013, in New Orleans. With no further business, the meeting adjourned at 4:45 p.m. Respectfully Submitted, Paul Suskie

Monday, October 29, 2012

1:00 - 5:00 p.m.

Southwest Power Pool Offices

Little Rock, Arkansas

1. CALL TO ORDER 2. PRELIMINARY MATTERS

a. Declaration of a Quorum b. Adoption of July 30, 2012 Minutes

3. UPDATES a. RSC Financial Report b. SPP c. FERC

4. BUSINESS MEETING a. Election of Officers for 2013 (VOTING ITEM) b. Approval of 2013 RSC Budget (VOTING ITEM)

5. REPORTS/PRESENTATION

a. CAWG Report ........................................................................................................................ Pat Mosier This Report provides an update on CAWG activity, including recommendations to the

RSC and CAWG’s future schedule.

b. Order 1000 Regional Update ............................................................................................ Paul Suskie Order 1000 Regional Compliance Filing .......................................................................... Paul Suskie This report will update the RSC on the efforts to finalize Tariff Language in accordance with

the policy decision adopted at the July RSC/BOD meetings and filing plans. c. Order 1000 Interregional Update

Seams Steering Committee Update ............................................................................... Paul Malone This report will update the RSC on the efforts of the SSC on Order 1000 and the status of

the SSC’s efforts to address the interregional planning requirements of Order 1000.

Interregional Cost Allocation TF Update (VOTING ITEM) .................................. Sam Loudenslager This report will update on the efforts on how SPP’s portion of Interregional Projects should

be cost allocated. CAWG’s Recommendation on Cost Allocation of Interregional Project Costs ............ Pat Mosier

This report will be the CAWG’s recommendation to the RSC on how SPP’s portion of

Interregional Projects should be cost allocated.

d. Waiver Request (VOTING ITEM) ..................................................................................... Lanny Nickell

This report will provide a summary of the request by Nebraska Public Power District

waiver to base plan fund cost that exceed the safe harbor limit.

CAWG’s Recommendation on Waiver Requests ............................................................. Pat Mosier The CAWG has a recommendation for the RSC on the Waiver request.

e. Update on Balance Portfolio ................................................................. Lanny Nickell & Paul Suskie This report will provide an update on the status of SPP’s Balanced Portfolio. This will include an

update on cost estimates, FERC filing, etc. f. Special Studies Update for the Mississippian Shale ..................................................... Carl Monroe

This report will provide an update on the Mississippian Shale in N. Oklahoma and S. Kansas and

related SPP studies. g. Integrated Marketplace Update .......................................................................................... Bruce Rew

This report will update the RSC on the SPP’s efforts in developing and implementing the

Integrated Marketplace (IM).

6. FUTURE RSC MATTERS

7. SCHEDULING OF NEXT REGULAR MEETING, SPECIAL MEETINGS OR EVENTS

a. SPP Training for State Regulators: Nov. 7, 2012 - Integrated Marketplace Staff Training for State Commissions –– Little Rock, AR

b. RSC Meetings: 2013 January 28 ....................................................... Little Rock April 29 ........................................................... Kansas City July 29 ................................................................... Denver October 28 ....................................................... Little Rock 2014 January 27 .............................................................. Austin April 28 ...................................................... Oklahoma City July 28 ................................................................... Omaha October 27 ....................................................... Little Rock

8. ADJOURNMENT

__________________________________________________________________________

* NOTE: ADDITIONAL INFORMATIONAL MATERIAL Attached to the RSC’s meeting agenda and background material is additional material that is

either for informational or reporting purposes.

Southwest Power Pool REGIONAL STATE COMMITTEE

Marriott Country Club Plaza, Kansas City, Missouri July 30, 2012

• M I N U T E S •

Administrative Items: The following members were in attendance:

Kevin Gunn, Missouri Public Service Commission (MOPSC) Patrick Lyons, New Mexico Public Regulation Commission (NMPRC) Dana Murphy, Oklahoma Corporation Commission (OCC) Dana Murphy, proxy for Donna Nelson, Public Utility Commission of Texas (PUCT) Olan Reeves, Arkansas Public Service Commission (APSC) Mike Siedschlag, Nebraska Power Review Board (NPRB) Thomas Wright, Kansas Corporation Commission (KCC)

President Olan Reeves called the meeting to order at 1:00 p.m. with roll call and a quorum was declared. He then requested a round of introductions. There were 106 in attendance either in person or via phone (Attendance & Proxies – Attachment 1). President Reeves asked for approval of the April 23, 2012 meeting minutes (RSC Minutes 4/23/12 - Attachment 2). Patrick Lyons moved to approve the minutes with one minor change; Tom Wright seconded the motion. The minutes were unanimously approved as amended. UPDATES

RSC Financial Report Paul Suskie provided the RSC Financial Report (Financial Report – Attachment 3). Mr. Suskie reported that the RSC is over budget due in part to travel expenses. Travel may need to be increased when drafting the 2013 Budget, which should also consider staff travel to the CAWG meetings. The final bill shown for the Seams Cost Allocation expense item was actually a 2011 Budget item. The 2013 Budget will be approved at the October 29 meeting. SPP Report Mr. Brown announced that SPP held a ribbon-cutting for the new facility on July 9 and moved 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. The building was on schedule and slightly under budget. After 67 years in leased space, the new facility is 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. A push on staffing helped with the change of status as well as relying more on staff than external consultants. Internal and external audits continue to be performed to assess project status. Dana Murphy requested that members receive data in a timely fashion, that the time frame for integrating the system is shared with the members, and that the stakeholders are made aware of any additional costs with the system.

Regional State Committee July 30, 2012

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Mr. Brown announced that SPP received a senior unsecure rating of A from Fitch. FERC 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. 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 requirements of 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.

BUSINESS MEETING

No business was reported. REPORTS/PRESENTATIONS Cost Allocation Working Group Report Pat Mosier provided the CAWG report (CAWG Report – Attachment 4). Ms. Mosier presented a quarterly


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overview of the group’s activities. Items addressed were:

• SPCTF on Order 1000• SPP Working Groups/Task Forces• Public Policy Requirements in Planning Survey• Ongoing consideration for Treatment of Cost overruns• Waiver Request: OMPA & AECC

Order 1000

Order 1000 ROFR Paul Suskie updated the group on the efforts of the SPCTF on Order 1000 and the Task Force’s Report recommendations to comply with Order 1000/1000-A on policy issues including the Right of First Refusal (ROFR) and the possible impacts on the Highway/Byway cost allocation methodology (Order 1000 – Attachment 5). Mr. Suskie stated that the group seeks RSC’s input on SPP’s compliance filing on ROFR in three areas:

(1) Whether or not the RSC supports SPP’s compliance filing seeking to maintain a ROFR for projects (100 kV & below) in the five SPP zones with more than one transmission owner? (The five zones with multiple transmission owners are AEP, OG&E, SPS, Mid‐Kansas, and Westar.)

