Southwest Power Pool STRATEGIC PLANNING COMMITTEE … · Strategic Planning Committee July 14, 2011...

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MINUTES NO. 70 Southwest Power Pool STRATEGIC PLANNING COMMITTEE MEETING Kansas City Marriott Country Club Plaza, Kansas City, Missouri July 14, 2011 • MINUTES • Agenda Item 1 – Call to Order and Administrative Items Ricky Bittle (AECC) called the meeting to order at 8:00 a.m. SPC members participating in person or by phone were Jim Eckelberger (Director); Harry Skilton (Director); Josh Martin (Director); Rob Janssen (Dogwood); Mel Perkins (OGE); Mike Palmer (EDE); Les Evans (KEPCO); Mike Wise (GSEC); Bruce Cude, proxy for David Hudson (Xcel); and Tom Kent, proxy for Pat Pope (NPPD). SPP Staff included Michael Desselle, Nick Brown, Carl Monroe, Paul Suskie, Katherine Prewitt, and Jay Caspary. Other guests participated in person or via phone (Attendance – Attachment 1). Mr. Bittle referred to the minutes of January 13, 2011, March 28, 2011 and June 13, 2011 and asked for additions or corrections (Minutes 1/13/11, 3/28/11 and 6/13/11 – Attachment 2). The minutes were approved by acclamation. By acclamation an additional item for consideration was added to the agenda to follow agenda item 5. Agenda Item 2 – Review Past Action Items Michael Desselle provided a review of past action items (Pending Action Items Status Report – Attachment 3). Agenda Item 3 – Markets and Operations Policy Committee Update Bill Dowling (Midwest Energy and MOPC Chairman) provided an informational report following the MOPC meeting from the previous two days. Of particular note were MOPC actions confirming the MWG Integrated Marketplace design and further confirmation that the Enhanced Combined Cycle design would follow by 1 year (March 2015) implementation of the Integrated Marketplace. The MOPC approved having staff move forward to file a change in the Tariff Administrative Fee cap. Like the SPC, MOPC has had some active efforts underway responding to the RSC Motions. Specifically, the MOPC heard reports from the Project Cost Task Force (PCTF). The MOPC approved completion of the ITP manual, despite some concerns about the current processes limitations in dealing with reactive and stability studies. Two Safe Harbor Waiver requests were considered by MOPC. Staff was asked to perform a Waiver process review to determine historically what has been established since the beginning of the process. Mel Perkins inquired about the status of the Credit Process Task Force established a 1 ½ years ago and encouraged MOPC leadership to accelerate resolution of Task Force effort to finalize rules for transmission credits for sponsored upgrades. Agenda Item 4 – Final Policy Recommendation regarding RSC Motions Ricky Bittle reported that the SPC Task Force Memorandum regarding the policy decisions in response to the RSC Motions was approved by the SPC in an e-mail vote on June 16 th . (SPC Task Force Memorandum – Attachment 4). Chairman Eckelberger asked some clarifying questions specifically about assignments/novations. It was described that the PCTF had built in controls into their processes (regardless of whether or not a project is assigned/novated) to deal with the state concerns on cost changes. General consensus of the Committee was reached and concerns were allayed (of note, two commissions (Missouri and Texas) indicated that silence did not indicate agreement). Terri Gallup (AEP) presented the MOPC’s Project Cost Task Force (PCTF) final report (PCTF Presentation and Report – Attachment 5) on its efforts to develop the technical recommendations in

Transcript of Southwest Power Pool STRATEGIC PLANNING COMMITTEE … · Strategic Planning Committee July 14, 2011...

Page 1: Southwest Power Pool STRATEGIC PLANNING COMMITTEE … · Strategic Planning Committee July 14, 2011 response to the RSC Motions #1 and #4 ( …best manner to address significant cost

MINUTES NO. 70

Southwest Power Pool

STRATEGIC PLANNING COMMITTEE MEETING

Kansas City Marriott Country Club Plaza, Kansas City, Missouri

July 14, 2011

• M I N U T E S •

Agenda Item 1 – Call to Order and Administrative Items

Ricky Bittle (AECC) called the meeting to order at 8:00 a.m. SPC members participating in person or by phone were Jim Eckelberger (Director); Harry Skilton (Director); Josh Martin (Director); Rob Janssen (Dogwood); Mel Perkins (OGE); Mike Palmer (EDE); Les Evans (KEPCO); Mike Wise (GSEC); Bruce Cude, proxy for David Hudson (Xcel); and Tom Kent, proxy for Pat Pope (NPPD). SPP Staff included Michael Desselle, Nick Brown, Carl Monroe, Paul Suskie, Katherine Prewitt, and Jay Caspary. Other guests participated in person or via phone (Attendance – Attachment 1).

Mr. Bittle referred to the minutes of January 13, 2011, March 28, 2011 and June 13, 2011 and asked for additions or corrections (Minutes 1/13/11, 3/28/11 and 6/13/11 – Attachment 2). The minutes were approved by acclamation.

By acclamation an additional item for consideration was added to the agenda to follow agenda item 5.

Agenda Item 2 – Review Past Action Items

Michael Desselle provided a review of past action items (Pending Action Items Status Report – Attachment 3).

Agenda Item 3 – Markets and Operations Policy Committee Update

Bill Dowling (Midwest Energy and MOPC Chairman) provided an informational report following the MOPC meeting from the previous two days. Of particular note were MOPC actions confirming the MWG Integrated Marketplace design and further confirmation that the Enhanced Combined Cycle design would follow by 1 year (March 2015) implementation of the Integrated Marketplace. The MOPC approved having staff move forward to file a change in the Tariff Administrative Fee cap. Like the SPC, MOPC has had some active efforts underway responding to the RSC Motions. Specifically, the MOPC heard reports from the Project Cost Task Force (PCTF). The MOPC approved completion of the ITP manual, despite some concerns about the current processes limitations in dealing with reactive and stability studies. Two Safe Harbor Waiver requests were considered by MOPC. Staff was asked to perform a Waiver process review to determine historically what has been established since the beginning of the process.

Mel Perkins inquired about the status of the Credit Process Task Force established a 1 ½ years ago and encouraged MOPC leadership to accelerate resolution of Task Force effort to finalize rules for transmission credits for sponsored upgrades.

Agenda Item 4 – Final Policy Recommendation regarding RSC Motions

Ricky Bittle reported that the SPC Task Force Memorandum regarding the policy decisions in response to the RSC Motions was approved by the SPC in an e-mail vote on June 16th. (SPC Task Force Memorandum – Attachment 4). Chairman Eckelberger asked some clarifying questions specifically about assignments/novations. It was described that the PCTF had built in controls into their processes (regardless of whether or not a project is assigned/novated) to deal with the state concerns on cost changes. General consensus of the Committee was reached and concerns were allayed (of note, two commissions (Missouri and Texas) indicated that silence did not indicate agreement). Terri Gallup (AEP) presented the MOPC’s Project Cost Task Force (PCTF) final report (PCTF Presentation and Report – Attachment 5) on its efforts to develop the technical recommendations in

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Strategic Planning Committee July 14, 2011 response to the RSC Motions #1 and #4 ( …best manner to address significant cost increases and/or overruns of transmission projects that are regionally funded; and, … how cost estimates are established for transmission projects before Cost Benefit Analyses are performed, respectively). The issue of the composition and voting “balance” of the proposed PCWG was discussed and challenged. Jake Langthorn (OGE) presented the Final Design Best Practices and Performance Criteria Task Force (DBPPCTF) report (DBPPCTF Presentation and Report – Attachment 6).

Agenda Item 5 – Reliability Impacts of EPA Regulations

Jay Caspary presented the results of the SPP staff’s initial assessment of Impacts of Proposed Environmental Protection Agency (EPA) Regulations (EPA Presentation and Report – Attachment 7). Discussions centered on whether or not Wind Generation and Demand Response had been factored into the assessment and the tone of the letter/report that should be used to motivate a federal response to our concerns. Of note and particular immediate concern was the issuance by EPA just in the prior week a final rule, the Cross-State Air Transport Air Pollution Rule (CSAPR). The concerns are that the issuance of this CSAPR now will include Kansas and Nebraska, further exasperates the impacts of the EPA Regulations and impacts SPP Companies sooner (2012).

Agenda Item 6 – Discussion Points for NERC President Attendance at the July Board Meeting

Michael Desselle presented a draft of comments that staff has prepared to deliver to Gerry Cauley during his upcoming attendance at the SPP Board Meeting. Comments and suggestions were provided to be incorporated into the draft. Additional direction was provided regarding the tone that the draft should communicate.

Agenda Item 7 – Entergy Update

Carl Monroe provided a status report of FERC’s ruling on the JOA dispute with MISO and the SPP testimony filed in the Arkansas proceeding on Entergy’s decision to seek to join MISO.

Agenda Item 8 – SPP Strategic Plan Metrics

Michael Desselle reviewed the status of Strategic Plan initiatives. (Strategic Plan Status Report - Attachment 8).

Agenda Item 9 – Federal Funds Task Force Update (Written Report)

Michael Desselle noted that the background material contains a status report of actions taken in response to the Federal Funds White Paper Recommendations. (Fed Funds Status Report - Attachment 9).

Agenda Item 10 – Summary of Action Items

Action items are: • Finalize and submit EPA Report and Letter consistent with discussions. • Finalize comments to NERC CEO consistent with discussions.

Agenda Item 11 – Discussion of Future Meetings

The next regularly-scheduled SPC meeting is October 13 in Dallas. Respectfully Submitted, Michael Desselle Secretary

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Southwest Power Pool, Inc. 

STRATEGIC PLANNING COMMITTEE MEETING 

Thursday, July 14, 2011 

 8 AM – 3 PM 

Kansas City Marriott Country Club Plaza, Kansas City, Missouri 

 •   A G E N D A   •  

 

1. Call to Order and Administrative Items .....................................................................Ricky Bittle 

2. Review of Past Action Items ............................................................................ Michael Desselle 

3. MOPC Update .......................................................................................................... Bill Dowling 

4. Final Policy Recommendation regarding RSC Motions ..............................................Ricky Bittle 

a. Project Cost Task Force Update ................................................................... Terri Gallup 

b. Design Best Practices and Performance Criteria Task Force Update ..... Jake Langthorn 

5. Reliability Impacts of EPA Regulations ..................................................................... Jay Caspary 

6. Entergy Update ....................................................................................................... Carl Monroe 

7. SPP Strategic Plan Metrics ............................................................................... Michael Desselle 

8. Federal Funds Task Force Update (Written Report) ................................................. Jay Caspary 

9. Summary of Action Items ................................................................................ Michael Desselle 

10. Discussion of Future Meetings......................................................................... Michael Desselle 

October 13, 2011                   Dallas 

January 19, 2012                    New Orleans 

May 3‐4, 2012 Retreat          TBD 

July 19, 2012                           Kansas City 

October 18, 2012                   San Antonio 

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MINUTES NO. 67

Southwest Power Pool

STRATEGIC PLANNING COMMITTEE MEETING

Doubletree Hotel – New Orleans, Louisiana

January 13, 2011

• M I N U T E S •

Agenda Item 1 – Administrative Items

Ricky Bittle (AECC) called the meeting to order at 8:00 a.m. SPC members participating in person or by phone were Jim Eckelberger (Director); Josh Martin (Director); Harry Skilton (Director); Rob Janssen (Dogwood); Mel Perkins (OGE); Mike Palmer (EDE); Les Evans (KEPCO); Mike Wise (GSEC); David Hudson (Xcel); and Paul Malone (proxy for Pat Pope (NPPD)). SPP Staff included Michael Desselle, Carl Monroe, Stacy Duckett, Les Dillahunty, Bruce Rew, Katherine Prewitt, Paul Suskie, and Scott Noble. Others guests participated in person or via phone (Attendance – Attachment 1).

Mr. Bittle referred to the minutes of October 14, 2010 and December 3, 2010 and asked for additions or corrections (Minutes 10/14/10, and 12/3/10 – Attachment 2). The minutes were passed by acclamation.

Agenda Item 2 – Review Past Action Items

Michael Desselle provided a review of past action items (Pending Action Items Status Report – Attachment 3).

Agenda Item 3 – Policy Discussions Continuation regarding RSC Recommendations

Les Dillahunty began the discussion noting that the focus on today’s discussions would be on the RSC motions, followed by a presentation by AEP regarding transmission project management principles and then a recap of ISO-NE’s Cost Allocation and Project Cost Estimation processes. He noted the purpose of today’s dialogue was to develop a strawman approach that Ricky Bittle could apprise the Board and RSC of the Committee’s progress in dealing with the policy matters. Katherine Prewitt, Les Dillahunty and Stacy Duckett provided a brief review of the staff whitepapers and recommendations that were updated since the December 3rd, 2010 SPC special meeting (Staff Presentation for Agenda Items 3a, 3b, 3c, & 3d – Attachment 4). Katherine specifically noted a change approved by the MOPC at its January 11-12 meeting: the formation of a Project Cost Task Force. Les discussed the novation process issues and concerns. Stacy Duckett noted issues of consideration related to the implementation of design and construction standards. Representatives from AEP (Mark Workman and Brian Johnson) provided an overview of AEP’s Project Management and Cost Estimation processes (AEP Project Management & Cost Estimating Overview – Attachment 5). Mark Rossi (Accenture) next provided a review of the ISO-NE Transmission Cost Allocation Rules (Review of ISO-NE Provisions – Attachment 6). Les then led a discussion regarding the Novation process. Following a lengthy discussion covering many aspects, issues and concerns regarding the novation process, a motion was proposed and seconded that SPP would provide all future proposed novations to the MOPC and the RSC for review and then to the Board and Members Committee for approval prior to filing. Significant additional discussion about the motion yielded a withdrawal of the motion from the table due to the inter-related nature of each of the RSC recommendations to the subject of novations. Ricky Bittle then proposed a task force of the SPC be created to develop a comprehensive recommendation starting with the Staff whitepapers as a whole. He asked for volunteers to be submitted no later than Wednesday January 19. He indicated the task force would meet face-to-face initially and then by conference call afterwards and that an additional SPC meeting would likely be needed in the March time frame.

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Strategic Planning Committee January 13, 2011 Agenda Item 4 – Markets and Operations Policy Committee Update

Bill Dowling (Midwest Energy and MOPC Chairman) provided an informational report following the MOPC meeting from the previous two days (Bill Dowling MOPC Report – Attachment 7). Of particular note were MOPC actions regarding the ITP20 report, creation of the Project Cost Task Force to provide input on the charter for a Project Cost Working Group under the MOPC, and the creation of an Events Analysis Working Group under the MOPC.

Agenda Item 5 – Entergy Update

Carl Monroe provided a status report on efforts studying Entergy’s cost/ benefit of joining SPP (Entergy Update – Attachment 8). He noted the recent receipt of a Memorandum of Understanding between SPP and Entergy that he and the Task Force Interest Entergy Membership (TFIEM) are reviewing.

Agenda Item 6 – SPP Strategic Plan Metric

Michael Desselle shared with the group a mock-up of the new metric and noted that report would also contain internal and external accountable parties (Strategic Plan Status Report - Attachment 9). Feedback was solicited on the chart.

Agenda Item 7 – Update on SPP Aggregate Value Proposition

Following a discussion on the update of efforts to quantify value to SPP’s membership by Scott Noble (SPP Aggregate Value Proposition Update – Attachment 10), direction was given to perform some representative load ratio share calculations (benchmark for member types and characteristics) to assess validity of the quantifications.

Agenda Item 8 – Summary of Action Items

Action items are: • Complete remaining pending action items. • Creation of a task force to address staff whitepapers on RSC recommendations. Populate task

force by January 19 and schedule first task force meeting. Subsequently schedule special SPC meeting in March.

