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Southwest Power Pool

TRANSMISSION WORKING GROUP MEETING

August 18-19, 2015

Magnolia Hotel – Denver, CO

• Summary of Action Items •

1. Approved the previous set of meeting minutes, excluding the July 22nd Net Conference

2. Approved the modified agenda

3. Approved RR-067 had no impact to reliability

4. Approved RR-071 had no impact to reliability

5. Approved the CIP-014-2 Scope as modified

6. Approved the findings of the TPLTF on TPL-001-4 and officially recognized the transition of the TPLTF from TPL-001-4 to TPL-007-1

7. Approved staff’s language as reflective of the TWG position on MOPC Action Item 206

8. Approved removal of the DC ties from the SPP Book of Flowgates

9. Approved RR-056

10. Approved modifications to the 2016 ITPNT Scope

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August 18-19, 2015

Magnolia Hotel – Denver Colorado

• M I N U T E S •

Agenda Item 1 – Administrative Items

Call to Order SPP Chair Mo Awad called the meeting to order at 8:03 a.m. The following members were in attendance (Attachment 1a – Attendance) or represented by proxy:

Mo Awad, Westar Energy, Inc. Scott Benson, Lincoln Electric System, Jerry Bradshaw proxy for John Boshears (phone) Joe Fultz, Grand River Dam Authority (phone) John Fulton, Southwestern Public Service Co., on phone Travis Hyde, Oklahoma Gas & Electric Dan Lenihan, Omaha Public Power District Randy Lindstrom, Nebraska Public Power District Jim McAvoy, Oklahoma Municipal Power Authority Matt McGee, American Electric Power Nate Morris, Empire District Electric Michael Mueller, Arkansas Electric Cooperative Corporation (phone) Alan Myers, ITC Great Plains John Payne, Kansas Electric Power Cooperative, Inc., on phone Jason Shook, GDS Associates representing ETEC, (phone) Tim Smith, Western Farmers Electric Cooperative Noman Williams, South Central MCN Brian Wilson, Kansas City Power and Light, proxy for Harold Wyble

Kirk Hall, SPP staff, confirmed that there was a quorum. Proxies Kirk informed the group there were two proxies (Attachment 1b – Proxies). Brian Wilson held Harold Wyble’s proxy and Jerry Bradshaw held John Boshears’ proxy. Antitrust Guidelines Kirk reviewed the Antitrust Guidelines (Attachment 1c – Antitrust Guidelines) with the group. Previous Meeting Minutes Mo asked the group if there needed to be any changes to the meeting minutes (Attachment 1d, 1e, 1f, 1g – May 19-20, 2015 Face-to-Face Meeting Minutes, June 3, 2015 Net Conference Meeting Minutes, June 19, 2015 Net Conference Meeting Minutes, July 6, 2016 Joint TWG/RCWG Net Conference Meeting Minutes) before approval. Randy Lindstrom proposed two changes to the May 19-20 minutes. Kirk also informed the group that Matt McGee requested a change to the June 3rd Net Conference minutes that had already been made since the posting. Matt also pointed out that the July 22nd minutes were mistakenly left out of the materials. Mo recommended those minutes be approved during the September 16th Net Conference call.

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Alan Myers made a motion to approve the set of meeting minutes as modified during the meeting. Scott Benson seconded Alan’s motion. The motion was approved unanimously.

Agenda Approval Mo requested any modifications to the meeting agenda (Attachment 1h – Meeting Agenda). Kirk pointed out one change to the agenda to accommodate travel arrangements for a presenter.

Scott Benson made a motion to accept the meeting agenda as modified. Alan Myers seconded the motion, which passed unopposed.

Background Materials Mo asked the members if they had any comments related to the meeting materials posted. Members had no comments related to the materials.

Agenda Item 2 – Review of Past Action Items

Kirk reviewed the Action Items (Attachment 2 – Action Items) list with the members. Kirk specifically discussed one completed action item which requested staff propose changes to Criteria 4. SPP’s legal review pointed out that the TWG does not have the authority to approve all Flowgates, only those generated by SPP. Due to this resolution, the item was marked closed.