(2) Whether or not the RSC supports SPP’s compliance filing seeking to maintain a ROFR for SPP projects funded under the RSC’s Byway cost allocation methodology (100 kV to 300 kV upgrades)?

(3) Whether or not the RSC supports SPP’s compliance filing seeking to maintain a ROFR for short‐term reliability projects that are needed to be in‐service before SPP can complete a Transmission Owner Selection Process and before a selected owner could obtain necessary state approvals for a project that is needed to maintain reliability?

Following discussion including that CAWG supports the SPCTF position, Tom Wright moved to support the areas outlined; Dana Murphy seconded the motion. The motion passed unanimously. Patrick Lyons and Dana Murphy suggested that the RSC should draft a letter to be included in SPP’s Order 1000/1000-A compliance filing showing the RSC’s support to retain ROFR for certain projects. Following discussion, Dana Murphy moved to draft a letter to the SPP Board of Directors and Nick Brown and Paul Suskie showing support for the retention of ROFR; Patrick Lyons seconded the motion. The motion passed unanimously.

SPCTF on Order 1000 Ricky Bittle provided an update on SPCTF on Order 1000 (SPCTF Update – Attachment 6). Mr. Bittle stated that SPP had received an extension for compliance filings addressing the Order 1000 regional transmission planning and cost allocation requirements. The compliance filings addressing the interregional coordination and cost allocation requirements are due by April 11, 2013. Mr. Bittle reviewed eight recommendations to the SPP Board of Directors from the 1st SPCTF on Order 1000 Report:

1. Recommendation as to the Transmission Upgrades for which SPP should Seek to Retain the Federal ROFR.

2. Recommendation as to What Model SPP Should Use to Select Transmission Owners for Projects Without a Federal ROFR.

3. Recommendation as to Transmission Owner Qualification Criteria. 4. Recommendation as to Changes to SPP’s Membership Agreement and


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OATT to Remove the Federal ROFR. 5. Recommendation as to Application of Order 1000 to Future SPP

Projects. 6. Recommendation as to Consideration of Transmission Needs Driven

by Public Policy. 7. Recommendation as to Information and Data from Merchant

Transmission Developers. 8. Timeline for Compliance Filing.

He then presented the six recommendations to the SPP Board of Directors from the 2nd SPCTF on Order 1000 Report:

1. Recommendation of Transmission Owner Selection Criteria 2. Recommendation of Qualification Criteria for Applicant

Transmission Owners. 3. Recommendation on the Mobile‐Sierra Doctrine. 4. Recommendation on the Retention of ROFR for Short‐Term

Reliability Projects. 5. Recommendation on Establishment of a Need by Date,

Notice of Such Date, and Requirement to meet Deadlines. 6. Recommendation of a required Deposit from the selected

transmission owner

The SPCTF recommendations for SPP’s compliance with Orders 1000/1000-A will be presented to the SPP Board of Directors on July 31, 2012. Seams Steering Committee (SSC) Paul Malone presented an SSC update (SSC Report – Attachment 7). Mr. Malone provided an overview of Order 1000 interregional planning requirements and stated that currently SPP was planning for three seams entities: MAPPCOR, AECI and MISO. The SSC has formed a Seams FERC Order 1000 Task Force (SFOTF) to develop an SPP proposal to address these requirements. Mr. Malone then presented a high level overview of the proposed process (Option 1), which the SSC unanimously approved as the SPP proposal to use in negotiating with each neighbor (See Attachment 7).

Interregional Cost Allocation TF (IRCATF) Update Chairman Kevin Gunn provided the IRCATF update (IRCATF Report – Attachment 8). Following a brief description of the group, Chairman Gunn presented General Benefit Principals and Interregional Cost Allocation Principles (as stated in the report). He then moved for adoption of these principles; Tom Wright seconded the motion. The motion passed unanimously.

OMPA Waiver Request (75196276) Lanny Nickell reviewed the Aggregate Study Waiver Process under Attachment J and provided past history (Waiver Requests Report – Attachment 8). Mr. Nickell then presented OMPA Request 75196276 and offered the following recommendations:

• CAWG recommends the cost of this upgrade not be

directly assigned to the customer.

• MOPC recommends that the cost of this upgrade notbe allocated to OMPA’s request based on the increased flow being less than 1 MW.

• SPP Staff recommends that the cost of this upgradenot be allocated to OMPA’s request.


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CAWG also recommended that the cost for improvements be granted Base Plan funding. Dana Murphy moved to approve the OMPA Waiver Request as recommended by the CAWG; Kevin Gunn seconded the motion. The motion passed unanimously.

AECC Waiver Requests (76585958 & 76586012) Lanny Nickell provided background for the AECC Waiver Requests 76585958 and 76586012. He then presented the following recommendations:

• CAWG recommends increase in Safe Harbor limit to $12,622,500.

n 1 MW.

• MOPC recommends the cost of the two upgrades not be allocated to AECC’s requests based on the increased flow being less tha

• SPP Staff recommends that the cost of these two upgrades not be allocated toAECC’s requests.

Tom Wright moved to approve AECC Waiver Requests as recommended by the CAWG; Michael Schiedschlag seconded the motion. The motion passed unanimously.

During discussion, the group asked if the waiver process needed to be reviewed. The group was informed that the MOPC has requested the Business Practices Working Group (BPWG) review this process and consider improvements regarding small waiver requests. Integrated Marketplace Update Bruce Rew provided an update on the Integrated Marketplace (IM Report – Attachment 11).

Future RSC Matters Future RSC matters include the election of Officers in October 2012 and the adoption of the 2013 Budget. Scheduling of Next Regular Meeting, Special Meetings or Events: President Reeves noted that the next regularly scheduled meeting is on October 29 in Little Rock at the new SPP campus. With no further business, the meeting adjourned at 4:35 p.m. Respectfully Submitted, Paul Suskie

Regional State CommitteeFor the Nine Months Ending September 30, 2012

Budget vs. Actual

YTD Actuals YTD Budget Variance

Income Other Income 373,088 213,250 159,838 Total Income 373,088 213,250 159,838

Expense Travel 115,951 82,500 33,451 Meetings 13,786 18,750 (4,964) Audit - - - Administrative Costs - 750 (750) RSC Consultant 44,292 86,250 (41,958) Technical Conference - 25,000 (25,000) Seams Cost Allocation * 199,059 - 199,059 Total Expense 373,088 213,250 159,838

Net Income (Loss) - - -

* Seams Cost Allocation line item is for cost budgeted in 2011 but expended in 2012.