• Perform representative load ratio share tests on the Aggregate Value Proposition.

Agenda Item 11 – Discussion of Future Meetings

There will be a special meeting of the SPC in March, date and location TBD. The next regularly-scheduled SPC meeting is July 14 in Kansas City. The SPC Retreat is scheduled for May 5-6, location TBD. Following all the agenda items a discussion occurred regarding a request from the ESWG seeking direction from the SPC. The question was about the scenarios to be considered in the ITP-10. As a starting point, direction was provided to continue to use the same 4 scenarios that the SPC previously recommended to be studied for the ITP20. It was noted that the renewable requirements for each state likely needed to be refreshed. Further direction was also provided to pay attention to also resolving seams problems. Finally, direction was provided to have the SPC be informed of variances to 4 scenarios. Respectfully Submitted, Michael Desselle Secretary

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MINUTES NO. 68

Southwest Power Pool

STRATEGIC PLANNING COMMITTEE MEETING

DFW Hyatt Hotel – Dallas, Texas

March 28, 2011

• M I N U T E S •

Agenda Item 1 – Administrative Items

Ricky Bittle (AECC) called the meeting to order at 10:00 a.m. SPC members participating in person or by phone were Josh Martin (Director); Harry Skilton (Director); Rob Janssen (Dogwood); Mel Perkins (OGE); Mike Palmer (EDE); Les Evans (KEPCO); Mike Wise (GSEC); David Hudson (Xcel); and Pat Pope (NPPD). SPP Staff included Michael Desselle, Carl Monroe, Stacy Duckett, Katherine Prewitt, Paul Suskie, and Emily Pennel. Others guests participated in person or via phone (Attendance – Attachment 1).

Agenda Item 2 – Review Past Action Items

Michael Desselle provided a review of past action items (Pending Action Items Status Report – Attachment 2).

Agenda Item 3 – ESWG ITP-10 Scenario Guidance

Michael Desselle provided a status report of the ESWG action taken to update the “futures” that are to be utilized in the 2011 ITP-10 study (ESWG ITP-10 Guidance – Attachment 3).

Agenda Item 4 – SPC Task Force Recommendations regarding RSC Motions

Ricky Bittle led a discussion of the policy recommendations developed by the SPC Task Force working with Staff to address the RSC motions regarding the transparency and accountability for transmission project estimation (SPCTF Recommendation Report – Attachment 4). A presentation summarizing the recommendations (SPCTF Presentation – Attachment 5) was used to work through the document. The discussions generated a list (Additional TF Consideration – Attachment 6) of items that the Task Force was asked to have further discussion about. It was noted that all future task force meetings will be open and posted. Finally, a status report will be provided to the RSC and Board in April.

Agenda Item 5 – Grid Emergency Communications

Emily Pennel led discussion on emergency communications, including the question of whether or not SPP should issue public appeals (Grid Emergency Communications – Attachment 7). Following dialogue, staff was tasked to develop a proposal or recommendation for the July MOPC meeting.

Agenda Item 6 – Unintended Consequences Language

Paul Suskie provided a brief status report. He noted that staff was developing a white paper. He also reviewed the timeline and discussed the formation of a joint task force from the RSC and MOPC.

Agenda Item 7 – Summary of Action Items

Action items are: • Schedule future SPC Task Force meeting(s) to discuss/resolve matters identified for further

discussion. • Staff to develop Grid Emergency Communication proposal and recommendation for the July

MOPC meeting.

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Strategic Planning Committee March 28, 2011 Agenda Item 8 – Discussion of Future Meetings

The next regularly-scheduled SPC meeting is July 14 in Kansas City. The SPC Retreat is scheduled for May 5-6. Adjournment With no further business, Ricky Bittle thanked everyone for their participation and adjourned to Executive session at 2:55 P.M. Executive Session The SPC provided direction to the staff regarding the recommendations of the Task Force of Interest in Entergy Membership (TFIEM). Respectfully Submitted, Michael Desselle Secretary

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MINUTES NO. 69

Southwest Power Pool

STRATEGIC PLANNING COMMITTEE SPECIAL MEETING

Marriott Los Colinas – Irving, Texas

June 13, 2011

• M I N U T E S •

Agenda Item 1 – Administrative Items

Ricky Bittle (AECC) called the meeting to order at 10:00 a.m. SPC members participating in person or by phone were Jim Eckelberger (Director); Harry Skilton (Director); Rob Janssen (Dogwood); Mel Perkins (OGE); Mike Palmer (EDE); Les Evans (KEPCO); Mike Wise (GSEC); David Hudson (Xcel); and Tom Kent, proxy for Pat Pope (NPPD). SPP Staff included Michael Desselle, Nick Brown, Carl Monroe, Paul Suskie, Lannie Nickell, Pat Bourne and Jay Caspary. Others guests participated in person or via phone (Attendance – Attachment 1).

Agenda Item 2 – SPC Task Force Recommendations regarding RSC Motions

Michael Desselle provided a review of the SPC Task Force meetings resulting in the policy recommendation to the SPC regarding the RSC Motions. (Memo-SPCTF Response to RSC Motions - Attachment 2). He additionally reviewed the SPC Task Force considerations and actions regarding comments received during the March 28th, 2011 SPC meeting (Additional TF Considerations - Attachment 3). Following these presentations, clarifying questions were asked and answers were discussed by section from the recommendation. In Section 3 of the recommendation (Estimates Outside a Bandwidth), Jim Eckleberger moved to add an additional option that the PCWG could propose to the Board. Jim moved and Harry Skilton seconded the addition of “3.2.1.4 Consider excluding from regional funding increased costs that were not anticipated when the NTC was approved.” The motion initially passed for participants in the room (4 in favor, 3 against, 1 abstention due to inability to hear discussion on the phone). Due to technical difficulties with the phone an e-mail ballot containing the above language was sent to the SPC members participating by phone, and following their ballots cast, the motion failed. Additional clarifying questions were discussed. The resulting discussions yielded no additional changes and all redlines were accepted to the SPCTF recommendation. Staff was instructed to send an e-mail ballot to the SPC members with the “clean”, (i.e., non-redlined), recommendation for approval. On June 16th the e-mail ballot was sent and the ballot passed with 1 “no” vote. Further instructions were provided that because of the phone difficulties yielding an initial approval and subsequent failure of Jim Eckelberger’s motion, that language would again be discussed at the July SPC meeting.

Agenda Item 3 – NERC Membership Renewal

Michael Desselle advised the SPC that NERC had requested all NERC members to renew their member registration by July 1, 2011 (SPC Recommendation to the Board for NERC Membership Renewal - Attachment 4). The recommendation was for SPP to renew its membership in NERC, opting to retain the current Regional Entity sector representation until the SPP RE voting term at the end of 2011, when SPP would change its sector representation to the ISO/RTO sector. Following a motion and second the motion passed unanimously. Respectfully Submitted, Michael Desselle Secretary

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Southwest Power Pool, Inc.

STRATEGIC PLANNING COMMITTEE Pending Action Items Status Report

July 14, 2011

Action Item Date Originated Status Comments

Schedule future SPC Task Force meeting(s) to discuss/resolve matters identified for further discussion.

March 28, 2011 Complete Motion Approved

Staff to develop Grid Emergency Communication proposal and recommendation for the July MOPC meeting.

March 28, 2011 In Progress

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Project Cost Task Force Response to RSC Motions 1 and 4

July 14, 2011

RSC Motions (Oct 2010)

• MOTION 1: RSC recommends that SPP review what is the best manner to address significant cost increases and/or overruns of transmission 

j t th t i ll f d dprojects that are regionally funded.

• MOTION 2: RSC recommends that SPP review the Novation Process and report to the RSC by April 2011.

• MOTION 3: RSC recommends that SPP consider establishing design and construction standards for transmission projects at 200 kV and above that are regionally funded.

• MOTION 4: SPP evaluate how cost estimates are established for• MOTION 4: SPP evaluate how cost estimates are established for transmission projects before Cost Benefit Analysis are performed.

• MOTION 5: CAWG to study various methods on how costs that exceed some standard can be addressed with different cost allocation mechanisms and recommend strategies to RSC.

2

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SPCTF Recommendations

• Standardized estimation methodologies

– Consistent estimation principlesp p

– Standardized template

– Define allowable cost variance

• Tiered approach to cost estimating

• PCWG to review any deviations from design best i d f i ipractices and performance criteria

– If estimate deviates from allowable variance, NTC could be modified or withdrawn

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Members of Project Cost Task Force (PCTF)

• Terri Gallup, Chairman (American Electric Power)

• Al Ackland (Kansas City Power & Light Company)

• Peter Day (Oklahoma Gas and Electric Co.)

• Jason Fortik (Lincoln Electric System)

• Ray Harold (Midwest Energy)

• Tom Hestermann (Sunflower Electric Power Corp.)

• Dave Kimball (Nebraska Public Power District)( )

• Tom Littleton (Oklahoma Municipal Power Authority)

• Sam McGarrah (Empire District Electric Company)

• Brian Slocum (ITC Great Plains, LLC)

4

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PCTF Questions to Answer

• Impacts to cost certainty

What is known/unknowns?What is known/unknowns?

How can unknowns be narrowed?

How can knowns be improved?

• What is known at each cost ti t t ?

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estimate stage?

• What can be done to improve certainty of cost estimates?

Project Cost Drivers

‐ Ratings/Capabilities

‐ Geography/TerrainGeography/Terrain 

‐ Land Use

‐ Line Length & Routing

‐ Project Schedule

‐ Commodity/Labor Prices

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‐ Exchange Rates

‐ Environmental Constraints

‐ Regulatory Requirements

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Stages of Cost Estimation1) Conceptual 

prepared by SPP from historical data

used for screening purposes only

2) Study 

submitted by DTO if project passes Conceptual screening and requires more refined estimate

3) NTC Project (NPE)/CNTC Project (CPE)

submitted by DTO in response to CNTC/NTC issuance

established as baseline for project cost variance

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p j

4) Design/Construction 

quarterly cost estimates from TO as engineering and construction for project is completed

What do we know at each Estimate Phase?

Conceptual Study Design & Construction

CNTC/NTCIssued

Actual Cost

What is known •End points•Capacities/ratings of equipment•Needed in‐service

What is unknown

What is known •Regional Geography•Capacities/ratings of  equipment•Needed in‐service•Rough line length•Rough station locations

What is unknown

What is known •Line length•Line route•Station locations•Commodity prices/labor costs•ROW costs

What is unknown

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What is unknown•Line route/lengths•Station locations•Regional geography

What is unknown•Line route•Regulatory issues•Environmental issues•Commodity prices/labor costs•Schedule

What is unknown•Weather impacts•Operational constraints•Construction change orders•Material delivery issues

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What do we know at each Estimate Phase?

CNTC Project (CPE) NTC Project (NPE)

CNTCIssued NTC

What is known •Rough line length•Rough station locations•Needed in‐service•Environmental issues/constraints

What is unknown•Line routeR l t i

What is known •Rough line length•Rough station locations•Needed in‐service•Environmental issues/constraints

What is unknown•Line routeR l t i

9

Authorization to spend $$ and receive compensation. Project Scope becomes moredefined when detailed engineering starts. Until TO has authorization to spend, they areat cost recovery risk to perform any detailed engineering prior to this phase.

•Regulatory issues•Commodity prices/labor costs•Schedule

•Regulatory issues•Commodity prices/labor costs•Schedule

Cost Estimate Stage Definition

Estimate Name StageLevel of Project 

Scope Definition

End UsagePrecision Bandwidth

Projects > 100  All other BOD kV & > $20 Million

Approved Projects

Conceptual 1 1 0% to 10% Concept screening for ITP20/ITP10 ‐50% to + 100%

Study 2 2 10% to 20%

Study of feasibility and plan 

development for ITP10/ITPNT

‐30% to +30%

CNTC Issued NTC Issued

CNTC Project (CPE) 3 N/A 20% to 40% Final baseline (CNTC) ‐20% to +20%

10

j ( ) / ( )

NTC Issued

NTC Project (NPE) N/A 3 20% to 40% Final baseline (NTC) ‐20% to +20%

Design & Construction 4 4 40% to 100%Design after NTC 

issued and build the project

‐20% to +20%

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PCTF Proposed Process Improvements

• Standardized Cost Estimate Reporting Template (SCERT)

– all cost estimates

– quarterly reporting

• Proposed Project Cost Working Group (PCWG)– detail its role in project tracking process

• Conditional Notification to Construct (CNTC) 

– projects  > $20 Million and > 100 kVp j $

• Establish Project Estimate baseline

– CNTC Project Estimate (CPE)

– NTC Project Estimate (NPE)

11

• Study Estimate > than $20 Million and > 100 kV

• Additional time for TO to refine estimate

Conditional Notification To Construct (CNTC)

• SPP re‐evaluates project if refined estimate outside accepted bandwidth

• NTCs issued Cost variance is acceptable BOD approves the refined cost analysis

12

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7

• Provides time and cost recovery to allow DTO to refine cost estimate

Value of CNTC

• PCTF recommends  a cost recovery  method for estimate refinement costs

• Additional BOD checkpoint with refined cost analysis 

13

• CNTC Project Estimate (CPE) 

DTO’s response to CNTC 

CNTC Project Estimate

compared to Study Estimate

• Cost variation from CPE to Study Estimate acceptable if its variance bandwidth does not exceed variance bandwidth of Study Estimate

14

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Study Estimate: $100 Million

CPE Evaluation Illustrations

$105 M $126 M

$105 MillionCNTC Project Estimate:

$84 M

15

SPP Issues NTC to DTOAction:

If the +/‐20% precision bandwidth of the project’s CPE is within the accepted range, an NTC will automatically be issued

Study Estimate: $100 Million

CPE Evaluation Illustrations

$120 M $144 M

$120 MillionCNTC Project Estimate:

$96 M

16

SPP Re‐evaluation and BOD ReviewAction:

If the +/‐20% precision bandwidth of the project’s RSE is outside the accepted range, SPP Staff will re‐evaluate the project and submit updated analysis to BOD for review

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Questions

Katherine PrewittDirector, [email protected]

17

Terri GallupPCTF [email protected]

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PROJECT COST TASK FORCE

July 6, 2011

 

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PCTF 2

Table of Contents Introduction ..................................................................................................................................................3 

RSC Motion 1 ...............................................................................................................................................3 

Problem Summary ...........................................................................................................................3 

RSC Motion 4 ...............................................................................................................................................3 

Problem Summary ...........................................................................................................................3 

Project Tracking Current Process .............................................................................................................4 

PCTF Recommendations.............................................................................................................................4 

Standardized Cost Estimate Reporting Template ............................................................................5 

Conditional Notification to Construct ..............................................................................................5 

Project Tracking Enhancements ......................................................................................................5 

Project Specification and Cost Estimation Process .........................................................................7 

PCWG Process ...............................................................................................................................14 

Appendix A ...................................................................................................................................................16

Appendix B ...................................................................................................................................................17

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Introduction

The Markets and Operations Policy Committee (MOPC) formed the Project Cost Task Force (PCTF) to address the SPP Regional State Committee (RSC) Motions 1 and 4 from their October 25, 2010 meeting. This document provides the recommendations that have been jointly developed by the PCTF, SPP staff, and interested stakeholders to address these Motions.

RSC Motion 1

RSC recommends that SPP review what is the best manner to address significant cost increases and/or overruns of transmission projects that are regionally funded.

Problem Summary The issue of increases in transmission project cost estimates is a result of increased project cost estimates provided by Designated Transmission Owners (DTO) in response to their respective Notification To Construct (NTC) letters for some of the Priority Projects approved by the Board of Directors (BOD) in April 2010. This issue is a product of the increased openness and transparency of the SPP planning processes and concern due to the new Highway/Byway regional cost allocation. In the past, transmission cost estimates tended to remain internal to each member utility, subject only to the utility’s internal review processes and any applicable obligations to its regulatory authorities.