2012 BUDGET2013 BUDGET

Proposed2014 BUDGET

Proposed2015 BUDGET

Proposed

Expense CategoryTravel & Meetings

Travel $122,000 $166,000 $174,300 $183,015Meetings $34,000 $25,000 $25,000 $25,000

Total Travel & Meetings $156,000 $191,000 $199,300 $208,015

Administrative

SOUTHWEST POWER POOLREGIONAL STATE COMMITTEE

BUDGET INFORMATION

AdministrativeAnnual Audit $2,100 $2,300 $2,300 $2,300Other Administrative $1,000 $1,000 $1,000 $1,000

Total Administrative $3,100 $3,300 $3,300 $3,300

Consultants $115,000 $100,000 $100,000 $100,000

Technical Conference $120,000 $50,000 $50,000 $50,000

Cost Benefit Studies $0 $0 $0 $0

TOTAL EXPENSES $394,100 $344,300 $352,600 $361,315

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Report to the Regional State Committee

October 29, 2012

COST ALLOCATION WORKING GROUP (CAWG)

CAWG REPORT TO RSC

S tS tSeparate Separate RecommendationRecommendation

Separate RecommendationSeparate Recommendation

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CAWG REPORT TO RSC

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CAWG REPORT TO RSC

In order to provide the best support for each rotating President of the RSC, the CAWG considered and now recommends to the RSC that:

The CAWG Chairman position be appointed each year by the RSC, such that, the Chairman of the CAWG is from the same state as that of the President of the RSC

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RSC.

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CAWG REPORT TO RSC

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CAWG REPORT TO RSC

Attachment J requires that a request for a waiver of the Safe Harbor Limits must be made within 15 days of “notice” provided by the Transmission Provider. When that “notice” occurs has not always been clear which has resulted in several waiver requests being made very early in the studyseveral waiver requests being made very early in the study process when cost impacts are also not as clear.

The RSC made that observation in its July 2012 meeting applicable to AECC’s waiver request.

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CAWG REPORT TO RSC

To address the uncertainty and allow a customer the ability to make its request when additional information through subsequent studies is available, the following language was added to the business practices:

A customer may submit a waiver request,y qpursuant to Attachment J Section III.C.1, at anytime after the posting of the first iteration of theaggregate study, but not later than 15 daysafter being notified that the aggregate study is final.

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CAWG REPORT TO RSC

At its October meeting, MOPC amended BPR No. 25 to clarify that the business practice related to the Safe Harbor provisions of the tariff only, with that amendment as follows:

A customer may submit a waiver request for waiverof the Safe Harbor Limit pursuant to Attachmentof the Safe Harbor Limit, pursuant to AttachmentJ Section III.C.1, at any time after the postingof the first iteration of the aggregate study, butnot later than 15 days after being notifiedthat the aggregate study is final.

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CAWG REPORT TO RSC

The CAWG agrees that the change provided by BPR No. 25 (including the clarification by MOPC) is appropriate, is more clearly defined, and provides the opportunity for better timing in pursuing a request for waivers of the Safe Harbor provisions. Therefore:

CAWG recommends the RSC support the approved BPR025.

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CAWG REPORT TO RSC

MOPC directed the BPWG to identify a non-discriminatory method that the Transmission Provider will use to calculate the amount of the costs that are eligible for consideration for waivers to the Safe Harbor provisions of Attachment J.

Specifically, the BPWG was to address the calculation of the p y,amounts requested for waivers which were tied to the length of transmission or resource contracts which exceeded the five-year minimum eligibility requirements of Attachment J for Safe Harbor treatment.

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CAWG REPORT TO RSC

Attachment J allows consideration of the waiver of Safe Harbor provisions. . .

...taking into account the extent to which the duration of the Transmission Customer’s commitment to the new or changed Designated Resource exceeds the five year commitmentDesignated Resource exceeds the five-year commitment period....

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CAWG REPORT TO RSC

In addressing this concern, BPR No. 32 amended the business practice such that the amount subject to waivers sought under this provision of Attachment J would be calculated. . .

by multiplying the number of years which the...by multiplying the number of years which the Duration the Transmission Customer’s commitmentto the new or changed Designated Resource exceeds the five year minimum commitment period, by 2.5%, multiplied by $180,000 per MW.

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CAWG REPORT TO RSC

CAWG notes that the standard calculation method set out by BPR No. 32 represents the method specifically proposed by CAWG and is the same method accepted by the RSCattendant to previous Waiver Requests brought before it. Such standard method, while not binding as to any final determination on the waiver request, provides a reasonable

d i t t h t t f th t fand consistent approach to measurement of the amount of that request. Therefore:

CAWG recommends the RSC support the approved BPR032.

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CAWG REPORT TO RSC

In its July 2012 meeting, RSC agreed to issue a letter specifically supporting SPP’s Order 1000 regional filing in which SPP seeks to retain ROFR on projects:(1) 100 kV & below which are in zones with more than

one transmission owner;

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(2) which are 100 kV to 300 kV funded under SPP’s Byway cost allocation method; and

(3) which are short-term reliability projects.

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CAWG REPORT TO RSC

As of the date the CAWG Report was provided for posting for the RSC meeting, the following states/districts have provided individual support of the RSC position:Arkansas

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New MexicoNebraska Public Power District

CAWG REPORT TO RSC

CAWG members continue to monitor identified Working Groups and Task Forces. During the quarter, the emphasis of the majority of the groups has been Order 1000 and Order 1000-A (SSC, RTWG, PCWG). In addition, of note, ESWG and its Metrics Task Force has finalized proposed additional benefit metrics

16

additional benefit metrics.

9

CAWG REPORT TO RSC

17

CAWG REPORT TO RSC

Questions:

Submitted by: Pat MosierChairman, CAWGOctober 29, 2012

18

1

Order 1000 Presentation

for the

SPP Regional State Committee

October 29, 2012

Order 1000 Requirements Analysis

2

• Analysis divides requirements into:

(1) Regional (RTO) Requirements

(2) Interregional Requirements

Order 1000 Regional (RTO) Requirements

3

Order 1000 Interregional Requirements

4

ORDERS 1000, 1000‐A, & 1000‐B“RIGHT OF FIRST REFUSAL”

5

Order 1000 ‐ Elimination of ROFR

6

ROFR Removal ‐ Public utility transmission providers must remove from theirOATTs or other FERC‐jurisdictional tariffs and agreements any provisions thatgrant a federal right of first refusal to transmission facilities that are selected in aregional transmission plan for purposes of cost allocation. [P 313] The focus ofthis requirement is transmission facilities that are evaluated at the regional leveland selected in the regional plan for purposes of cost allocation, as opposed tofacilities that are planned exclusively in the public utility transmission provider’slocal planning process and simply “rolled‐up” and listed in the regionaltransmission plan for informational purposes and analysis. [P 318 and n.299]

Applicability ‐ This requirement does not apply to the right of an incumbent utilityto build, own, and recover costs for upgrades to its existing transmission facilities,and does not alter an incumbent transmission provider’s use and control ofexisting rights of way, even if such upgrades or facilities on existing rights‐of‐wayare selected in the regional transmission plan for purposes of cost allocation. [P319]

ROFR’s 4 Limitations• Rule removing ROFR from Commission approved tariffs and

agreements is subject to four limitations:

(1) This does not apply to a transmission facility that is not selected ina regional transmission plan for purposes of cost allocation;

(2) This does not apply to upgrades to transmission facilities, such astower change outs or reconductoring;

(3) This allows, but does not require, the use of competitive bidding tosolicit transmission projects or project developers; and

(4) Nothing in this requirement affects state or local laws orregulations regarding the construction of transmission facilities,including but not limited to authority over siting or permitting oftransmission facilities.