With the implementation of SPP’s Highway/Byway cost allocation methodology, additional scrutiny is warranted in reviewing changes to regionally funded project cost estimates for projects that were a result of an SPP process and that have cost estimates greater than $20 million (Applicable Projects). This document describes the PCTF and SPP staff proposed process.

RSC Motion 4

SPP evaluate how cost estimates are established for transmission projects before Cost Benefit Analyses are performed.

Problem Summary Current review of transmission project cost estimates appears to be inadequate, resulting in movement to a more rigorous cost review process that will lead to more transparency of the cost components and assumptions contained within a cost estimate.

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PCTF 4

The PCTF and SPP staff were charged with creating a standardized and transparent method for the development of transmission project cost estimates associated with Applicable Projects. These cost estimates should be refined as projects move from a conceptual estimate to the design/construction phases of an Applicable Project. The PCTF and SPP staff have proposed a continuous tracking and reporting process that reflects updates that will have increasingly higher levels of accuracy and certainty as the project moves from a conceptual cost estimate stage to the completion of the project.

Project Tracking - Current Process

When SPP issues an NTC for an approved project, it is entered into the Project Tracking process. For an NTC associated with SPP approved Project(s), the DTOs currently have 90 days to respond to the NTC committing to a project(s) as specified in the NTC or proposing a different project schedule or project specifications. The DTO is required to submit quarterly updates of cost estimates and the expected in-service date. These updates are incorporated into a quarterly report that is submitted to the BOD/Members Committee, the MOPC, and the RSC. In accordance with the guidelines provided in the SPP Open Access Transmission Tariff (OATT) Business Practices document BP 1.15 - Notification to Construct, cost estimates that have increased by more than 20% since the previous estimate require the DTO to submit justification for the variance.

PCTF Recommendations

The PCTF recommends multiple enhancements to the tracking and the cost estimate processes for projects upon which SPP will perform cost benefit analyses. Revised project tracking enhancements are proposed to the current project tracking process for the DTO to provide a detailed explanation of changes to the study estimate to timely recognize Applicable Projects that are nearing or are already outside stated bandwidths. To increase the transparency related to modifications of cost estimates for projects after BOD approval and issuance of an NTC to a DTO, a defined cost estimate process is proposed to be used for Applicable Projects. The PCTF also recommends implementing a mechanism for a new working group to review whether a project that has experienced a cost variance that exceeds a specified bandwidth is reasonable, and to provide a recommendation to SPP with the working group findings. SPP will determine whether the project should be reevaluated for construction, with the BOD making a final determination regarding the status of the project under review.

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Standardized Cost Estimate Reporting Template The PCTF recommends the development and implementation of a Standardized Cost Estimate Reporting Template (SCERT) that will be utilized for all approved project cost estimates and applicable monthly/quarterly updates. The PCTF developed the SCERT by assessing the appropriate information to be provided in response to the SPP Project Tracking inquiries. The objectives of the SCERT are to:

a. Provide a consistent format among all estimates b. Facilitate the Project Tracking process c. Ensure the required level of detail is provided d. Facilitate the transition of a completed project into the proper Annual

Transmission Revenue Requirement (ATRR) recovery process through SPP’s OATT

The SCERT includes: (i) estimated/actual expenditures spent to date; (ii) estimate at completion; (iii) projected in-service date; (iv) direct and indirect costs; (v) AFUDC estimates and if project has CWIP in rate base; and (vi) proposed route map. An example SCERT is included in Appendix A.

Conditional Notification to Construct The PCTF recommends the introduction of a Conditional Notification To Construct (CNTC) to be issued for Applicable Projects 100 kV and above that have been approved by the SPP Board of Directors (BOD). The purpose of the CNTC is to provide the DTO(s) additional time to perform detailed engineering within a stated timeframe to refine its study estimate for further SPP analysis to determine if the project should proceed with an NTC for actual construction. The CNTC is not an authorization for the DTO(s) to order materials or begin construction on the project, but rather is an initiative to the DTO(s) to perform any cost estimate analysis not previously done to improve the accuracy of the study estimate such that the DTO(s) will be within a +/- 20% precision bandwidth. The PCTF recommends the DTO(s) should be fully compensated (without ROE) for costs incurred to prepare the refined study estimate for projects that SPP determines will not proceed to construction.

Project Tracking Enhancements To make the Project Tracking process more rigorous, the PCTF proposes several enhancements that should be considered for implementation after an NTC or CNTC is issued. For Applicable Projects 100 kV and above that have been approved by the BOD and issued a CNTC:

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PCTF 6

1. If the DTO accepts the CNTC, it shall provide SPP with a CNTC Project Estimate (CPE) as described in Stage 3 of the proposed process (see Project Specification and Cost Estimation Process below).

2. If the CPE variance bandwidth of -20% to +20% does not exceed the study cost estimate variance bandwidth of -30% to +30%, the project’s cost variance will be deemed acceptable and will be immediately issued an NTC by SPP staff. This will be the authorization for the DTO to proceed with the project.

3. If the CPE variance bandwidth exceeds the variance bandwidth of the study estimate, SPP staff will re-evaluate this project using the new cost estimate data, and will make a recommendation to the BOD at its next scheduled quarterly meeting. SPP staff’s recommendation could be but is not limited to one of the following actions:

a. Accept the cost variance and approve the project as is b. Modify the existing project c. Replace the project with an alternative solution d. Cancel the project

4. The study estimate received from the DTO for these projects will be used as the

initial baseline for measuring final project approval.

5. If the cost variation of the CPE is accepted by the BOD, the CPE will be used as a final baseline for reporting all cost estimate changes during the Project Tracking process and will be the basis for determining project variance.

For all other projects approved by BOD and issued an NTC:

1. If the DTO accepts the NTC, it shall respond as prescribed in the NTC letter and provide SPP with a refined study cost estimate. This estimate is referred to as the NTC Project Estimate (NPE).

2. The NPE received from the DTO for these projects will be used as the final baseline for reporting all cost estimate changes during the Project Tracking process and will be the basis for determining project variance.

For all Applicable Projects with an approved NPE:

1. SPP’s Project Tracking process should be enhanced to require DTOs of all Applicable Projects with an approved NPE to submit Project Tracking updates to SPP staff on a quarterly basis, unless the bandwidth is exceeded as denoted in 1.(a) or 1.(b) below, in which case the DTO will notify SPP immediately with the information as follows:

a. If an Applicable Project deviates or is expected to deviate +/-10% from its established baseline cost, the DTO will immediately notify SPP staff

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PCTF 7

detailing the cost variances with an updated SCERT with comments on the variances. SPP staff will provide notification to the Project Cost Working Group (PCWG) with no corrective action expected. SPP staff will monitor these projects and take appropriate action if necessary.

b. If an Applicable Project deviates or is expected to deviate +/-20% from its established baseline cost, the DTO will immediately notify SPP staff detailing the cost variances with an updated SCERT with comments and explanations regarding the variances. SPP staff will provide the updated information to the PCWG. The PCWG will review and provide recommendations to the MOPC and BOD. The PCWG will provide an update to the RSC. The DTO will be required to provide monthly updates to SPP staff until BOD action is taken.

2. At least quarterly, SPP will submit a Project Tracking report to the PCWG detailing all project cost estimate changes outside the established project variance bandwidth.

Project Specification and Cost Estimation Process The PCTF recommends a tiered approach for project cost estimates based on the level of project definition that is known while also considering an appropriate level of risk valuation. These stages are defined as:

• The Conceptual Estimate is the estimate prepared by SPP staff based on historical cost information in an SPP database and updated information provided by the DTO(s). It is to be used as a screening tool to determine if a project is cost-effective and should or should not be pursued in meeting a determined system need. This estimate would not attempt to address detailed environmental, geography, terrain or other issues.

• The Study Estimate is the estimate prepared by the DTO(s) for projects that pass

the Conceptual Estimate screening process and require a more refined cost estimate for project approval.

• The CNTC Project Estimate (CPE) is the estimate prepared by the DTO(s) for

projects after the receipt of a CNTC. This estimate will include any cost estimate analysis not previously done to improve the accuracy of the Study Estimate, but before any construction investment is made by the DTO(s).

• The NTC Project Estimate (NPE) is provided by the DTO after receipt of an NTC for a non-Applicable Project; it includes any additional cost information known at the time the DTO is required to provide its response to the SPP.

• Design and Construction Estimates are provided by the DTO to SPP after the

DTO engineering and construction are being completed, including any environmental, routing or siting requirements, and that has a known route. This

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PCTF 8

would include but not be limited to any known material and labor costs. This cost estimate will also include any known condemnation costs.

The Cost Estimate Stage Definition table below lists the four stages of the project estimating process. Each of these stages must have more refined requirements for the accuracy of cost estimates and detail of data. The bandwidth for estimate accuracy reduces as the scope definition detail increases.

Estimate Name* Stage

Level of Project Scope

Definition End Usage Precision

Bandwidth

Projects > 100

kV & > $20 Million

All other BOD Approved Projects

Conceptual 1 1 0% to 10% Concept

screening for ITP20/ITP10

-50% to + 100%

Study 2 2 10% to 20%

Study of feasibility and

plan development for ITP10/ITPNT

-30% to +30%

CNTC Issued NTC Issued

CNTC Project (CPE) 3 N/A 20% to 40% Final baseline

(CNTC)** -20% to +20%

NTC Issued

NTC Project (NPE) N/A 3 20% to 40% Final baseline

(NTC)** -20% to +20%

Design & Construction 4 4 40% to 100%

Design after NTC issued and build

the project -20% to +20%***

* The Conceptual Estimate will be prepared by SPP. All subsequent estimates will be prepared by the DTO(s). **BOD approval required to reset the baseline. ***Actual cost is expected to be within +/-20% of final baseline estimate.

Table 1: Cost Estimate Stage Definition

The PCTF recommends that DTOs develop consistent cost estimates through the completion of a SCERT for similar information to be included in a cost estimate as well as assumptions used by the DTO to develop the Study Estimate. For the Study phase estimate, all DTOs shall base those estimates relative to design best practices and performance criteria. The sections below describe each Stage of the Cost Estimation process in more detail:

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Conceptual Estimate Stage

Knowns and unknowns are meant to be illustrative In this first stage, SPP staff will develop the initial project scopes and Conceptual Estimates using a generic cost estimate tool (database platform) that will be developed in conjunction with the Transmission Owners1. The estimating tool will include generic SPP historical cost data such as cost per mile for specific voltage levels, substation cost estimates, and cost modifiers for other factors such as different regions, terrain, urban/rural, etc. This allows cost estimates to be developed easily for screening large numbers of potential projects and selecting suitable candidates for further study. The output of the tool will be a table providing the total cost estimate for each project under consideration, as well as all the supporting information for each. This will provide an easy-to-use reference for the cost estimates and the variations among them. SPP staff, in conjunction with the Transmission Owners, will update the cost data used in the cost estimating tool on an annual basis. To support these updates, SPP staff will provide an aggregate summary of final cost data collected in the Project Tracking process. This will ensure the cost estimate tool is kept up-to-date for Conceptual Estimates and will help refine the tool to reflect actual costs.

1 Future development

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Study Estimate Stage

Knowns and unknowns are meant to be illustrative Stage 2 begins after the initial project screening is completed and the list of potential projects has been narrowed to those most likely to be selected. SPP and incumbent DTO for each project must review and refine the project scope and provide study-level cost estimates for each alternative project. The Study Estimate is the first detailed estimate the DTOs will be required to submit. For this estimate, DTOs will base assumptions relative to design best practices and performance criteria. There are still a large number of unknowns at this point in the planning process and the project scope should identify those unknowns and the risks associated with them. The final project cost is expected to be within a -30% to + 30% variance from Study Estimate.

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CNTC Project Estimate Stage

Knowns and unknowns are meant to be illustrative For Applicable Projects 100 kV and above, the DTO’s time to submit an updated cost estimate to SPP, referred to as the CNTC Project Estimate (CPE), will be extended to allow the DTO the opportunity to perform cost estimate analysis not previously done to improve the accuracy of the Study Estimate. The CPE should be submitted to SPP no later than four months prior to the start of the next applicable ITP process cycle. If the cost variation exceeds the accepted bandwidth, SPP staff will re-evaluate the project with the updated cost data and present this analysis to the BOD, no later than one quarter prior to the start of the next applicable ITP process cycle. The final project cost is expected to be within a -20% to + 20% variance from the CPE.

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NTC Project Estimate Stage

Knowns and unknowns are meant to be illustrative This stage begins after a non-Applicable Project has been issued an NTC. The DTO has 90 days to respond to the NTC by committing to a project as specified in the NTC or proposing a different project schedule or project specifications. If the DTO accepts the NTC, it shall respond as prescribed in the SPP NTC letter and provide SPP with a refined study scope and cost estimate. This estimate will be referred to as the NTC Project Estimate (NPE). The NPE will cover the period between accepting the NTC and the start of project design. The final project cost is expected to be within a -20% to + 20% variance from the NPE.

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Design and Construction Estimate Stage

Knowns and unknowns are meant to be illustrative This stage covers the period between starting design engineering to the final project closeout and submittal of actual project costs to SPP through the Project Tracking process. All line-item differences between the estimate being used as a baseline and these updated estimates must be accompanied by a detailed explanation from the DTO. The final project cost is expected to be within a -20% to + 20% variance from the applicable CPE or NPE.

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PCWG Process The PCTF proposes that SPP stage the implementation of the process proposed for PCWG to initially apply to approved Applicable Projects 300 kV and above, and after the process is refined and working well to include approved Applicable Projects 100 kV and above. The DTO shall immediately provide data and information to [email protected] for any Applicable Project that deviates or is expected to deviate +/- 10% from its established baseline cost. SPP staff will then notify the PCWG. The PCWG may require the DTO to provide a monthly project tracking data. If an Applicable Project deviates or is expected to deviate +/-20% from its established baseline cost, the DTO will immediately notify SPP staff detailing the cost variances with an updated SCERT with comments and explanations regarding the variances. The PCWG will oversee a quarterly report to be submitted to the MOPC, RSC, and BOD prior to their quarterly meetings. The PCWG will receive the updated scope and SCERT, project tracking data updates, any comments from the DTO related to cost estimate variances, and any applicable input from SPP staff. The DTO’s comments should include relevant information regarding any sunk costs, an explanation for the cost estimate variances, and comments as to why the project should or should not continue forward. The PCWG’s recommendations to the MOPC and BOD may include any of the following:

i. Accept the cost deviation as reasonable and acceptable and reset the

baseline used to evaluate future cost deviations. ii. Identify all or a portion of costs related to the variances and recommend

changes to the NTC that would reduce the cost or avoid issues that may be causing the increase.

iii. Suspend all future expenditures on the project while SPP restudies the project to determine appropriate changes to the NTC or possible withdrawal of the NTC.

If the PCWG recommends a restudy and/or changes or revocation of the NTC, the recommendation to the MOPC would follow SPP’s existing processes for approval to the BOD. The BOD will make the final determination on whether to restudy and/or change or revoke the NTC. There are instances when resetting the baseline cost estimate will be prudent, as it would not be reasonable for a project to be flagged automatically for review every month following a cost estimate variance that had been previously reviewed and accepted. The PCWG will recommend to the BOD whether to reset the baseline cost estimate. The

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BOD will make the final determination on whether to reset the baseline. If a baseline cost estimate is reset, the previous estimates will be retained in the monitoring tool.