7

Order 1000‐A; Paragraph 426.“Petitioners request clarification about whether a transmission facility is a localtransmission facility if it is selected in a regional transmission plan for purposes of costallocation and the costs are allocated to a single pricing zone in which the proposedtransmission facility is to be located, and that zone consists of more than onetransmission provider. . . . In general, any regional allocation of the cost of a newtransmission facility outside a single transmission provider’s retail distribution serviceterritory or footprint, including an allocation to a “zone” consisting of more than onetransmission provider, is an application of the regional cost allocation method and thatnew transmission facility is not a local transmission facility. “

* * * * *

“However, we recognize . . . that special consideration is needed when a smalltransmission provider is located within the footprint of another transmission provider. “

* * * * *

“Accordingly, we will address whether a cost allocation to a multi‐transmission providerzone is regional on a case‐by‐case basis based on the specific facts presented. Specificsituations may be included in a compliance filing along with the filed regional costallocation method or methods.”

8

Order 1000‐B; LaFleur Dissent Page 2After further consideration, I believe the Commissionacted prematurely in concluding that any amount ofregional funding converts an otherwise local reliabilityproject to a regional project for purposes of the ROFR. Byreaching this conclusion in the abstract, without thebenefit of considering stakeholder‐vetted proposals todefine local projects in light of the principles underlyingelimination of the ROFR and the requirement that costsmust be allocated in a manner that is at least roughlycommensurate with benefits, the Commission has deniedtransmission planning regions the flexibility it wiselyacknowledged to be necessary with respect to the zoneissue. I agree with SPP and OGE that we should providethat flexibility.8 9

SPP ORDER 1000 REGIONAL COMPLIANCE FILING

TRR 077

10

Recognize the following:• 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, 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

11

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 CriteriaOrder 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” could be confusing– Applicant TO (ATO) = Applicant– Qualified TO (QTO) = Qualified RFP Participant (QRP)– Selecting a DTO = Selecting an RFP proposal

12

• Passed unanimously by the RTWG at its October 4 conference call

• Pass unanimously by the MOPC at its October 16 Meeting

13

Tariff Revisions for SPP Regional Compliance Filing for Order 1000

will be presented to the SPP BODs

RTWG & MOPC Action on TRR 077

QUESTIONS

14

Report from the Seams Steering Committee

October 29, 2012

Paul Malone, Chair

ORDER 1000 OVERVIEW OF RESPONSIBILITIES

3

FERC Order 1000

Regional Interregional

Coordinated Planning

Cost Allocation

4

Policy Development Responsibilities

5

• Regional State Committee (RSC)• Interregional Cost Allocation Task Force (IRCATF)

Cost Allocation

• Seams Steering Committee (SSC)• Seams FERC Order 1000 Task Force (SFOTF)


SPP’S PROPOSED INTERREGIONAL COORDINATED PLANNING PROCESS

6

Interregional Coordination Requirements

7

Info/Data Sharing

Annual Data Sharing

Sharing of Regional “Needs”

& Solutions


Use Common Models,

Assumptions, & Criteria

Joint Evaluation of Interregional

Solutions

Transparency

Stakeholder input into interregional coordination procedures

Website for Interregional Materials

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 more than one planning region (exceeds Order 1000 requirements)

8

Interregional Committees

• Interregional Planning Stakeholder Committee (IPSAC)

– Stakeholders from each region

– For SPP, comprised of the SSC and other interconnected TO’s

– Advisory group

– Provides recommendations and feedback to the JPC

9

• Joint Planning Committee (JPC)

– Staff committee

– Decision making committee

– Requires agreement of both regions

Proposed Process

10

Proposed Process cont.

11

Proposed Process cont.

12

PATH TO COMPLIANCE

13

Utilize Two Avenues

JOA Updates

Coordinated Planning Process

SSC Review JOAs filed with FERC

14

OATT Revisions

Interregional Cost

Allocation

New Project Type & Regional Review

RTWG, MOPC,

CAWG, RSC, & Board

Proposed Compliance TimelineAssuming 32 Day Extension

January 2013 Policy

Decisions

RTWG Finalize OATT Changes and Staff,

working with SSC, Finalize JOA Language

April 2013 MOPC, RSC &

Board Approval

15

Make FERC Filings on May 13, 2013

1

Report on FERC Order 1000 Inter‐Regional Cost Allocation Efforts

October 29, 2012

Sam [email protected]

ORDER 1000 INTERREGIONAL COST ALLOCATION

2

2

Status of Interregional Cost Allocation

• Step 1: Interregional Cost Allocation Principles

– IRCATF approved principles and guidelines for SPP pp p p gstaff to use in discussions with seams neighbors

Flexible approach that recognizes differing drivers with neighboring planning regions

– In July, RSC approved the same principles and guidelines

i l ll i f i l• Step 2: Regional Cost Allocation of Interregional Projects

• Step 3: If Possible, Reach Agreement with Neighbors

3

SPP MISOMin. Project Cost $0 $20 Million

Differences With MISO in Project Eligibility and Cost Allocation Proposals

j

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

Metrics Considered

1. Adjusted Production Cost

2. Reliability3. Increase in transfer

capability4. Reduced Losses5. Reduced Emissions

1. Adjusted Production Cost

4

3

• Have met with MAPP stakeholders on October 4

• Met with MAPP and WAPA staff on October 26

Discussions With Other Neighbors

• AECI is currently working with Southeastern Regional Transmission Planning (SERTP)

5

• SPP Staff brought to the MOPC a request to approve filing with FERC seeking an approximate 30 day

Other Issues

g g pp yextension to make the SPP Order 1000 Interregional Compliance filing

– As with the regional compliance filing, the extension will accommodate the quarterly schedule of meetings

• MOPC approved the request

• Same request will be considered by the Board tomorrow

6

4

COST ALLOCATION OF INTERREGIONAL PROJECTS

7

Background

• How should the costs of interregional projects be allocated within SPP?

– The principles adopted by the Seams Steering Committee were developed almost two years ago; memorialized in whitepaper

– Reviewed and input provided by CAWG to the SSC

• SSC recommended that:

– “regardless of voltage class, costs allocated to SPP … should be recovered under SPP’s Region‐wide Charge on the same basis as Base‐Plan Upgrades whose nominal operating voltage level is greater than or equal to 300 kV.”