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Appendix A

Standardized Cost Estimate Reporting Template (SCERT)

SPP Project Name 

Current Year Dollars   Loaded Nominal Dollars   

Project ID 

Upgrade ID 

Estimate Provider  

Estimate Creation Date 

Project Scope 

RTO Determined Need Date 

Project Start Date   In‐Service Date  

Line Costs Loaded 

Nominal $   Line Assumptions  Segment 1  Segment 2 

Engineering Labor  Mileage       

Construction Labor  Number of Circuits       

Right‐of‐Way  Shield Wire 

Number       

Material  Type       

Line Sub‐Total  Size       

Station Costs    

Conductor 

Type       

Engineering Labor  Size       

Construction Labor  Rating       

Site Property Rights  # Conductors per 

Phase       

Material 

Structure 

Configuration       

Station Sub‐Total  Foundation Type       

Summary Info     Material       

Line Sub‐Total    NESC 

Assumptions       

Station Sub‐Total     Dead Ends       

AFUDC     Tangents       

CWIP (Y/N)     Underbuild       

Contingency     Station Assumptions  Station 1  Station 2 

Total Project Cost Estimate     Location       

Transformers Quantity       

Size       

Breaker Scheme 

Quantity       

Size       

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Appendix B

Conceptual Estimate

Development

Did project pass

screening?

Study Estimate

Development

BOD Approval

Historical Project Data

Conceptual Cost

Estimate

Is Project >100 kV and

Study Estimate > $20

Million?

CNTC Issuance

CNTC Project Estimate

Development

CNTC Project Estimate

(CPE)

Is CPE bandwidth within acceptable

range?

Project Re-evaluation

Study Cost Estimate

NTC Issuance

BOD Approval

SPP Task

DTO Task

Stakeholder Group, MOPC, RSC, and/or BOD Task

Cont’d Page 2

Project Tracking Process Flow

Did BOD approve project?

Project Solution

Conception

Alternate Solution

Cancel or Replace Project

Did BOD approve re-evaluation?

Cancel or Replace Project

YES

NO

NO

NO

YES

YES

NO

NO

NTC Project Estimate

Development

NTC Project Cost Estimate

(NPE)

NTC Issuance

YES

YES

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Southwest Power Pool, Inc. 

PCTF 18

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Southwest Power Pool Project Cost Working Group

Charter July 6, 2011

Purpose To maintain the integrity of the SPP transmission project estimate process, a rigorous and transparent evaluation of cost estimate variances is required. The SPP project tracking process sets cost variance bandwidths and mandates justification and review for cost estimates that have changed outside these bandwidths.

The purpose of establishing the Project Cost Working Group (PCWG) is to create a group with stakeholder input, oversight, and accountability that can provide a transparent review of transmission cost variances. To ensure cost estimate variances are addressed in a timely manner, the PCWG will evaluate projects exceeding allowable variance levels on a monthly basis. As a part of the project estimate review, the PCWG will provide recommendations to the Markets and Operations Policy Committee (MOPC) and Regional State Committee (RSC) for review and to the SPP Board of Directors (BOD) for approval. On a quarterly basis, the PCWG will provide a report of their findings and comments to Stakeholders.

Scope of Activities In carrying out its purposes, the PCWG will:

1. Provide a monthly review of regionally funded projects that have been identified by the SPP project tracking process as having estimated costs that have exceeded allowable variance levels.

2. Provide recommendations for projects that exceed the allowable variance levels. 3. Provide a quarterly report to Stakeholders.

Representation The PCWG membership should consist of members who can collectively represent the interests of the SPP stakeholders. To ensure they have the expertise to make the recommendations required, these members should have experience in one or more of the following areas: transmission construction costs/estimating, project management, and/or ratemaking.

PCWG membership will consist of up to the following:

10 Voting members-

• 5 Transmission Owning • 5 Transmission Using

Non-Voting member-

• 1 CAWG Liaison

Duration Permanent

Reporting The PCWG reports to the Markets and Operations Policy Committee.

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Other Notes: In light of FERC Orders 888 and 889 and the group composure of transmission and generation parties, the PCWG will have to observe the Standards of Conduct outlined in FERC Order 889. As such, there may be topics discussed by the PCWG that are privileged and confidential. Under such an event, appropriate measures will be taken to ensure that no Standards of Conduct are violated, including but not limited to, closed meetings, closed sessions, etc. Members and participants will be required to adhere to SPP’s Nondisclosure Agreement.

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Southwest Power Pool, Inc. DESIGN BEST PRACTICES AND PERFORMANCE CRITERIA TASK FORCE

Recommendations to the Strategic Planning Committee July 14, 2011

Organizational Roster Jake Langthorn, OGE (Chair) Allen Ackland (KCPL) Scott Benortham (Westar Energy) Jeff Brown (EMDE) Brian Brownlow (NPPD) Terri Gallup (AEP) Kent Herzog (OPPD) JD Linscott (LES) Erin Keeler (ITC Great Plains) Dave Parrish (AEP West Txm) Jeff Stebbins (SPS/Xcel Energy) Noman Williams (Sunflower) Patrick West (SWPA) Jay Caspary, SPP Staff

Background Design Best Practices and Performance Criteria Task Force (DBPPCTF) was approved by the Strategic Planning Committee on April 28, 2011 to address the following:

To establish Design Best Practices and Performance Criteria (DBP&PC) to be used by the SPP’s Transmission Owners (TOs) in developing Study Estimates for SPP footprint projects rated at voltages at 100 kV and greater. These DBP&PC are intended to ensure consistency in TO Study Stage estimates.

Analysis The DCPPCTF held 6 conference calls and webinars in May through June, to finalize its scope and develop a final draft of Study Estimate Design Guide. This Guide documents design best practices and performance criteria regarding transmission lines, substation, as well as system protection and control design, as well as scoping requirements to provide a common foundation for study stage estimates for TOs to provide for initial SPP planning assessments.

The DBPPCTF concluded its initial efforts in June in advance of the July series of SPP meetings. The proposed Study Estimate Design Guide as a final draft was approved unanimously by its members.

Recommendations

• SPC provide comments/direction to finalize draft report so that it can be approved

• Amend title of report to be “Study Estimate Design Guide” and incorporate revised name into all affected SPP documents

• Post “Study Estimate Design Guide” to SPP Governing Documents on the SPP website

Action Requested: Approve Recommendations.

Recent Approvals: DBPPCTF approved this final draft on June 30, 2011.

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1

DBPPCTF Recommendationsto SPC

April 14, 2011

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Design Best Practices and Performance Criteria Task Force

• Design Best Practices and Performance Criteria Task Force  (DBPPCTF) was approved by the Strategic Planning Committee on April 28, 2011 to address the following:

– To establish Design Best Practices and Performance Criteria (DBP&PC) to be used by the SPP’s Transmission O (TO ) i d l i S d E i f SPPOwners (TOs) in developing Study Estimates for SPP footprint projects rated at voltages at 100 kV and greater.  These DBP&PC are intended to ensure consistency in TO Study Stage estimates. 

3

DBPPCTF Roster

• The DBPPCTF is chaired by Jake Langthorn of OG&E with the following representatives of TOs:

– Allen Ackland (KCPL), Scott Benortham (Westar Energy), 

– Jeff Brown (EMDE), Brian Brownlow (NPPD), 

– Terri Gallup (AEP), Kent Herzog (OPPD),  JD Linscott (LES), 

– Erin Keeler (ITC Great Plains), 

– Dave Parrish (AEP West Transmission),Dave Parrish (AEP West Transmission), 

– Jeff Stebbins (SPS/Xcel Energy), 

– Noman Williams (Sunflower),  and Patrick West (SWPA)

4

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DBPPCTF Scope of Activities

• As outlined in the SPC TF recommendations, the DBPPCTF will address the following items:

1.1.3. SPC recommends the Transmission Owners achieve consensus on the development of region‐wide design best practices to be consolidated within a document managed by SPP. The existing ad‐hoc group of transmission owners should continue their informal dialogue to establish design best practices and performance criteria focused on providing consistently developed estimates at the “study” stage. The group should provide a status report in 3rd Quarter 2011 and finalize their work product by 4th Quarter 2011. … 

5

DBPPCTF Scope of Activities (cont)

…The establishment of such design best practices and performance criteria should address policy decisions such as:

1.1.3.1. Design best practices to be used to establish similar design objectives no matter who builds it.

1.1.3.2. Objective to get estimates that do not change outside a bandwidth over the design and construction phases of a project.

1.1.3.3. Performance criteria needed to concisely describe the intended scope of a project.

1.1.3.4. Scope details needed by a Transmission Owner to provide a level of estimate that has the appropriate bandwidth.

6

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DBPPCTF Scope of Activities (cont)

1.1.4. SPC recommends adopting a set of performance criteria. The performance criteria may include:

1.1.4.1. Normal and emergency conductor or equipment ampacityfor a given project Voltage

1.1.4.2. Normal and emergency terminal equipment ampacities

1.1.4.3. Locally relevant wind/ice loadings

1.1.4.4. Appropriate interrupting fault current levels

1 1 4 5 Substation bus configurations1.1.4.5. Substation bus configurations

1.1.5. SPC recommends that performance criteria be utilized to evaluate project variances following the issuance of NTC’s and in subsequent phases.

7

DBPPCTF Activities

• The DBPPCTF met via 6 teleconference/webinars from May 12th through June 30th. 

• Input and coordination with the PCTF was accomplished to a large extent as a result of the overlapping membership and participation by stakeholders in these complimentary efforts.

• Meeting documents posted at http://www.spp.org/section.asp?group=2157&pageID=27

• Next meeting set for July 22nd from 8 to 10AM 

8

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Final Draft Report Overview

• “SPP Design Best Practices, Performance Criteria and Scoping Guidelines for Transmission Facilities” outline

• Introduction

• Design Best Practices & Performance Criteria• Transmission Lines

• Transmission Substations• Transmission Substations

• Transmission Protection and Control Design

• Scoping Requirements

9

Introduction Highlights

• Design Best Practices & Performance Criteria (DBP&PC) are intended to promote consistency in TO Study Stage estimates

• TO Study Estimate assumptions will be detailed in the Standardized Cost Estimate Reporting Template (SCERT) being developed by the PCTF

10

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DBP&PC Highlights for Lines

• Minimum Conductor Sizing for normal ratings is specified, e.g., 1,200 Amps for 230 kV and 3,000 Amps for 345 kV

• Reconductoring should consider advanced conductors if existing structures are adequate and have sufficient life expectancy to preclude tear down and rebuilds

• Reactive Compensation costs should be included in project costs estimates , as appropriate, with a default assumption of 1 MVAR per mile of line

11

DBP&PC Highlights for Substations

• Substations should be designed to accommodate future expansion and includes suggested bus configurations by voltage class and number of terminals

• Minimum rating of terminal equipment is specified, e.g., 1,200 Amps for 230 kV and 3,000 Amps for 345 kV

• Minimum bus rating is specified, e.g., 2,000 Amps for 230 kV and 3,000 Amps for 345 kV

12

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DBP&PC Highlights for Protection/Controls

• Protection and control designs for all facilities should include due consideration of redundancy to provide necessary reliability and flexibility to facilitate system operations and maintenance

• PMUs or Intelligent Electronic Devices (EIDs) should be installed in all new 230 kV and above substations

• SCADA and RTUs should be considered for all substations

13

DBPPCTF Recommendations

• SPC provide comments/direction to finalize draft report so that it can be approved

• Amend title of report to be “Study Estimate Design Guide” and incorporate revised name into all affected SPP document

• Post “Study Estimate Design Guide” to SPP Governing Documents on the SPP website 

14

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SPC Action Item

• Approve the “Study Estimate Design Guide” or direct further actions as appropriatedirect further actions, as appropriate

• Direct staff to incorporate “Study Estimate Design Guide” into all affected SPP documents

• Disband DBPPCTF at the conclusion of their efforts

15

Jake Langthorn –OG&E 

16

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Page 1 of 20

SPP Design Best Practices, Performance Criteria, and Scoping Guidelines for Transmission

Facilities Draft Dated July 1, 2011

Introduction

Applicability This document outlines the Design Best Practices and Performance Criteria (DBP&PC) to be used by the Transmission Owner (TO) when developing Study Estimates for the SPP footprint projects rated at voltages of 100 kV and greater. These DBP&PC are intended to promote consistency in TO Study Stage estimates. Recognizing the importance of well defined scopes when developing cost estimates, this document also contains scoping guidelines for the Conceptual and Study estimate phases. These guidelines will promote mutual understanding of the project definition between SPP and the TOs as the project is developed and estimates are prepared for the applicable phase of the potential project. TO Study Estimate assumptions will be detailed in the Standardized Cost Estimate Reporting Template (SCERT) as used by the SPP project cost tracking process.

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Page 2 of 20

Design Best Practices and Performance Criteria Design Best Practices represent high-level, foundational principles on which sound designs are based. Design Best Practices facilitate the design of transmission facilities in a manner that is compliant with NERC, SPP, and TO requirements; are consistent with Good Utility Practice as defined in the SPP Open Access Transmission Tariff (SPP Tariff)1; are consistent with industry standards such as NESC, IEEE, ASCE, CIGRE, and ANSI; and are cost-effective. Although not addressed here, construction and maintenance best practices must be considered during the design phase to optimize these costs and efficiencies.

Performance Criteria further define the engineering and design requirements needed to promote a more uniform cost and reliability structure of the transmission facilities and to ensure that the TOs construct project(s) within the parameters requested by SPP. Flexibility is given such that the TO’s historical and current performance criteria, business processes, and operation and maintenance practices are considered. Individual sections within this document contain both Design Best Practices and Performance Criteria.

Scope Management A well developed and rigorously managed scoping document promotes consistent estimates and helps control costs. It also ensures that the SPP and TO have a clear understanding of the project being reviewed.

1 The SPP Tariff defines Good Utility Practice as follows: “Good Utility Practice: Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region, including those practices required by Federal Power Act section 215(a)(4).”

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Design Best Practices & Performance Criteria

Transmission Lines

General Any criteria established for the design of transmission lines must consider safety, reliability, operability, maintainability, and, economic impacts. The NESC contains the basic provisions considered necessary for the safety of utility personnel, utility contractors, and the public. However, the NESC is not intended to be used as a design manual, so Good Utility Practice must also be considered. Where applicable, RUS guidelines should also be considered.

Siting and Routing The impact of the transmission facility to the surrounding environment should be considered when developing the study estimate. Sensitivity to wetlands, cultural and historical resources, endangered species, archeological sites, existing neighborhoods, and federal lands, are examples that should be considered when siting transmission facilities. The TO must comply with the requirements of all appropriate regulatory agencies during the siting process, and all applicable environmental and regulatory permits must be obtained for the transmission facilities. The TO should describe any known or anticipated environmental issues and associated estimated costs in the Study Estimate, as well as any estimated regulatory siting and permitting costs. Study Estimates will use a default assumption for line mileage that is based upon right angle design absent better assumptions. Where two or more TOs are directed by the SPP to build a project, the TOs shall agree between them how much of the project should be built by each. The TOs will then submit a Study Estimate in accordance with these design best practices.

Electrical Clearances The clearances of the NESC shall be adhered to in the design of transmission lines. Conductor-to-ground and conductor-to-conductor clearances should include an adequate margin during design to account for tolerances in surveying and construction. Sufficient climbing and working space for NESC and OSHA working clearances should be considered when establishing the geometrical relationships between structure and conductors. Appropriate clearances should be maintained considering NESC requirements, maximum operating temperature, and extreme ice loading. Conductor-to-conductor clearances should account for sag and tension, wire movement variances, and minimum approach distances. Where applicable, dynamic effects (e.g. galloping conductors, ice-drop, etc.), should be considered.

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Structure Design Loads Structures will be designed, at a minimum, to NESC standards and in accordance to the TO’s design practices, as appropriate.