8

5

Inter‐Regional Cost Allocation TF

• Recommendation On Cost Allocation of Inter‐Regional Projects

– Concluded Byway projects deemed to be “Interregional” could be either 1) highway/byway or 2) highway,

– Preferred “highway” for Interregional Projects regardless of voltage.

9

Planning In the Past

• Projects that have shown benefits to our seams neighbors were marginalized in part due to a lack of cost allocation methodology

• For example:

– Chamber Springs to NW Texarkana

– Dolet Hills to Messick

– Turk to McNeilTurk to McNeil

10

6

Why To Allocate Inter‐Regional Costs Only to the Highway?• Lower voltage, underlying facilities can be the

limiting element for a flowgate that could restrictlimiting element for a flowgate that could restrict interregional transfer capability

• Relieving this constraint can alleviate problems and result in additional transmission service being sold

• Such a result provides regional benefits

11

Why (cont.)

• If the highway/byway methodology is used, the zone that the facility is constructed in would be forced to pay costs “well in excess of its load ratio share” when the project provides sufficient benefits to multiple zones and should be 100% shared regionally.

– Is this equitable?

• Costs should be allocated “roughly commensurate” i h b fiwith benefits

12

7

Other Considerations

• The majority of the tie‐lines that connect SPP to its neighbors are below 300kV

– Upgrades to these facilities should provide significant benefits to the SPP region

– Regional allocation of these costs would increase the interest in pursuing these upgrades

13

CAWG Action

• At it’s October meeting, the CAWG discussed the options for allocation of costs of Inter‐Regional projects

• Recommendation that was adopted by CAWG:

– CAWG recommends that the Regional State Committee adopt a 100% regional allocation of costs related to Inter‐Regional planning processes.

14

1

CAWG RECOMMENDATION TO RSC

BackgroundBackground• The RSC has not specifically voted on the Intra-Regional

Allocation Method to be used for Inter-Regional (Seams) Cost which will be allocated to the SPP Region.

However:• The Seams Steering Committee (SSC) provided its

recommendation on the appropriate Intra-Regional Allocation of Seams Costs in its February 2011 White Paper

Page 1 of 9

Seams Costs in its February 2011 White Paper,

• The Interregional Cost Allocation Task Force (ICATF) addressed Intra-Regional Allocation of Seams Costs as presented to the RSC at its July 2012 meeting.


Cost Assignment Options As Presented to CAWG:

1. Assign All Seams Costs to the Regional Rate( i,e. Highway)

2. Allocate Seams Costs pursuant to Currently Approved Allocation Methods (i.e Highway/Byway-dependent upon voltage of Seams Project)

Page 2 of 9

2


• The SSC Supports Assignment of Seams Costs To the• The SSC Supports Assignment of Seams Costs To the Regional Rate (i.e. Highway) as reflected in 2011 Whitepaper

• The ICATF, in its presentation to the RSC in July 2012, advised that, while it could support either (1) Allocation of Seams Costs pursuant to the Currently Approved Tariff (i.e. Highway/Byway – dependent upon voltage) or (2) Assignment

f All C t T th R i l R t (i Hi h ) th ICATF’

3

of All Costs To the Regional Rate (i.e. Highway), the ICATF’s preference is Assignment of Seams Costs to the Regional Rate.

Page 3 of 9


1. Assignment to the Regional Rate – CAWG Considerations for g gsupport of this treatment:

A. Projects chosen in an Inter-Regional Process differ from SPPregional projects:i. By definition, Inter-Regional Projects are measured to provide

benefits region- wide. ii. Inter-Regional Projects may be contained entirely in

the non-SPP region but with costs allocated to SPP. g

B. Regional Rate Treatment will encourage Inter-Regional Projects.

C. Regional Rate Treatment of Seams Projects, as Base PlanProjects, will help provide a better balance of costs and benefits under the currently approved allocation method.

Page 4 of 9

3


2. Use Current Highway/Byway (based on voltage) –2. Use Current Highway/Byway (based on voltage) Considerations for its support:

A. Assigning all Seams projects to the Regional Rate will require tariff change.

B. Highway/Byway is based on SPP studies and approved by FERC. C. There is no evidence that Highway/Byway treatment would “harm”

Seams projects.D Existing tariff allows for waivers of Highway/Byway as well as a 3

5

D. Existing tariff allows for waivers of Highway/Byway, as well as a 3-year review of any unintended consequences.

E. Assigning lower voltage seams projects to Regional Rate is notconsistent with SPP’s Order 1000 ROFR argument.

Page 5 of 9


2. Use Current Highway/Byway (based on voltage) – (cont )2. Use Current Highway/Byway (based on voltage) (cont.) Responses to Considerations for its support:

A. A tariff change will be required irrespective of allocation treatment.B. Seams projects will be based on Inter-regional studies for regional

benefits, with the inter-regional allocation of costs to the SPP regiondone using a significantly different method than used in current regional allocation.

6

C. Zonal assignment of all costs of seams projects, which by definition garner regional benefits, would be unfair to zone .

D. “Cost Allocation by waiver” is impractical, given the expected regional benefits seams projects should provide.

E. Order 1000-A ,irrespective of voltage or regional allocation, appears to eliminate Federal ROFR for all seams projects.

Page 6 of 9

4


Based on the unique qualities of seams projects, including the inter-q q p j , gregional process and cost assignment, the following motion was made to and passed by the majority of CAWG members:

CAWG recommends that the Regional State Committee adopt a 100% Regional allocation of costs related to inter-regional projects selected pursuant to inter-regional planning processes.

The roll call vote was as follows

7

The roll call vote was as follows:

New Mexico: No Nebraska: Yes Oklahoma: Yes Texas: NoKansas: Yes Missouri: Yes Arkansas: Yes

Page 7 of 9


Note that, in dissenting with the CAWG majority, the Texas CAWG , g j y,representative suggested an alternative treatment, recommending that the RSC should adopt current Highway/Byway treatment of SPP’s portion of costs for inter-regional projects, with the option to seek waiver of that treatment if the inter-regional project can be shown to provide regional benefits.

In discussions on this suggestion, CAWG members determined that a t ll ti th d i t th id i h

8

set allocation method was more appropriate than considering each seams project’s allocation on a case-by-case basis (i.e. Allocation-by-Waiver).