Design Load Application Structures and foundations should be designed to withstand a combination of gravity, wind, ice, conductor tension, construction, and maintenance loads. The following loadings, based on ASCE Manual of Practice (MOP) 74, should be considered to help ensure structural integrity under most probable loading combinations. Dynamic loading (e.g. galloping, ice-drop, etc.) of conductors should also be considered.

Loads with All Wires Intact • NESC requirements

• Extreme wind applied at 90º to the conductor and structure

• Extreme wind applied at 45º to the conductor and structure

• Combined wind and ice loadings

• Extreme ice loading

Unbalanced Loads • Unbalanced loads should be considered to prevent local and cascading failure. Spacing

for cascading should be predicated on TO practices.

o Longitudinal loads due to unbalanced ice conditions (ice in one span, ice fallen off of adjacent span) with all wires intact

o Longitudinal loads due to a broken ground wire or one phase position (the phase may consist of multiple sub-conductors)

Construction and Maintenance Loads • Construction and maintenance loads shall be applied based on the recommendations of

ASCE MOP 74.

• These loads may be modified based on local TO construction, maintenance, and safety practices.

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Structure and Foundation Selection and Design Structure types may be latticed steel towers or steel, concrete, or wood poles at the TO’s discretion. The choice should be based on consideration of structural loading, phase configuration, total estimated installed cost and other economic factors, aesthetic requirements, siting restrictions, and right-of-way requirements.

Structure design should be based on the following as they apply:

• ASCE Standard No. 10, Design of Latticed Steel Transmission Structures

• ASCE Standard No. 48, Design of Steel Transmission Pole Structures

• ASCE Publication Guide for the Design and Use of Concrete Poles

• ANSI 05-1, Specifications and Dimensions for Wood Poles

• IEEE Std. 751, Trial-Use Design Guide for Wood Transmission Structures

Structures may be supported on concrete piers, grillages, piles, or they may be directly embedded. The method selected shall be based on known or anticipated geotechnical conditions and structure loading.

Insulation Coordination, Shielding, and Grounding Metallic transmission line structures shall be grounded. Overhead static wires (shield wires) should also be grounded, or a low impulse flashover path to ground should be provided by a spark gap. Individual structure grounds should be coordinated with the structure insulation level and static wire shielding angles (with reference to the phase conductors) to limit momentary operations of the supported circuit(s) to the targeted rate. The coordination of grounding, shielding and insulation should be established considering the effects of span lengths, conductor-to-ground clearances, lightning strike levels, and structure heights.

Rating of Phase Conductors The maximum operating temperature of phase conductors shall be based on metallurgical capacity (i.e., the maximum temperature the conductor can withstand without incurring damage due to heat) and assuming a reasonable loss of strength.

The conversion to ampacity shall be based on IEEE Publication No. 738, Standard for Calculating the Current-Temperature of Bare Overhead Conductors, and SPP Criteria 12.

The TO should select environmental parameters based on its experience and historical and current line rating and operating procedures.

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Selection of Phase Conductors Phase conductors should be selected based on the anticipated power flow of the circuit, metallurgical and mechanical properties and proper consideration for the effects of the high electric fields.

Minimum Conductor Sizing The conductor size shall be selected by the TO based on metallurgical (losses, impedance), mechanical, and corona performance. The TO should also consider: electrical system stability (voltage and stability), ampacity, and efficiency effects when selecting conductor size.

The following minimum normal amperage ratings should be considered:

Voltage (kV) Amps 100 - 200 As

Specified by SPP

230 1,200

345 3,000

500 3,000

765 4,000

Reconductoring TOs should consider the application of advanced conductors for reconductoring projects if existing structures are adequate and have sufficient life expectancy to preclude tear down and rebuilds.

Optical Ground Wire Optical Ground Wire (OPGW) is preferred for all overhead shield wires to provide a communication path for the transmission system. Where there are multiple static wires only one is recommended to be OPGW. Consideration should be given to installing both wires as OPGW at voltages of 345 kV and higher to provide redundancy for protection schemes. Where there is an underground fiber communication path OPGW is not preferred. The size shall be determined based on the anticipated fault currents generating from the terminal substations.

Adequate provisions should be made for OPGW repeater redundancy as well as power supply redundancy at each repeater.

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Reactive Compensation Project cost estimates should include reactive compensation as appropriate. The default assumption should be 1 MVAR of reactive compensation per mile of line.

Transmission Substations

General Criteria established for the design of transmission substations must consider safety, reliability, operability, maintainability, and economic impacts. The NESC contains the basic provisions considered necessary for the safety of utility personnel, utility contractors, and the public. However, the NESC is not intended to be used as a design manual, so Good Utility Practice must also be considered. Where applicable, RUS guidelines should also be considered.

Substation Site Selection and Preparation When selecting the substation site, careful consideration must be given to factors such as line access and right-of-way, vehicular access, topography, geology, grading and drainage, environmental impact, and plans for future growth. Each of these factors can affect not only the initial cost of the facility, but its on-going operation and maintenance costs. Storm water management plans and structures must comply with all federal, state, and local regulations.

Electrical Clearances The clearances for substation design shall be in accordance with all applicable standards and codes. Vertical clearances to ground shall meet or exceed the NESC requirements. When the exposed conductors are in areas where foot traffic may be present, a margin may be added to the NESC clearance. Substation phase spacing shall meet IEEE C37.32 and NESC requirements. Sufficient space for OSHA working clearances should be provided when establishing the geometrical relationships between structure and conductors.

Structure and Foundation Selection and Design Structures may be designed and fabricated from tapered tubular steel members, hollow structural steel shapes, and standard structural steel shapes. The selection of structure type (e.g., lattice, tubular, etc.) should be based on consideration of structural loading, equipment mounting requirements, total estimated installed cost and other economic factors, and aesthetic requirements.

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Structure design should be based on the following, as appropriate:

• ASCE Standard No. 10, Design of Latticed Steel Transmission Structures

• ASCE Standard No. 48, Design of Steel Transmission Pole Structures

• ASCE Standard No. 113, Substation Structure Design Guide

• AISC’s Steel Construction Manual

Structures may be supported on concrete piers, spread footings, slabs on grade, piles, or they may be directly embedded. The method selected shall be based on known or anticipated geotechnical conditions, structure loading, and obstructions (either overhead or below grade).

Design Load Application Structures and foundations should be designed for all loads acting on the structure and supported bus or equipment, including forces due to gravity, ice, wind, line tension, fault currents and thermal loads. The following loadings should be considered:

Line Structures and Shield Wire Poles

• NESC requirements

• Extreme wind applied at 90 degrees to the conductor and structure

• Combined wind and ice loadings

• Extreme ice loading

Equipment Structures and Shield Poles without Shield Wires

• Extreme wind, no ice

• Combined wind and ice loadings

• In the above loading cases, wind loads shall be applied separately in three directions (two orthogonal directions and at 45 degrees, if applicable)

• Forces due to line tension, fault currents and thermal loads shall also be considered

• Deflection of structures should be limited such that equipment function or operation is not impaired

Grounding The substation ground grid should be designed in accordance with the latest version of IEEE Std. 80, Guide for Safety in AC Substation Grounding. The grid should be designed using the maximum anticipated fault current.

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Substation Shielding All bus and equipment should be protected from direct lightning strikes using an acceptable analysis method such as the Rolling Sphere Method. IEEE Std. 998, Guide for Direct Lightning Stroke Shielding of Substations, may be consulted for additional information.

Bus Selection and Design Bus selection and design must take into consideration the electrical load (ampacity) requirements to which the bus will be subjected, in addition to structural loads such as gravity, ice, wind, short circuit forces, and thermal loads. Bus conductor and hardware selection are also critical to acceptable corona performance and the reduction of electromagnetic interference. Allowable span lengths for rigid-bus shall be based on both material strength requirements of the conductor and insulators, as well as acceptable bus deflection limits. Guidelines and recommendations for bus design can be found in IEEE Std. 605, Guide for Bus Design in Air Insulated Substations.

Bus Configuration Substations should be designed to accommodate future expansion of the transmission system (e.g. converting ring bus to a breaker and a half as terminals are added). The following table provides suggested bus configurations.

Voltage (kV) Number of Terminals Substation Arrangement

100 - 499 One or Two Single Bus

Three to Six Ring Bus

More than Six Breaker-and-a-half

500/765 One or Two Single Bus

Three to Four Ring Bus

More than Four Breaker-and-a-half

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Rating of Bus Conductors The maximum operating temperature of bus conductors should be based on metallurgical capacity (i.e., the maximum temperature the conductor can withstand without incurring damage due to heat) and assuming a reasonable loss of strength.

The conversion to ampacity shall be based on the IEEE Std. 738, Standard for Calculating the Current-Temperature of Bare Overhead Conductors, and IEEE Std. 605, Guide for Bus Design in Air Insulated Substations. The TO should select environmental parameters based on its experience and historical and current bus rating and operating procedures. Bus conductors should be sized for the maximum anticipated load (current) calculated under various planning conditions and contingencies. The bus should be designed so as to not be the limiting element.

Substation Equipment Future improvements should be considered when sizing equipment.

Surge protection should be applied, where appropriate, on all line terminals with circuit breakers and considered on all oil-filled electrical equipment in the substation such as transformers, instrument transformers and power PTs.

All substation equipment should be specified such that audible sound levels at the edge of the substation property are appropriate to the facility’s location.

Bus and Equipment Insulation Levels Minimum BIL ratings for substation insulators, power transformer bushings, potential transformer bushings, current transformer bushings, and power PTs are found in the tables below. When placed in areas of heavy contamination (coastal, agricultural, industrial), insulator contamination can be mitigated by using extra-creep insulators, applying special coatings to extra-creep porcelain insulators, and using polymer insulators. Substation Insulators

Nominal System L-L Voltage (kV)

BIL (kV Crest)

BIL (kV Crest) Heavy Contaminated Environment

115 - 138 550 650 (Extra Creep)

161 650 750 (Extra Creep)

230 900 900 (Extra Creep)

345 1050 1300 (Extra Creep)

500 1550 1800 (Standard Creep)

765 2050 2050 (Standard Creep)

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Power Transformers, Potential Transformers and Current Transformers

Nominal System L-L Voltage (kV)

Power Transformer Winding BIL

(kV Crest)

Power PTs(kV Crest)

PT and CT BIL (kV Crest)

Circuit Breaker BIL (kV Crest)

115 450 550 550 550

138 650 650 650 650

161 650 650 650 650

230 825 900 900 900

345 1050 1300 1300 1300

500 1550 N/A 1550 / 1800 1800

765 2050 N/A 2050 2050

Rating Margins for Substation Equipment Substation equipment shall be rated to carry the anticipated worst-case loading.

Minimum Interrupting Fault Current Levels Minimum substation design symmetrical fault current ratings can be found in the following table. The fault current capability must exceed expected fault duty.

Voltage (kV)

Interrupting Current

Symmetrical (kA) 100 – 345 40

500 50

765 50

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Minimum Rating of Terminal Equipment Minimum ratings of substation terminal equipment should be as follows:

Voltage (kV) Amps 100 - 200 1,200

230 1,200

345 3,000

500 3,000

765 4,000

Minimum Bus Rating Minimum ratings of substation bus should be as follows:

Voltage (kV) Amps 100 - 200 2,000

230 2,000

345 3,000

500 3,000

765 4,000

Substation Service There should be two sources of AC substation service for preferred and back-up feeds. An acceptable substation service alternative would be to feed the substation service transformers via the tertiary winding of an autotransformer or connect power PTs to the bus. Distribution lines are not preferred as the primary AC source because of reliability concerns, but can be used when other sources are unavailable. If there are no feasible alternatives for a back-up substation service, provision of a generator should be considered.

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Control Enclosures Control enclosures may be designed to be erected on site, or they may be of the modular, prefabricated type. Enclosures may be constructed of steel, block, or other alternative materials, and should be designed and detailed in accordance with the applicable sections of the latest editions of the following:

• AISC Specification for Structural Steel Buildings

• ACI 530/530.1, Building Code Requirements and Specification for Masonry Structures and Related Commentaries

• ACI 318, Building Code Requirements for Structural Concrete and Commentary

• AISI Specification for the Design of Cold-Formed Steel Structural Members.

Design loads and load combinations should be based on the requirements of the International Building Code or as directed by the jurisdiction having authority. Enclosure components shall also be capable of supporting all cable trays and attached equipment such as battery chargers and heat pumps. Wall and roof insulation should be supplied in accordance with the latest edition of the International Energy Conservation Code for the applicable Climate Zone.

Oil Containment Secondary oil containment should be provided around oil-filled electrical equipment and storage tanks in accordance with the requirements of the United States EPA. More stringent provisions may be adopted to further minimize the collateral damage from violent failures and minimize clean-up costs. Additional design information can be found in IEEE Std. 980, Guide for Containment and Control of Oil Spills in Substations

Single Pole Switching / Breakers / Controls Facilities 500kV and above should consider single pole switching.

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Transmission Protection and Control Design

General Criteria for employing protection and control principles in the design and construction of new substations must adhere to NERC Reliability Standards and SPP Criteria, as well as individual TO standards.

These guiding principles and best practices center on the following criteria:

• Communication Systems

• Voltage and Current Sensing Devices

• DC Systems

• Primary and Backup Protection Schemes

Communication Systems Power Line Carrier (PLC) equipment or fiber as the communication medium in pilot protection schemes is recommended to meet the high-speed communication required. PLC equipment is typically used on existing transmission lines greater than five miles in length. Fiber protection schemes should be considered on all new transmission lines being constructed using OPGW. Compatible relays, considering the use of the same manufacturer, should be installed at both ends. Other forms of communication, i.e. microwave or tone, may be considered.

Voltage and Current Sensing Devices Independent current transformers (CTs) are recommended for primary and backup protection schemes in addition to independent secondary windings of the same voltage source (i.e., CCVTs).

DC Systems DC systems should be designed in accordance with NERC standards, SPP Criteria, and TO practices.

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Primary and Backup Protection Schemes Primary and backup protection schemes should be required for all lines and be capable of detecting all types of faults on the line. The primary scheme should provide high-speed, simultaneous tripping of all line terminals at speeds that will provide fault clearing times for system stability as defined in NERC Transmission Planning and Reliability Standards TPL-001 through TPL-004.

The following criteria should be used to determine if one or two high speed protection systems are needed on a line. While it is possible that the minimum protective relay system and redundancy requirements outlined below could change as NERC Planning and Reliability Standards evolve it will be the responsibility of each individual TO to assess the protection systems and make any modifications deemed necessary.

Line Applications: 765 / 500 kV At least two high speed pilot schemes using a dual battery design and dual direct transfer trip (DTT) using PLC and/or fiber are required. Fiber should be used on all new transmission lines using OPGW and PLC equipment for existing lines (Mode 1 coupling to all three phases). Where there is an underground fiber communication path OPGW is not preferred. PLC-based protection schemes using directional comparison blocking (DCB) require automatic checkback features to be installed to ensure the communication channel is working properly at all substations.

345 kV Dual high speed pilot schemes and one direct transfer trip (DTT) using PLC and/or fiber are required. Dual DTT is required if remote breaker failure protection cannot be provided with relay settings. Fiber should be used on all new transmission lines using OPGW and PLC equipment for existing lines. Where there is an underground fiber communication path OPGW is not preferred. Independent PLC communication paths may be required for proper protective relay coordination. PLC-based protection schemes using directional comparison blocking (DCB) require automatic checkback features to be installed to ensure the communication channel is working properly at all substations.

Below 300 kV A minimum of one high speed pilot scheme using PLC and/or fiber is suggested. Fiber should be used on all new transmission lines using OPGW and PLC equipment for existing lines. Where there is an underground fiber communication path OPGW is not preferred. Dual pilot schemes may be required for proper relay coordination. If dual high speed systems are needed, independent communication channels will be used. PLC-based protection schemes using directional comparison blocking (DCB) require automatic checkback features to be installed to ensure the communication channel is working properly at all substations.