Page 8 of 9

5


Questions:


Page 9 of 9

Neligh Waiver RequestNeligh Waiver Request

October 30, 2012

Board of Directors

Lanny Nickell

OverviewO e e

• Transformer Waiver Process Overview

• Project Overview

• Evaluation Considerations

• Recommendation

2

Transformer Waiver Processa s o e a e ocess

• Change cost allocation

– From low side to high side

• Tariff considerations

– Predominate flows from lower to higher voltage

– Necessary for the support of the lower voltage system in the host zone

3

Neligh Transformere g a s o e

• Approved in 2012 ITP10ITP10

– Part of Neligh to Hoskins 345 kV project

– 2019 need date

• 345/115 kV

• Expected E&C Cost: $ 2 000$5,244,000

4

Evaluation considerationsa uat o co s de at o s

• Predominate flows

• GI Queue information

• TSR dependencies

• Support of the lower voltage system

• NPPD analysisNPPD analysis

5

Predominate Flow Analysisedo ate o a ys s

• 2012 ITP10 • Flows 115 kV to 345 kV

– Model year 2022

– 8760 hours of flow

– 59% of hours

– 71% of MWh

6

Neligh GI Queue Reviewe g G Queue e e

SPP Table – Current GI Queue Wind Statistics*

GI Queue Status

In-Service (MW)

IA Executed (MW) Under Study (MW)

TotalsConstruction

authorizedConstruction

not authorizedOn

Suspension Totals(MW)

authorized by customer

not authorized Suspension

Neligh Area > 300 kV - - - - - 0 Area > 300 kV

Neligh Area < 300 kV 384 - - 75 - 459

Totals (MW) 384 0 0 75 0 459

7

*As of August 31, 2012

TSR ImpactsS pacts

• TSR Impacts

– No confirmed service dependent on transformer

T l d di i di i– Two later‐queued studies indicating need transformer

2012‐AG12012 AG1

2012‐AG2

8

Underlying System SupportU de y g Syste Suppo t

• 2012 ITP10

– Moves trapped generation to EHV system

– 2019 need date

• 2013 ITPNT

– Not needed for transmission service and load growth

9

NPPD CommentsCo e ts

• Anticipated flows are from low to high voltage

• Neligh to Hoskins 345 kV project needed to support additional wind

• “But for” Neligh to Hoskins 345 kV project, transformer would be unnecessary for underlying systemsystem

10

Recommendationeco e dat o

MOPC recommends BOD approve the NPPD Neligh transformer waiver request

11

1


BACKGROUND:

1. Request:

As required by the timing requirements within the SPP Tariff, on July 26. 2012, Nebraska Public Power District (NPPD) sought a waiver of the current cost allocation requirements for a base plan transformerthe current cost allocation requirements for a base plan transformer to be installed at or near Neligh, Nebraska (Neligh Transformer). The Neligh Transformer is a 345/115 kV transformer and was part of a 345 kV ITP10 approved project. The current estimated allocated cost of the Transformer is $5,244,000.

1


2. Tariff Requirements - Attachment J

A. Transformer Allocation Basis:Within a Base Plan Upgrade, a Transformer connected at two different voltage levels is considered to be at the lower voltage level for purposes of cost allocation.

B. Waiver of Allocation BasisA waiver to assume the higher voltage level for cost allocation may be requested based on actual use of the transformer.

2

2


2. Tariff Requirements - Attachment J (cont)

D. Waiver Determinants:

Factors in this usage determination include but are not limited to:

(i) that power-flows are predominately from lower voltage to higher(i) that power-flows are predominately from lower voltage to higher voltage;

(ii) that 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.

3


SPP/NPPD ANALYSIS

Analyses were conducted which captured the operation of the Neligh Transformer, the results of which were:

1. Flows were predominantly from the 115 kV side to 345 kV side of the Transformer - with 59% of hours flowing upthe Transformer - with 59% of hours flowing up.

2. The Neligh Transformer was not needed by the underlying system and “but for” the Neligh/Hoskins 345 kV project, would not have been required.

4

3


CAWG CONCLUSION

Based on the analysis performed, the proposed Waiver request meets the Tariff minimum requirements to qualify the Neligh Transformer at the higher voltage level (i.e. 345 kV) for cost allocation purposes, with approval of that Waiver consistent with prior waiver request determinationsprior waiver request determinations.

5


CAWG RECOMMENDATION:

SPP Staff will recommend approval of NPPD’s Waiver Request for the Neligh Transformer. Therefore,

CAWG recommends that the RSC endorse the recommendation for the SPP Board to approve the NPPD Neligh Transformerfor the SPP Board to approve the NPPD Neligh Transformer Waiver Request.

6

4


Questions:


7

1

Balanced Portfolio Review

Lanny Nickell

RSC/BOD

October 29‐30, 2012

1

Outline

• Purpose

• Overview of Balanced Portfolio Conceptp

• 2009 Balanced Portfolio Development

• 2009 Portfolio Cost and Benefit Estimates

2

2

Purpose• MOPC directed SPP Staff in July 2012, to prepare a

presentation on how the Balance Portfolio was set up by listing the projects; refresh on what the estimatedby listing the projects; refresh on what the estimated costs and benefits were versus what they are now in total and by zone.

• 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.

3

OVERVIEW OF BALANCED PORTFOLIO CONCEPT

4

3

Balanced Portfolio General 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

5

Benefits Determination

• Production cost savings analysis performed using PROMOD for 3 specific yearsPROMOD for 3 specific years

• APC savings by zone derived from analysis

• Benefits for remaining years determined by interpolating APC savings from analysis

• Sum of the annual benefits discounted using an 8%

6

discount rate

4

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

7

• Sum of the ATRRs discounted using an 8% discount rate

2009 BALANCED PORTFOLIO DEVELOPMENT

8

5

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

– 7‐345 kV projects

– Total estimated E&C of $691.2 million9

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 200910

6

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

11

No EPA Impacts

2022 –58,300 MW

2009 PORTFOLIO, COST AND BENEFIT ESTIMATES

12

7

Portfolio 3‐E Adjusted

‐12.5%19.0%

Original $692MLatest $856M

75.0%

46.1%

‐3.9%

86 5%

13

36.5%

86.5%

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

14

All numbers are in thousands of dollars

SWPS $56,134WEFA $7,986WRI $14,730NPPD $5,562OPPD $2,199LES ‐$3,486Total $176,406

8

Balanced Portfolio Estimate Trend

FERC Filing

FERC Filing

FERCFiling

15

QUESTIONS???

16

1

Balanced Portfolio Review

Paul Suskie

October RSC

1

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

2

2

(1) SPP OATT REQUIREMENTS

3

(1) SPP OATT REQUIREMENTS3 Aspects to Review

• Development of Portfolio of Balanced Portfolio of P j [A h O S i IV (3) (5)]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 Presentation4

3

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.

5

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

6

4

Phase‐in Transfers at 20% per year over five years

Years

2nd Year

3rd Year4th Year

5thYear

6‐10True Up

7

1st Year

ea

(2) EXAMPLE: HOW TRANSFERS WORK IN A HRTO

8

5

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

9

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%

10

6

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

11

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

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

• 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 12

Ratio and Transfer Allocation

7

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%

13

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.