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Transformer Applications: 765 / 500 kV Transformer protection for three (3) single phase banks should be designed considering a dual station battery design, with the protection divided into two systems. The first system should be an overall differential protection scheme. The second system should provide protection for other needs such as internal differential, highside and lowside lead differential, backup overcurrents, sudden pressure and loss of cooling protection. The two protection systems should be separated as much as is practicable. 345 kV - 100 kV The transformer protection should be divided into two systems, an overall differential protection scheme, and a second system providing protection for other needs such as internal differential, highside and lowside lead differential, backup overcurrents, sudden pressure and loss of cooling protection. Bus Applications: 765 / 500 kV Bus protection at this voltage level should be designed considering a dual station battery design. Low impedance bus differential protection should be considered. The protection should be divided into two systems with their own dedicated lockout relay. 345 / 230 kV Low impedance bus differential protection should be used with the protection divided into two systems with their own dedicated lockout relay. 200 kV and below Current summation (unrestrained differential) should be typically used in new stations at these voltage levels with the protection scheme divided into two systems with their own dedicated lockout relay. To improve reliability at these voltages, bus one-shot capabilities should be provided when a capacitor bank is installed on the bus and its protection is not accounted for in the bus differential scheme. If bus fault levels are greater than 20kA, then high impedance or low impedance protection solutions must be considered.

Substation Devices For substation devices, such as capacitor banks, Static VAR Compensator, reactors, appropriate protection systems should be incorporated with due consideration of redundancy and flexibility to facilitate system operations and maintenance.

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Phase Measurement Units (PMUs) PMUs, or Intelligent Electronic Devices (IEDs) capable of providing PMU measurements, should be installed in all new 230 kV and above substations.

SCADA and RTUs SCADA should be considered for all substations. The capability to retrieve fault records should also be considered.

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Scoping Requirements This section describes the Scoping Requirements to be used by the SPP when developing Conceptual Estimates and the TOs when developing Study Estimates for transmission facilities for the SPP footprint.

Conceptual Estimate Scope Requirements (Developed by SPP and provided to the TO) Transmission Line Projects

• Description of project

• Termination points of each transmission line (Point A to Point B)

• Voltage

• Estimated Line length

• Line Ampacity

• Need Date

Transmission Substation Projects • Description of project

• Voltage

• Need Date

• Transformer requirements

Study Estimate Scope Requirements (Developed by the TO and provided to SPP) The Study Estimate Scope document should include the Conceptual Estimate Scope requirements in addition to the information listed below.

Transmission Line Projects • Structures

o Structure types - specify lattice structures, poles (wood, steel, concrete, etc.)

o Number of storm structures, dead ends, running corners, tangents

o Foundation information

• Number of circuits

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• Conductor size, type and number/phase

• Type of terrain

• Switch requirements

• Legal requirements (e.g. CCN process)

• Geotechnical assumptions

• Special material requirements

• Preliminary line route (rough location when practical)

• Access road requirements

• Design criteria

o Weather loading

o Live line maintenance

o Unbalanced structural loads

• Distribution/Joint Use requirements

• Right-of-Way

o Right-of-Way acquisition

o Right-of-Way clearing requirements

o Right-of-Way width

• Permitting Concerns

o Traffic control requirements

o FAA Requirements

• Environmental Concerns

o Environmental Study Requirements

o Wetland Requirements/Mitigation

o Threatened and Endangered Species Mitigation

o Cultural/Historical Resource Requirements

Transmission Substation Projects • Preliminary one-line diagram

• All major equipment, including rehab of existing equipment to meet the SPP project scope, i.e. Transformers, Breakers, Control panels, Switches, CTs, PTs, CCVTs

• BIL ratings

• Contamination requirements

• Mobile substation requirements

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• Required substation property/fence expansions (indicating anticipated arrangement of proposed facilities and any resulting expansion needed)

• Control enclosure expansions (indicating anticipated panel layout and any resulting expansion needed)

• Fiber optic requirements

• Remote end requirements

• Metering requirements

• Reactive Compensation requirements

• Wetland/T&E/Community Approval/Unusual site prep requirements.

• SCADA requirements

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Memorandum 

To:  Strategic Planning Committee 

From:  SPC Task Force  

Date:  June 16, 2011 

Re:  Response to RSC Motions 

The Strategic Planning Committee (“SPC”) Task Force working in conjunction with the SPP staff (“Staff”) offers the following recommended policy decisions for consideration in response to the Regional State Committee (“RSC”) motions.  The information is arranged by topic ( i.e., 1. Design Best Practices and Performance Criteria; 2. Tracking/Estimates; 3. Estimates Outside a Bandwidth; and, 4. Assignments and Novations) rather than by RSC Motion.  

 1. Design Best Practices and Performance Criteria 

 1.1. Should SPP establish mandatory design best practices for regionally funded projects? 

 1.1.1. SPC recommends any consideration for design best practices be applied to all projects 

regardless of funding mechanism. 1.1.2. SPC recommends that design best practices be used to establish the framework by which 

new proposed projects will be estimated at the study stage.    1.1.3. SPC recommends the Transmission Owners achieve consensus on the development of 

region‐wide design best practices to be consolidated within a document managed by SPP.  The existing ad‐hoc group of transmission owners should continue their informal dialogue to establish design best practices and performance criteria focused on providing consistently developed estimates at the “study” stage.  The group should provide a status report in 3rd Quarter 2011 and finalize their work product by 4th Quarter 2011.  The establishment of such design best practices and performance criteria should address policy decisions such as: 

1.1.3.1. Design best practices to be used to establish similar design objectives no matter who builds it. 

1.1.3.2. Objective to get estimates that do not change outside a bandwidth over the design and construction phases of a project. 

1.1.3.3. Performance criteria needed to concisely describe the intended scope of a project. 

1.1.3.4. Scope details needed by a Transmission Owner to provide a level of estimate that has the appropriate bandwidth. 

1.1.4. SPC recommends adopting a set of performance criteria.  The performance criteria may include: 

1.1.4.1. Normal and emergency conductor or equipment ampacity for a given project voltage 

1.1.4.2. Normal and emergency terminal equipment ampacities 

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1.1.4.3. Locally relevant wind/ice loadings 1.1.4.4. Appropriate interrupting fault current levels 1.1.4.5. Substation bus configurations 

1.1.5. SPC recommends that performance criteria be utilized to evaluate project variances following the issuance of NTC’s and in subsequent phases. 

1.1.6.   

1.2. How often should design best practices be reviewed and updated?  1.2.1. SPC recommends these design best practices be reviewed at least every two years by a 

stakeholder working group assigned by the MOPC.  

1.3. Who should be responsible for enforcing design best practices and performance criteria?  1.3.1. SPC recommends the Notification to Construct (“NTC”) direct building the project in 

conformance with the design best practices and performance criteria. 1.3.2. SPC recommends the formation of a permanent working group under the MOPC, the 

Project Cost Working Group (“PCWG”).  SPC recommends that after an NTC is issued the PCWG be responsible for reviewing conformance with the design best practices and performance criteria for projects outside the bandwidth and reporting deviations to the MOPC, RSC, and BOD. 

  2. Tracking/Estimates  

2.1. Should SPP implement standardized cost estimating methodologies for projects?  

2.1.1. SPC recommends Transmission Owners develop consistent cost estimating principles relative to design best practices. 

2.1.2. SPC recommends the development or selection, and implementation of a Standardized Cost Estimating Reporting Template  (SCERT) to be utilized for reporting cost estimates to SPP. 

2.1.3. SPC recommends that consideration be given to the amount of project cost variance within which a project will remain cost effective.  

2.2. How should costs associated with providing cost estimates on projects prior to issuance of an NTC be recovered by a TO?  2.2.1. SPC recommends this issue be further discussed through the stakeholder process. 

  2.3. What level of accuracy is expected for cost estimates for projects? 

 2.3.1. The Project Cost Task Force (PCTF) of the MOPC should define what needs to be included 

at each level of estimate (i.e., everything that the TO needs to provide to SPP and everything that SPP is to provide to each TO in order to develop consistent estimates).   

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SPC recommends a tiered approach to cost estimating that utilizes progressively more precise cost estimates throughout the planning and construction cycles.  Estimates should have the levels of accuracy relative to the variance from final project costs consistent with the Project Cost Task Force recommendation.    

2.4. What review process should be incorporated into each cost estimate level identified above?  2.4.1. SPC recommends a cost estimating reporting tool (could be SCERT) be used in reporting 

all cost estimates provided to SPP. 2.4.2. SPC recommends study, NPE, design, and construction phase cost estimates be reviewed 

by Staff for adherence to design best practices and performance criteria as established by Transmission Owners.  Staff will address any deviations from design best practices and performance criteria with the Transmission Owner submitting the cost estimate and if outside the established bandwidths during the process, the PCWG will review as noted below in Section 3(Estimates Outside a Bandwidth).  

 2.5. Should SPP’s roles and responsibilities be increased in the project tracking process? 

 2.5.1. SPC recommends that SPP’s project tracking process be enhanced to require all projects 

with an approved NTC Project Estimate (“NPE”) or latest Estimate at Completion (“EAC”) in excess of $20 Million be reported quarterly unless it exceeds the bandwidth in which case monthly reporting is required; all other projects will be required to be updated quarterly. 

2.5.2. SPC recommends the submittal of cost estimate data in a consistent format using the SCERT. 

2.5.3. SPC recommends SPP submit a monthly report of all project variances outside an established project variance bandwidth (see 3.1.1. below) to the PCWG. 

 2.6. Should Designated Transmission Owners (“DTOs”) be required to submit additional cost 

tracking information to SPP and utilize consistent methodologies for managing the desconstruction costs of approved transmission projects? 

ign and 

 2.6.1. SPC recommends the information being submitted for use in cost tracking of projects 

include: 2.6.1.1. Actual expenditures (spent to date) 2.6.1.2. Estimate at Completion 2.6.1.3. Projected in‐service date 2.6.1.4. Indirect costs and financing costs 

 2.6.2. SPC recommends all DTOs use the SCERT in reporting the estimated and actual costs of 

each project.  3. Estimates Outside a Bandwidth  

3.1. What is the allowable approved project cost deviation before a project should be reviewed? 

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 3.1.1. SPC recommends DTOs provide a report to Staff and the PCWG detailing the cost 

variances on any project that deviates or is expected to deviate +/‐10% from its NPE. 3.1.2. SPC recommends any project cost that deviates or is expected to deviate +/‐ 20% from its 

NPE be acted on by the PCWG based on 3.2.1 below with a report and recommended actions to be submitted to the MOPC, RSC, and BOD. 

 3.2. What options should be available to deal with projects whose cost estimate changes outside of 

the bandwidth approved in 3.1.2 above?  

3.2.1. SPC recommends the PCWG provide recommendations to the MOPC,RSC, and BOD that may include any of the following: 

3.2.1.1. Accept the cost deviation as reasonable and acceptable and reset the baseline used to evaluate future cost deviations. 

3.2.1.2. Identify all or a portion of costs related to the variance and recommend changes to the NTC that would reduce the cost or avoid issues that may be causing the increase. 

3.2.1.3. Suspend all future expenditures on the project while SPP restudies the project to determine appropriate changes to the NTC or possible withdrawal of the NTC.   

 If the PCWG recommends a restudy and/or changes or revocation of the NTC, the recommendation to the MOPC would then follow SPP’s existing processes for approval to the BOD.  The BOD will make the final determination as to whether to restudy and/or change or revoke the NTC. 

3.2.2. SPC recommends: 3.2.2.1. Assessing whether design best practices and/or performance criteria are being 

followed are components of judging whether project cost variances are reasonable and appropriate. 

3.2.2.2. Consideration be given to excluding from regional funding project costs that are a result of the TO not adhering to performance criteria, and thereby included in the local pricing zone. Any such consideration should be referred to the MOPC, RSC and Board. 

 3.3. Should certain criteria be met in order for an approved project to be restudied if recommended 

by the PCWG in 3.2.1.3?  

3.3.1. SPC does not recommend specific criteria be developed at this time.  SPC recommends the BOD assess whether a restudy is warranted on a case‐by‐case basis while considering the time and cost for Staff to perform the restudy.  Accordingly, no automatic triggers for restudy are necessary. 

 4. Assignment and Novations  

4.1. Should increased transparency apply to both the novation and assignment process?  

4.1.1. SPC recommends yes. 

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 4.2. What increased role should be assumed by SPP in the novation and assignment process? 

 4.2.1. SPC recommends that SPP facilitate increased transparency for both the novation and 

assignment processes.  4.3. What is the distinction between an “assignment’ and a “novation”? 

 4.3.1. An “assignment” is the transfer of a DTO’s legal right to build a project pursuant to an 

NTC issued by SPP.  Although the DTO has transferred its legal right to build a project pursuant to an assignment, the original DTO is still under a legal obligation to ensure that the project is built. 

4.3.2. A “novation” is the release of the original DTO’s obligation to ensure that a project is built.   After the DTO’s Assignment of the right to build and the approval and execution of a novation, the new TO will have both the right and obligation to build the project.  If the party receiving both an assignment and a novation fails to complete the project, the original DTO is not obligated to complete the project. 

 4.4. Should the definition of assignment and novation be part of the SPP Tariff? 

 

 4.4.1. SPC recommends yes, but the definitions noted above in section 4.3 are not intended to 

be “tariff” language; they are intended as guidance related to the development of the SPC position.  Further specific definitions should be developed by the RTWG. 

 4.5. Should the Board approve Assignments?  

4.5.1. SPC recommends yes, the Board should approve Assignments, such approval conditioned only on the four specific criteria already identified in the SPP Tariff.   Those criteria are: 

4.5.1.1. The Entity’s having obtained all state regulatory authority necessary to construct, own and operate transmission facilities within the state(s) where the project is located;  

4.5.1.2. The Entity’s meeting the creditworthiness requirements of the Transmission Provider; 

4.5.1.3. The Entity’s having signed, or capability and willingness to sign, the SPP Membership Agreement as a Transmission Owner upon the selection of its proposal to construct and own the project; and, 

4.5.1.4. The Entity’s meeting such other technical, financial and managerial qualifications as are specified in the Transmission Provider’s business practices.  

4.5.2. SPC recommends approval of Assignments for all designated entities including Assignments between affiliates (subject to the same criteria noted above in 4.5.1).  The review required for existing TOs or affiliates would be defined in a business practice.  

4.6. For transparency purposes, what other information should SPP provide to stakeholdersregarding assignments? 

 

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Page 6

 

4.6.1. SPC recommends that SPP provide information regarding proposed assignments and supporting analysis to the RSC, MOPC, and Members Committee for review to increase transparency. This information will include: 

4.6.1.1. The identification of the project proposed to be assigned  4.6.1.2. The identification of the Transmission Owner making the assignment  4.6.1.3. The identification of the entity receiving the assignment  4.6.1.4. The identification and status of pertinent matters before FERC or state 

commissions related to the project including the assignment (this shall include the status of any certification proceeding, approvals, etc.) 

4.6.1.5. A comparison of the DTO and proposed recipient of Assignment relating to each (assuming that party constructs the project) as applicable: 

4.6.1.5.1. Actual or Projected debt/equity ratios 4.6.1.5.2. Actual or Projected cost of capital 4.6.1.5.3. Actual or Projected return on equity or applicable measure 4.6.1.5.4. Actual  or  Proposed  type  and  amount  of  construction  financing  costs,  i.e. 

Interest rate, AFUDC or CWIP 4.6.1.5.5. S&P and Moody’s credit ratings 4.6.1.5.6. Estimated Net Plant Carrying Charge (NPCC) or Annual Transmission 

Revenue Requirement (ATRR) for the life of the project after it is placed in‐service 

4.6.1.5.7. An explanation describing the difference in the ATRR  4.6.1.6. A comparative analysis as to whether assignment changes the ROE, weighted cost 

of capital, and overall costs for the project,  whether any performance guarantees between the parties exists and whether any consideration between the parties is included in the ATRR 

4.6.1.7. Whether the Assigning Party will own, operate and maintain the line. 4.6.1.8. Detail on what process was used in selecting the potential DTO 

 4.7. What information should SPP provide to stakeholders regarding novations? 

 4.7.1. If not already provided, the information provided in 4.6.1 above, as well as the following 

information: 4.7.1.1. The identification and status of pertinent matters before FERC related to the 

novation of the project(s)  

4.8. Should the Board approve Novations? 

4.8.1. SPC recommends yes, the Board should approve Novations, such approval conditioned upon the information required in section 4.5.1 above. 

 4.9. What other tariff modifications should be made regarding Assignments and Novations? 

   4.9.1. SPC recommends that the RTWG incorporate Novation and Assignment approvals, as 

described herein, into the SPP Tariff.   

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Southwest Power Pool, Inc. STAFF INITIAL ASSESSMENT OF IMPACTS OF PROPOSED EPA REGULATIONS

Recommendations to the Strategic Planning Committee July 14, 2011

SPP Staff Les Dillahunty Jay Caspary Tim Miller Joshua Phillips John Hyatt Susan Polk

Background During its May 5-6, 2011 meeting, the Strategic Planning Committee directed SPP staff to conduct an independent study to assess the reliability impacts of a group of regulations proposed by the Environmental protection Agency (EPA) that will potentially impact generation in the SPP footprint. The focus of staff’s assessment was the Clean Water Act -Section 316(b), Clean Air Act – HAP Rule, Clean Air Transport Rule, and the Coal Combustion Residuals Rule. Completion of this initial assessment needed to be completed in June to provide time for consideration of any SPP comments regarding the potential reliability impacts of the EPA regulations. Analysis To ensure completion of this assessment within the timeframe required, staff performed an abbreviated analysis of potential reliability impacts. In addition to researching and reviewing several representative reports, staff engaged representatives of AEP, CUS, KCP&L, OPPD, SPS and Westar to discuss the specific impacts that these regulations may have on their generators. These results were extrapolated across the generator fleet within the SPP footprint to provide an initial assessment. Staff performed a reliability assessment based on existing SPP capacity margin requirements as a metric. In addition, staff completed estimates of the expected installed costs of environmental upgrades on the existing fleet for the scenarios outlined in the reliability assessment.

Findings: The attached report documents the assessment’s approach, findings and recommendations based on a Business As Usual, as well as 4 potential futures, e.g., Best Case, Low Estimate, High Estimate and Worst Case. As expected, the range of potential reliability impacts and installed costs for environmental equipment retrofits for compliance are wide, with some scenarios that are concerning and therefore warrant that comments be filled by SPP to the EPA.

Recommendation:

SPC review and provide direction to SPP Staff to finalize this assessment which concludes with the following recommendations that need to be forwarded to the EPA prior to their July 19 comment deadline:

“While the focus of staff’s initial assessment has been the coal and gas units and select EPA rules, other pending requirements – CO2 for example – could have major impacts to future resource plans, system reliability, and economics. It is important to note this initial assessment did not consider impacts of the RICE regulations may have on the potential loss of small units which smaller municipalities have relied upon. Elimination of those units could create local congestion challenges and require both transmission expansion and local programs to keep the lights on.

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SPP is concerned that the abbreviated - rushed timeline for compliance with the proposed rules, should they be approved, will most likely be more aggressive than what can be achieved by the industry. Should this be the case it may adversely impact grid reliability due to the sudden required retirements and outages of units. SPP encourages the EPA to work with generation owners to monitor equipment installation to ensure it is done in a timely, safe, reliable and cost effective manner without an arbitrary deadline. Compliance plans developed in a collaborative manner may lessen the negative impact and/or prevent the unavailability of labor, parts, and other resources that may result from an arbitrary deadline. Such an approach would also ease concerns over grid instability caused by mass outages on generators to install the required equipment. SPP recommends that the EPA work to provide a gradual compliance schedule that allows the industry time to meet the requirements in an economical, safe and reliable manner. Working with the industry to institute these changes will also allow for a more gradual integration of the costs of compliance that could significantly mitigate sudden increases in consumer electricity prices.”

Action Requested: Approve recommendation

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R e v i e w o f t h e P o t e n t i a l R e l i a b i l i t y I m p a c t s o f P r o p o s e d

E P A R e g u l a t i o n s I m p a c t i n g G e n e r a t i o n i n t h e S P P F o o t p r i n t

July 7, 2011

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 Impacts of Proposed EPA Regulations on SPP 1

Table of Contents 

Introduction ..................................................................................................................................................2

Clean Water Act – Section 316(b) ...................................................................................................2

Clean Air Act – HAP Rule...............................................................................................................2

Clean Air Transport Rule .................................................................................................................3

Coal Combustion Residuals Rule ....................................................................................................3

Approach ......................................................................................................................................................3

Reliability Outlook .......................................................................................................................................5

Cost of Environmental Controls .................................................................................................................7

SPP’s Recommendation to the EPA ...........................................................................................................8

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 Impacts of Proposed EPA Regulations on SPP 2

Introduction 

During its May 5-6, 2011 meeting, the Strategic Planning Committee directed SPP staff to conduct an independent study to assess the reliability impacts of a group of regulations proposed by the Environmental Protection Agency (EPA) that will potentially impact generation in the SPP footprint. As in a similar May 2011 ERCOT study, the assessment’s scope is limited to the regulations identified below. Confining the impacts to a specific or proposed regulation at a specific point in time, however, is challenging.1  

Clean Water Act – Section 316(b)  Section 316(b) of The Clean Water Act is intended to limit entrainment and impingement that occurs during the cooling process at electrical generation facilities. The proposed rule2 affects existing power plants that generate electricity and withdraw at least 2 million gallons per day of cooling water, used to dissipate waste heat. The EPA estimates that approximately 670 power plants will be affected, although some facilities may already employ technologies that comply with the impingement requirements of the proposed rule.3 Comments are due on or before July 19, 2011, and a final rule is expected in July 2012 with commensurate compliance beginning in 8 years.

Clean Air Act – HAP Rule  The EPA-proposed mercury and air toxics standards consist of national emissions standards for hazardous air pollutants (HAP) from coal- and oil-fired electric generating units under section 112(d) of the Clean Air Act and revised new source performance standards for fossil fuel-fired units under section 111(b) of the Clean Air Act.4 This set of regulations is applicable to coal- and oil-fired electric generating units, and is expected to decrease by 91% the level of mercury currently being released by these facilities. Comments are due on or before August 4, 2011, and a final rule is expected in November 2011. Compliance is mandatory within three years, although an additional year may be granted. 1 Although notable, staff’s assessment does not address the national emission standards for hazardous air pollutants for reciprocating internal combustion engines (RICE), which were the subject of EPA Docket ID No. EPA-HQ-OAR-2008-0708. The final RICE rule was made effective May 9, 2011. 2 National Pollutant Discharge Elimination System – Cooling Water Intake Structures at Existing Facilities and Phase I Facilities, 76 Fed. Reg. 22174 (proposed April 20, 2011) (to be codified at 40 C.F.R. pts. 122 and 125). 3 Answers to Common Questions about the Proposed Rule, March 28, 2011, accessed http://water.epa.gov/lawsregs/lawsguidance/cwa/316b/upload/qa_proposed.pdf, July 1, 2011. 4 National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units, 76 Fed. Reg. 24976 (proposed May 3, 2011) (to be codified at 40 C.F.R. pts. 60 and 63).

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 Impacts of Proposed EPA Regulations on SPP 3

Clean Air Transport Rule  The Clean Air Transport Rule (CATR)5 is intended to reduce air pollution, specifically the transportation of ozone and fine particle matter across states. Originally proposed on July 6, 2010 as a replacement to the Clean Air Interstate Rule, the CATR contains two phases that would reduce nitrogen oxide (NOx) and sulfur dioxide (SO2). The rule applies to 31 eastern states and the District of Columbia. Compliance with Phase I begins in 2012. This rule is applicable to facilities with more than 25 megawatts (MW) of capacity and would apply to the 67% of the generation units in the SPP footprint.

Coal Combustion Residuals Rule The Coal Combustion Residuals Rule6 contains several alternatives for dealing with waste ash produced during the generation of electricity. Both proposals by the EPA use the Resource Conservation and Recovery Act to manage disposal of coal ash in a more stable state than current methods of impoundment. The first two methods involve federal permitting and monitoring requirements. The third allows states to interpret national permitting guidelines. According to the EPA’s Regulatory Impact Analysis, over the next 50 years the first two methods could result in higher costs than the third method.

Approach 

It is unclear how these regulations will affect the industry. The ITP10 Scenario 2 regarding EPA Rules retires most coal units less than 200MW which aggregate to a total of 2.6 gigawatts (GW) of capacity within SPP. Earlier reports provided results ranging from 1 to 5 GW of retired capacity in the SPP footprint. Such scenarios provide a spectrum from potentially minor to moderate reliability issues in the SPP footprint. To ensure completion of this assessment for consideration within the timeframe required, staff performed an abbreviated analysis of potential reliability impacts and utilized a number of representative reports in framing its analysis. A list of these reports is set forth below:

• Potential Coal Plant Retirements Under Emerging Environmental Regulations, The Brattle Group, December 8, 2010;

• Potential Impacts of Environmental Regulation on the U.S. Generation Fleet, Edison Electric Institute, prepared by ICF International, January 2011;

• Review of the Potential Impacts of Proposed Environmental Regulations on the ERCOT System, Electric Reliability Council of Texas, May 11, 2011 (ERCOT Report);

5 Federal Implementation Plans to Reduce Interstate Transport of File Particulate Matter and Ozone, 75 Fed. Reg. 45210 (proposed Aug. 2, 2010) (to be codified at 40 C.F.R. pts. 51, 52, 72, 78, and 97). 6 Hazardous and Solid Waste Management System; Identification and Listing of Special Wastes; Disposal of Coal Combustion Residuals from Electric Utilities, 75 Fed. Reg. 35128 (proposed June 21, 2010) (to be codified at 40 C.F.R. pts. 257, 261, 264, 265, 268, 271, and 302).

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 Impacts of Proposed EPA Regulations on SPP 4

• U.S. Utilities: Coal-Fired Generation Is Squeezed in the Vice of EPA Regulation; Who Wins and Who Loses?, Bernstein Research, October 2010; and

• 2010 Special Reliability Scenario Assessment: Resource Adequacy Impacts of Potential U.S. Environmental Regulations, North American Electric Reliability Corporation, October 2010.

Staff also engaged representatives of American Electric Power (AEP), City Utilities of Springfield (CUS), Kansas City Power and Light Company (KCP&L), the Omaha Public Power District (OPPD), Southwestern Public Service Company (SPS), and Westar Energy, Inc. (Westar) to discuss the specific impacts these regulations may have on their respective generators. In the discussions a survey was provided. The survey requested information, by unit, of the plans held by the generation owners. From the survey SPP received information about unit retirement dates, derate amounts, outage timeframes, and expected compliance dates. These surveyed generation owners account for 68% of the total coal and natural gas (NG) capacity in the SPP RTO footprint. When appropriate, the collected data was considered generally representative and extrapolated to represent all coal and gas generators in the footprint. Specific calculations where this extrapolation method was used are noted below. Chart 1 compares the capacity captured in these discussions with that of the entire footprint.

Chart 1: 68% of SPP Coal and NG capacity was captured in discussions with generation owners

 Staff incorporated into its analysis the expected unit retirements and proposed retrofits of these generation sources and created four scenarios that describe the possible reliability and economic impacts. The first scenario, “Best Case” used only information provided by the surveyed generation owners. No extrapolation or estimation was applied in this scenario regarding the impacted capacity. To account for capacity potentially impacted by these regulations but not surveyed, staff calculated the total unit retirements provided by survey respondents compared to the total number of units owned. A percentage of 10% was found by extrapolating the total-to-retired or retrofit units that would be impacted. This scenario is referenced as the “Low Estimate” case. To account for the spectrum of perspectives amongst those surveyed, further extrapolation was used solely with information from those surveyed with the highest amount of retirements and retrofits, providing a 25% scenario. This scenario is referenced as the “High Estimate” case. In each of case, 50% of the units were retired and 50% of the units were retrofitted. Surveyed generation owners are actively pursuing many detailed studies regarding the practicality and profitability of retrofitting or retiring generating units. To account for the uncertainty surrounding this capacity, a final scenario “Worst Case”, was developed. It retires any unit currently under study and in addition to the units retired in the High Estimate case.

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 Impacts of Proposed EPA Regulations on SPP 5

Staff considered two years in its analysis: 2015, when the HAP regulation goes into effect, and 2021, when the Clean Water Act – Section 316(b) regulation is to be in place. These two years provides important bookends that can be used to infer the impacts to the footprint in the intervening years. Information about future generation capacity and total load was acquired using information from the U.S. Energy Information Administration and the surveyed generation owners. To estimate the potential cost impact of the proposed regulations on SPP generation owners, SPP prepared projections using dollar per kilowatt estimates from the ERCOT Report for retrofits of environmental control equipment. These expenses would be incurred if generation owners, through their ongoing analysis, determine that control equipment will be installed or upgraded to meet the regulations mitigating most of the possible retirements in the Worst Case scenario.

Reliability Outlook 

The capacity margins for the SPP RTO footprint in were calculated to determine if generation supply will be available to meet the forecasted load and provide the reliability support required in SPP’s governing documents. The capacity margin plays an important role in maintaining reliability across the grid due to unexpected interruptions to generation equipment occur, increases in demand due to extreme weather, etc. SPP calculates the capacity margin by subtracting the total load from the total generation capacity, including the net of the firm import and export obligations, divided by the total capacity. SPP Criteria require a minimum capacity margin of 12%. However, it may not prove reasonable to assume that today’s requirement would continue to be adequate for SPP in the scenarios outlined above. Many small units could be retired while existing, larger units are being retrofitted with equipment that has an unknown impact on the performance and availability of retrofitted generators. The data that SPP used in its evaluation of the scenarios is presented in Tables 1 and 2. In the Best Case roughly 1 GW of capacity was identified by SPP stakeholders as planned for retirement, with 1 GW to be placed into outage for compliance upgrades. This amount is below the volume noted in the reports cited in the Approach section The Low Estimate case widens the scope of retirements beyond those surveyed to all SPP generation In this case, again, there is a limited impact with 3 GW of capacity taken from service. The High Estimate case utilizes a broader application of the extrapolated information. In this scenario, SPP is forecasted to fall short of the minimum required capacity margin. The High Estimate case also demonstrates what may happen due to the tight timeframe around the unit upgrades. If units currently undergoing detailed individual assessments by the utilities with regard to their assessment and determination of the action(s) are retired SPP is further negatively impacted by the regulations and may be unable to maintain system security. A Business As Usual (BAU) case is provided for reference.