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

Portfolio 10 Year ATRR

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

14

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

8

Phase‐in of $19.7M Annualized Transfers HRTO

YearsYears 6‐10True Up

15

(3) ACTUAL SPP TRANSFER AMOUNTS BY ZONE

16

9

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 17

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

Allocation of Regional

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 18

10

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

19

1st Year

ea• $12.4M

• $6.2M

Balance Portfolio PV over 10 Year ATRR Cost Estimates and Transfers ‐ SPP 2012 Filing

Zone PortfolioBenefits


B/CBefore

Transfer ATRR Cost from Zones


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 $201.6 1.1 $144.8 $167.4 $0.0 1.0EMDE ($2.5) $23.6 (0.1) $45.7 $19.6 $0.0 1.0GRDA $6.2 $17.5 0.4 $25.9 $14.6 $0.0 1.0KCPL $60.8 $69.3 0.9 $66.0 $57.5 $0.0 1.0MIDW $95.7 $6.55 14.8 $0.0 $5.4 $83.9 8.1MIPU ($11.7) $36.3 (0.3) $78.1 $30.1 $0.0 1.0MKEC $86.9 $10.1 8.6 $0.0 $8.3 $68.5 4.7OKGE $193.1 $127.2 1.5 $39.7 $105.6 $0.0 1.0SPRM ($1.0) $13.9 (0.1) $26.5 $11.5 $0.0 1.0SUNC $24.2 $9.6 2.5 $0.0 $8.0 $6.7 1.4SWPS $406.8 $103.6 3.9 $0.0 $86.0 $217.3 2.2WEFA $57.9 $28.4 2.0 $0.0 $23.5 $6.0 1.0WRI $106.7 $103.6 1.0 $82.9 $86.0 $0.0 1.0

NPPD $40.3 $71.9 0.6 $91.3 $59.7 $0.0 1.0OPPD $15.9 $55.7 0.3 $86.1 $46.3 $0.0 1.0LES ($25.3) $17.2 (1.5) $56.8 $14.3 $0.0 1.0Total $1,278.4 $896.1 1.4 $743.7 $743.7 $382.3 1.4 20

11

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

21

1st Year

ea

• $20.5M

• $41M

Balance Portfolio PV over 10 Year ATRR Cost Estimates and Transfers ‐ Current Cost Estimates

Zone PortfolioBenefits


B/CBefore

Transfer ATRR Cost from Zones


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 22

12

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

23

1st Year

ea

• $15.3M

• $30.6M

(4) STATUS OF CURRENT SPP’S BP FILINGS AT FERC AND SPP COMMITTEES

24

13

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.

25

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.

26

14

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.

27

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

28

15

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.

29

(5) SPP OATT PROVISION RELATING TO BP UNINTENDED CONSEQUENCES REVIEW & RECONFIGURATIONRECONFIGURATION

30

16

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.31

(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.

32

17

(6) NEXT STEPS

33

(6) Next Steps

MOPC asked SPP staff to take a provide a Quarterly Update as Projects Cost Estimates.

If further review if needed, support existed to Reconvene the RARTF.

– The RARTF was a joint TF appointed by of the MOPC Chair and RSC President. The RARTF was tasked to develop the methodology for the Review of the Highway/Byway cost allocation methodologyallocation methodology.

– Add an additional member to the RARTF.

34

18

Next Steps (Cont.)Members State/Company Notes

Chairman Michael Siedschlag NPRB RSC Member

Vice Chairman Richard Ross AEP SPP Member

Commissioner Butch Reeves APSC RSC Member

Commission Tom Wright KCC RSC Member

Bary Warren Empire SPP Member

35

Phil Crissup OG&E SPP Member

Harry Skilton SPP SPP BOD Member

NEWMEMBER FROM BENEFITING ZONES

TBD by MOPC Chair and RSC President

MIDW, MKEC, SPS, SUNC, or WEFA

Conclusion

• SPP Staff will provide Quarterly Update to the MOPC and the RSC.

36

19

QUESTIONS???

37

DANA MURPHYCOMMISSIONER

OKLAHOMA CORPORATION COMMISSION

Intents to DrillJan 2008 - Sept 2012 Comparison

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total

2008 442 496 521 496 579 521 693 598 572 599 378 325 6,220

2009 265 244 220 228 176 260 217 148 152 213 188 189 2,500

2010 187 245 324 230 255 298 275 320 301 274 288 268 3,265

2011 290 259 312 311 346 354 302 310 306 320 310 312 3,732

2012 373 351 412 339 349 316 329 320 326 3,115

0

100

200

300

400

500

600

700

800

Inte

nts

to D

rill

2

195

205

200199

200

193

200 199

198

190

192

194

196

198

200

202

204

206

Jan Feb Mar Apr May Jun July Aug Sep2012

Average Rig Count

3

125 138 129147

121 134153

123106

7774

5961

7487 57

60

39

710

2

54

612

4

3

0

50

100

150

200

250

Oct Nov Dec Jan Feb Mar Apr May Jun

Com

plet

ions

Completions by Well Type

DryGasOil

4

WFEC Transmission System inAlfalfa Electric Area – Planned 2012

7

WFEC Transmission Systemin Kay Electric Area – Planned 2014

To Wakita Switch

OGE Interconnect

8

AQ Request from WFEC to SPP 2012SPP Request # Name/ location COOP Requested on Type Reply due on Results

DPA‐2012‐March‐147 Byron Alfalfa 40984New Delivery Point ‐WFEC Study needed

DPA‐2012‐March‐148 Caballo Alfalfa 40984New Delivery Point ‐WFEC 41177Withdrawn

DPA‐2012‐March‐149 Carmen Alfalfa 40984Xfmr upgrade Study needed

DPA‐2012‐March‐150 Enville RRV 40984New Delivery Point ‐WFEC Approved

DPA‐2012‐March‐151 Fountain Kay 40984Xfmr upgrade Study needed

DPA‐2012‐March‐152 Marland?? Cimarron 40984Xfmr upgrade Study needed

DPA‐2012‐March‐153 N. Kingfisher Cimarron 40984New Delivery Point ‐WFEC Approved

DPA‐2012‐March‐154 Numa Kay 40984Xfmr upgrade Study needed

DPA‐2012‐March‐155 Whitehorse Alfalfa 40984New Delivery Point ‐WFEC Study needed

DPA‐2012‐March‐156 Winchester Alfalfa 40984New Delivery Point ‐WFEC Study needed

DPA‐2012‐March‐161 Blackwell Kay Xfmr upgrade Study needed

DPA‐2012‐May‐179 Elgin Cotton New Delivery Point ‐PSO Approved

DPA‐2012‐May‐184 Neal CVEC Withdrawn

DPA‐2012‐June‐195 Seminole CVEC 41074Jul 20 Withdrawn

DPA‐2012‐July‐204 Marshall Cimarron 41092Aug 20 Approved

DPA‐2012‐July‐205 Perry Kay 41092Xfmr upgrade Study needed

DPA‐2012‐July‐210 Sterling 3 Canadian Valley 41115New Delivery Point ‐ OG&E 41141Approved