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 Impacts of Proposed EPA Regulations on SPP 6

Table 1:  2015 Reliability Outlook 

BAU Best Case Low Estimate High Estimate Worst Case

Outages - 1 2 3 7

Retirements (GW) - 1 1 3 3

Total Capacity (GW) 69 66 65 63 59

Capacity Margin (%) 19% 15% 15% 11% 5%

Capacity Margin (GW) 13 10 10 7 3

Shortfall (GW) - - - 1 5

Table 2:  2021 Reliability Outlook 

BAU Best Case Low Estimate High Estimate Worst Case

Outages - - - - -

Retirements (GW) - 1 2 3 7

Total Capacity (GW) 72  70  70  69  65

Capacity Margin (%) 17% 15% 14% 13% 8%

Capacity Margin (GW) 12 11 10 9 5

Shortfall(GW) - - - - 3

These evaluations were conducted for the years 2015 and 2021 and included multi-year outages necessary for the installation of control equipment, facility retirements, anticipated generation expansions and peak load levels. The expected capacity contribution of wind generation toward summer peak load requirements is relatively minor and has not been included. A summation of the data is provided in Chart 2. To provide a view of graph of the forecasted capacity margins within SPP for the BAU and scenarios over the next several years, Chart 2 is provided. The chart shows the impacts within SPP if the regulations force 7 GW currently under economic evaluation and compliance review into retirement.

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 Impacts of Proposed EPA Regulations on SPP 7

 Chart 2: Forecasted Capacity Margins 

These results are indicative of the range of possible outcomes, but they may not necessarily reflect most pessimistic conditions given the uncertainty which surrounds any long-term projections, including future environmental regulations. In the ”Worst Case” scenario, SPP expects system reliability within at least five load pockets to be adversely impacted absent aggressive transmission expansion projects, demand response or generation expansion projects.

Cost of Environmental Controls 

The assessment broadly evaluated a range of costs incurred by generation owners due to potential environmental control installations. These expenses would be incurred if the generation owners determine that units currently under study will be retrofitted less the expected retirements. In this instance, SPP is evaluating the cost to retrofit the 7 GW planned to be retired in only the “Worst Case” scenario. Table 3 outlines the associated equipment and costs. Approximately $8.5 billion was identified by the evaluation for installation of Bag Houses (BH), Flue Gas Desulfurization equipment (FGD), and Selective Catalytic Reactors (SCR). This case assumes that units with similar characteristics to those identified as needing control equipment will be retrofitted. While these estimates regarding installed costs for new environmental equipment to make coal units comply with expected EPA rules are significant, they represent only a portion of the total cost impacts which will be realized on consumer bills. The cost impacts associated with environmental upgrades at existing plants to comply with the proposed rules is comparable to the projected transmission expansion investment which has been approved within the SPP footprint for the period 2011 through 2017. Unlike cost recovery for transmission expansion, which has its costs allocated across the SPP footprint to a large extent, the cost allocation for EPA compliance investments will be much more localized and varied across SPP zones.

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 Impacts of Proposed EPA Regulations on SPP 8

 Table 3: 2015 Retrofit Costs 

$/kW  Units Impacted

Capacity Impacted

(GW)

Total Cost ($B)

BH  197 34 8 1.5

New FGD   573 39 10 5.5

FGD pgrade U 450 -  - -

$CR7  250 30 6 1.5

Total  - 42 12 8.5

These evaluations were conducted for 2015 and are based upon cost estimates provided in the ERCOT Report, supplemented by the Edison Electric Institute for SCRs, with equipment installations provided by the surveyed generation owners. As demonstrated in Table 3, the projected cost to retrofit, in lieu of retirement, in the High Estimate case would be approximately $8.5 billion. The rate impact and justification cases involved in acquiring such funding from state utility commissions may impact the capability of the utilities to secure funding. Also, the impact on consumer bills should not be understated.

SPP’s Recommendation to the EPA 

While the focus of staff’s initial assessment has been the coal and gas units and select EPA rules, other pending requirements – CO2 for example – could have major impacts to future resource plans, system reliability, and economics. It is important to note this initial assessment did not consider impacts of the RICE regulations may have on the potential loss of small units which smaller municipalities have relied upon. Elimination of those units could create local congestion challenges and require both transmission expansion and local programs to keep the lights on. SPP is concerned that the abbreviated - rushed timeline for compliance with the proposed rules, should they be approved, will most likely be more aggressive than what can be achieved by the industry. Should this be the case it may adversely impact grid reliability due to the sudden required retirements and outages of units. SPP encourages the EPA to work with generation owners to monitor equipment installation to ensure it is done in a timely, safe, reliable and cost effective manner without an arbitrary deadline. Compliance plans developed in a collaborative manner may

7 Selective Catalytic Reactor (SCR) cost based on the assumptions from the Edison Electric Institute (EEI) report estimating costs to be between $200/kw and $400/kw, and further discussion with SPP generation owners.

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 Impacts of Proposed EPA Regulations on SPP 9

lessen the negative impact and/or prevent the unavailability of labor, parts, and other resources that may result from an arbitrary deadline. Such an approach would also ease concerns over grid instability caused by mass outages on generators to install the required equipment. SPP recommends that the EPA work to provide a gradual compliance schedule that allows the industry time to meet the requirements in an economical, safe and reliable manner. Working with the industry to institute these changes will also allow for a more gradual integration of the costs of compliance that could significantly mitigate sudden increases in consumer electricity prices.

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VIA ELECTRONIC MAIL AND FIRST CLASS MAIL July __, 2011 Water Docket U.S. Environmental Protection Agency Mail Code: 4203M 1200 Pennsylvania Ave., NW Washington, DC 20460 EPA Docket Center U.S. Environmental Protection Agency Mail Code: 2822T 1200 Pennsylvania Ave., NW Washington, DC 20460 Re: National Pollutant Discharge Elimination System – Cooling Water Intake Structures at Existing

Facilities and Phase I Facilities; Docket ID No. EPA-HQ-OW-2008-0667

National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units; Docket ID Nos. EPA-HQ-OAR-2009-0234 and EPA-HQ-OAR-2011-0044

Dear Sir or Madam: Southwest Power Pool, Inc. (SPP) appreciates the opportunity to comment and respectfully submits the attached report entitled, “Review of the Potential Reliability Impacts of Proposed EPA Regulations Impacting Generation in the SPP Footprint”, dated July 2011, in response to the U.S. Environmental Protection Agency’s (EPA) proposed rules issued in the above-captioned dockets. SPP is an Arkansas non-profit corporation with its principal place of business at 415 N. McKinley, Suite 140, Little Rock, Arkansas 72205. Currently, SPP has 64 members serving approximately 15 million customers in a 370,000 square mile service territory covering all or part of the following states: Arkansas, Missouri, Kansas, Oklahoma, Louisiana, Mississippi, Nebraska, New Mexico and Texas. SPP’s members include investor-owned utilities, municipals, cooperatives, state authorities, independent power producers, power marketers, independent transmission companies, as well as a contract participant. SPP is a Federal Energy Regulatory Commission approved Regional Transmission Organization (RTO) and administers open-access transmission services across the SPP region under the terms of SPP’s Open Access Transmission Tariff. As an RTO, SPP plans for and functionally controls the transmission infrastructure committed to it and administers a competitive real-time wholesale electricity marketplace.

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While the focus of SPP’s initial assessment has been the coal and gas units and select EPA rules, other pending requirements – CO2 for example – could have major impacts to future resource plans, system reliability, and economics. It is important to note this initial assessment did not consider impacts the reciprocating internal combustion engines (RICE) regulations may have on the potential loss of small units which smaller municipalities have relied upon. Elimination of those units could create local congestion challenges and require both transmission expansion and local programs to keep the lights on. SPP is concerned that the abbreviated - rushed timeline for compliance with the proposed rules, should they be approved, will most likely be more aggressive than what can be achieved by the industry. Should this be the case it may adversely impact grid reliability due to the sudden required retirements and outages of units. SPP encourages the EPA to work with generation owners to monitor equipment installation to ensure it is done in a timely, safe, reliable and cost effective manner without an arbitrary deadline. Compliance plans developed in a collaborative manner may lessen the negative impact and/or prevent the unavailability of labor, parts, and other resources that may result from an arbitrary deadline. Such an approach would also ease concerns over grid instability caused by mass outages on generators to install the required equipment. SPP would recommend that the EPA work to provide a gradual compliance schedule that allows the industry time to meet the proposed requirements in an economical, safe and reliable manner. Working with the industry to institute these changes will allow for a more gradual integration of the costs of compliance that could significantly mitigate sudden increases in consumer electricity prices. Please do not hesitate to contact me should have questions or would like to request additional information. Respectfully submitted, [Click here and type name] Title Phone • Fax: (501) 664-9553 • Email address cc: [Insert recipients as desired]

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July 2011  Initiative 

Milestones /  Recent Activity 

Current Status 

Build

 a Rob

ust T

ransmission

 System

 

Implement Priority Projects  

• Implementing enhanced Project Management/Tracking processes • Developing/implementing increased transparency and accountability 

mechanisms 

 

Develop/Implement Integrated Transmission Planning Processes 

• ITP10 proceeds apace; scenario assumptions were refreshed   

Regional Cost Recovery  • Populated Joint Unintended Consequences task force of MOPC and RSC   

Inter‐Regional Optimization  • Identifying possible joint projects • Seams Steering Committee • Fostering cooperative & joint inter‐regional planning 

 

Operational Optimization  • Efforts are continuing with members to enhance policies, tools & practices to optimize use of existing systems, specifically related to dynamic line ratings 

 

Develop

 Efficient  

Market P

rocesses 

Implement Day Ahead Market with Transmission Congestion Rights 

• Authorization to proceed received • Created internal market leadership focused on successful 

design/construction/implementation phases for the Integrated Marketplace • Leveraging PJM and ERCOT experience • Engaged stakeholders through the CWG • Engaged Vendors • Market Participant Kickoff • Performed internal resource target gap analysis • Developed communication Plan 

          

 

Implement Reliability Unit Commitment Process

Incorporate Operating Reserves into Real Time Balancing and Day Ahead Markets 

Implement Consolidated Balancing Authority

Demand Response Integration 

Manage Implementation 

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July 2011  Initiative 

Milestones /  Recent Activity 

Current Status 

Create M

embe

r Value

 

Reliability Excellence  • Reliability Standards department formed: enhanced leadership and coordination 

• Organizational realignment of compliance and combination of CIP • Working to identify process improvements in standards development • Identified department goals • Developing “leave‐behind” talking points for NERC Leadership on 

improvement objectives 

 

Benchmarking and Measurement • Engineering is evaluating “off‐the‐shelf” benchmarking tools related to transmission project estimating 

 

Enhance Market Monitoring Tools • Though MMU now has access outage data, the quality of data is poor; outage scheduling data from the CBA project is needed.  Outage scheduler project delayed but still on track to provide MMU necessary data before year‐end 

 

Continuous Process Improvement • Multi‐year implementation plan endorsed • Tracking delayed to 2Q 2011 • PRPC ranking criteria revision (ROI, measurement criteria) • Enhanced Business Unit strategic planning  and linkage to budget  & 

performance measurement is implemented • Accountability processes implemented (Performance appraisal linkage 

performance objectives 

 

Strategic Membership Expansion and Maintenance 

• Entergy outreach continuing • OPPD outreach continuing 

 

Communication and Education  • Quarterly reviews and assignments • Corporate‐wide advocacy process under development 

 

 

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FFTF White Paper Recommendations Status Report to the SPC July, 2011

SPP staff provides the following updates for the approved tasks from the FFTF White Paper for its July 2011 report to the SPC:

1. SPP will seek and support opportunities to emphasize the importance of rightsizing in the transmission planning process. That support will be provided in a number of forums; i.e. support to Members and stakeholders, engagement with stakeholder and industry groups, articles

In the 2nd quarter of 2011, SPP staff continued its outreach and participated in several forums to educate stakeholders and policy makers on the aging of existing backbone EHV facilities in the US and the need to capitalize on existing ROWs to rightsize key facilities in critical corridors as long range plans focus on needs in the next 10-20 year planning horizon. Every facility that gets replaced in kind has the potential to perpetuate the existing patchwork quilt of a grid for another 50 years. Key forums included the NARUC/NCSL workshop sponsored by DOE’s NREL, as well as a WIRES Capitol Hill briefing. SPP staff has provided some leadership at EPRI to initiate the development of a whitepaper to discuss the merits of hybrid AC and DC networks to improve transmission efficiency as part of P172. SPP Customers have requested 52 Firm Transmission Service Requests amounting to 7,149 MW of wind exports from SPP to SERC, with firm / contingent firm service on adjacent systems for many requests. Most of these requests are under study in SPP, with a few granted to date. It’s important to note that SPP is reviewing it pricing of through and out rates which could help potential rightsizing of select facilities in key corridors due to the lumpy nature of transmission. SPP and the industry awaits FERC RM10-23 which is expected this month and is likely to shape inter-regional planning and cost allocation, as well as the role of merchants going forward.

2. SPP staff will initiate formal dialogue with ERCOT/CREZ TOs, as well as MISO, to identify potential joint EHV transmission facilities/corridors in the Texas Panhandle and Missouri River Valley, respectively, in 4Q10.

SPP staff continues dialogue with key staff at ERCOT, Hunt Transmission / Sharyland, and Tres Amigas regarding CREZ and merchant facilities around Amarillo. In 2Q11, SPP staff had conversations with Clean Line representatives on their potential acquisition of additional ROW for use by SPP facilities adjacent to their proposed Plains and Eastern, as well as the Grain Belt Express, HVDC projects which traverse SPP across OK/AR and KS/MO, respectively.

3. SPP staff will identify opportunities to raise awareness regarding rightsizing opportunities and challenges in key industry forums, e.g., forthcoming EIPC/EISPC meetings, Transmission Summit 2011 Sweetwater TX January 2011, NARUC/DOE National Electricity

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Forum in Feb 2011, WINDPOWER 2011 in May 2011, upcoming FERC technical conferences/testimony, etc. by Nov 2010 with input from SPC on priorities.

SPP staff provided several presentations in the 2nd quarter of 2011 regarding the need for long range, collaborative and cooperative plans, with key consideration given to the need to get the best lines in the best corridors. For this period, presentations and panel discussions were made at the USEA Annual Meeting, NARUC/NSCL transmission workshop, WINDPOWER 2011, Western Transmission Roundup, and the Class IV Winds conference. Key opportunities and challenges for the US bulk power industry were noted in an interview of Jay Caspary that was published in the IEEE-USA Today's Engineer June 2011 newsletter. In addition, SPP staff became actively involved in the EIPC Subteam 7 effort to focus on the development of transmission expansion methodologies which will be completed in 2012. Key considerations which were incorporated into the Subteam 7 proposed guidelines included the need to evaluate upsizing AC facilities to facilitate efficient inter-regional expansion, as well as HVDC and advanced technologies in the development of long range plans. It’s noteworthy that Federal Futures for the EIPC show that wind development in SPP can be expected to reach levels of 80-140GW by 2020-2030 for several scenarios. In May, SPP staff participated in the Power Systems Engineering Research Center (PSERC) meeting at Carnegie Mellon University. Staff is is recommending the SPP join PSERC beginning in 2012 as a member for many reasons. One key effort at PSERC of particular interest is an opportunity to help shape a PSERC National Transmission Overlay study which is a 3 year effort being by lead by staff at Iowa State with support from Wichita State and others to develop a vision for 2050 using NETPLAN. This effort should be a great compliment to the EIPC in creating a blueprint for the US to develop policy development, as well as to inform SPP’s ITP.

4. SPP staff will work with key stakeholders such as DOE, FERC staff, Congressional staff, consultants to develop strategies to increase their awareness and SPP’s emphasis on rightsizing starting in 1Q11

In addition to the previously noted NARUC/NCSL workshop and the WIRES Capitol Hill Briefings, SPP staff has been actively involved in WIRES as well as providing input to DOE’s Quadrennial Technology Review in support of their grid modernization effort. In addition, SPP staff has been working directly with key staff at DOE on potential opportunities for help shape DOE initiatives and efforts to support transmission expansion. Finally, SPP staff has been involved in initial scoping discussions regarding the future of the EIPC and how that effort should proceed in 2013 after DOE funding concludes.

  

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