DPA‐2012‐July‐211 Billings Kay 41117Xfmr upgrade 41141Approved

DPA‐2012‐July‐212 Rose Valley Alfalfa 41117New Delivery Point ‐WFEC 41141Approved

DPA‐2012‐July‐217 Medicine Lodge Alfalfa 41121New Delivery Point ‐WFEC 41141Study needed

DPA‐2012‐July‐218 Renfrow ‐ SR Kay 41121New Delivery Point ‐ OG&E 41141Study needed

DPA‐2012‐August‐223 Webb City Kay 41142Xfmr upgrade 41172Approved

DPA‐2012 September‐234 Cozy Curve Alfalfa 41158New Delivery Point ‐ OG&E 41202Approved

DPA‐2012 September‐236 Dill Kiwash 41158Xfmr upgrade 41202Approved

DPA‐2012 September‐237 Medford Kay 41158New Delivery Point ‐WFEC 41202Study needed

DPA‐2012 September‐233 Newkirk Kay 41158New Delivery Point ‐ OG&E 41202Approved

DPA‐2012 September‐238 Renfrow‐Kay Kay 41158New Delivery Point ‐WFEC 41202Study needed

DPA‐2012 September‐239 Savanna Kiamichi 41158Xfmr upgrade ‐WFEC 41202Approved

DPA‐2012 September‐235 Shilder (Lyman) Kay 41158New Delivery Point ‐PSO 41202Approved

DPA‐2012‐September‐243 Marland Kay 41178Xfmr upgrade 41202Study needed

DPA‐2012‐September‐246 Pond Creek Kay 41178New Delivery Point ‐WFEC 41202Study needed

DPA‐2012‐September‐244 Loafman Rural 41180New Delivery Point ‐WFEC 41202Study needed

DPA‐2012‐October‐249 Maysville Rural 41185New Delivery Point ‐ OG&E 41233pending

DPA‐2012‐October‐248 Wallville Rural 41184Xfmr upgrade ‐WFEC 41233pending

DPA‐2012‐October‐247 Sandy Corner Alfalfa 41184Xfmr upgrade ‐WFEC Study needed

Delivery Point Network Study Agreement Number DPA-2012-March-151, 152,154 and DPA-2012-March-161

Delivery Point Network Study Agreement Number DPA-2012-March-147, 148,149 and DPA-2012-March-155,156

Green: Approved by SPP AQ process.Red with pink: Study Needed (Not approved in the AQ process).Red with no highlights: Project withdrawn by WFEC.No highlights: Project pending SPP AQ review. 9

SPP Study Recommendations• Need more structured and understandable communication

between producers, utilities, OCC, and SPP. • SPP should set a “Date Certain” for AQ Study Process to

stop continual restarts on evaluations.• Consider Planning and Modeling group needs in order to

decrease response time• Need transparent tracking of requests as they go through

the process.• Consider outsourcing studies to accelerate process where

it makes sense.• Help identify potential transmission system solutions.• Consideration of specialist at SPP to work with producers

to better report anticipated needs.10

Provisions for Abnormal Load Growth in SPP Tariff

Carl A. Monroe

How does SPP decide what and where transmission is needed? (OATT)• Integrated Transmission Planning process (Attachment O)

• New Load Additions

– Delivery Point Addition (Attachment AQ)

– Delivery Point Transfer (Attachment AR)

• Aggregate Transmission Service Studies (Attachment Z1)

– Determines transmission upgrades needed to transmit energy from new generation to load

– Shares costs of studies and new transmission

• Generation Interconnection Studies

– Determines transmission upgrades needed to connect new generation to electric grid

2

Getting Long Term Transmission Service

3

Delivery Point Transfer StudyAttachment AR

Transfer of existing delivery point from one Network Customer to another Network

Customer

Aggregate Study

Attachment Z1

PTP requests, redirects, and all new designate resources

Delivery Point Addition StudyAttachment AQ

New delivery points, modifications to

existing delivery points, and new “block” load

additions

When process is right for me?

• Will delivery point be served by existing Designated Network Resource?

– YES – New Attachment AQ Process

– NO – Aggregate Transmission Service Studies

• Will existing delivery point service be transferred to new Designated Network Resource?

– YES ‐ Attachment AR

4

AQ Process – Key Steps1. Request submitted to host Transmission Owner (TO)

and SPP.

2. Host TO performs a Load Connection Study (LCS)

3. SPP staff determines if a Delivery Point Network Study (DPNS) is required.

4. If DPNS is required, customer makes a deposit to SPP for estimated study costs and SPP staff performs study.

5. DPNS report to the customer and host TO.

6. Network Integrated Transmission Service Agreement (NITSA) with upgrade(s) updated.

5

20 – 50 Days 5 Days 30 Days 60 Days 15 days

SPP Staff Receives Request

Staff Posts Findings of Screening

Staff Sends out Study Agreement

10 Days 30 days 60 Days

TO Receives Request

Customer Executes Study Agreement and Provides Necessary Study Data

Staff Delivers Study Report to Customer and Host TO and requests SCERT

TO Sends Load Connection Study Agreement to Customer

Customer Executes Study Agreement and Provides Necessary Study Data

TO Delivers Study Report to Customer

AQ Timeline

Staff Sends Updated NITS Agreement to Customer

30 days 15 days

NTC Issued

Customer Executes Updated NITS Agreement

Website

• Studies, request forms, and process guidelines: http://sppoasis.spp.org/documents/swpp/transmission/studies.cfm

• OATT with Attachment AQ: http://www.spp.org/section.asp?group=215&pageID=27

• Delivery Point Transfer ‐ Posted studies, guidelines, and forms:http://sppoasis.spp.org/documents/swpp/transmission/TRPAGE.CFM

8

http://sppoasis.spp.org/documents/swpp/transmission/studies.cfm

http://sppoasis.spp.org/documents/swpp/transmission/studies.cfm

http://www.spp.org/section.asp?group=215&pageID=27

http://www.spp.org/section.asp?group=215&pageID=27

http://sppoasis.spp.org/documents/swpp/transmission/TRPAGE.CFM

http://sppoasis.spp.org/documents/swpp/transmission/TRPAGE.CFM

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

https://cloudpal.idashboards.com/idashboards/?guestuser=2spp2

https://cloudpal.idashboards.com/idashboards/?guestuser=2spp2

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

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, 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

Southwest Power Pool REGIONAL STATE COMMITTEE Southwest ... · the Office of Electric Reliability...

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Transcript of Southwest Power Pool REGIONAL STATE COMMITTEE Southwest ... · the Office of Electric Reliability...