Agenda Item 3 – MOPC/BOD Update

Mo updated the group on the April round of Markets and Operations Policy Committee (MOPC) and Board of Directors (Board) meetings. The first thing Mo discussed was the approval to re-evaluate 7 NTCs with a due date of the October round of MOPC and BOD meetings. The ESWG provided information to the MOPC on the 2017 ITP10 Futures. This information was carried through to the BOD. An update to the Z2 Crediting process was given. Mo also mentioned an RTWG created task force related to the Z2 Crediting process and encouraged anyone with an interest in this to join the task force. The Transmission Planning Improvement Task Force (TPITF) also provided an update to the MOPC based upon their work so far. Jerry Bradshaw received John Boshear’s proxy.

Agenda Item 4 – TPITF Update

Mo then began a deeper discussion on the work of the TPITF. He began by recapping the discussion and decisions made by the group so far. The TPITF has agreed upon implementing an 18 month rolling planning process which includes an annual report with a recommended portfolio of solutions. The first 6 months would be dedicated to building models with the final 12 months dedicated to the assessment of the models. In order to produce an annual report, the modeling portion of the process would overlap with the last 6 months of the assessment portion. Mo then began discussion on the feedback requests from the TPITF Standardization of NT/TPL Scopes in ITP Manual Mo brought up the topic of standardization of scopes and asked Kirk to go through a presentation (Attachment 3 – TPITF Scope Presentation) noting what items staff and the TPITF had identified so far for standardization in the ITP Manual. Kirk pointed out that most items had been identified to be moved to the manual. The only item identified that would need detail would be the futures assumptions. One question in the room was where the detailed information would be identified. Kirk responded that detailed information such as the model year or futures assumptions would reside in an assumptions document that would be created for each study. Discussion on Scenario 0 vs. Scenario 5 Mo then moved the discussion to the Scenario models. Members did not discuss the detail of each scenario model, but more about how the Scenario models are used. Members did not come to a

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consensus whether the models should be used in the ITPNT process. It was agreed upon within the group that a better method of modeling the wind output does need to be determined. It was also pointed out that any changes made to the ITP process would need to be made in the Aggregate Study and Generation Interconnection Process. Combining the TPL with the ITP Mo shifted discussion to the potential of including the TPL Assessment with the ITP. Stakeholders then discussed the pros and cons of including the TPL Assessment within in the ITP process. Members questioned the ability of the ITP assessment to be completed in a 12 month time period. Members also questioned the use of the ITP model for compliance purposes since the MDWG model is currently being used and is the preferred model for assessing compliance. Modeling of DC Ties from most constraining perspective Mo then moved the discussion of modeling DC ties. During the TPITF meeting, the question of modeling DC ties in the most constraining method was discussed. Mo asked members if the current method was the right way to model DC ties or should the methodology be changed.

Action Item: MDWG to engage with owners of DC Ties (or data submitters) to propose an action for this issue by the end of the year.

Straw Polls Mo then requested the group take a non-binding straw poll for the previous discussions to gauge the TWG’s interest. Straw Poll #1: Study Scope Standardization – Members who identified themselves as generally in favor of standardizing the ITP and TPL scopesScott Benson Alan Myers Dan Lenihan Nate Morris Travis Hyde Tim Smith Noman Williams

Randy Lindstrom John Payne Jason Shook Michael Mueller Brian Wilson Jerry Bradshaw Mo Awad

Jim McAvoy Straw Poll #2: Combining ITP and TPL Assessments – Members who identified themselves as generally in favor of combining the ITP and TPL AssessmentsNoman Williams Mo Awad Nate Morris Matt McGee Alan Myers

Scott Benson Jason Shook Brian Wilson Jerry Bradshaw Michael Mueller

Straw Poll #3: Removing block dispatch models from the ITPNT assessments – Members who identified themselves as generally in favor of using only the CBA Scenario in the ITPNT Assessment Alan Myers Joe Fultz Jason Shook Brian Wilson Jerry Bradshaw

Michael Mueller Noman Williams Matt McGee Mo Awad

Straw Poll #4: Removing block dispatch models from the ITPNT assessments as well as Generation Interconnection and Transmission Service studies Alan Myers Scott Benson

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Noman Williams Jason Shook Joe Fultz

Brian Wilson Michael Mueller Mo Awad

Straw Poll #5: Modifying Scenario 5 for a more realistic renewable dispatch Noman Williams Alan Myers Scott Benson Travis Hyde

Jason Shook Joe Fultz Mo Awad

Agenda Item 5 – Tariff Revision Request

TRR-067 Matt Harward, SPP staff, reviewed TRR-067 (Attachment 4a – TRR-067) with the TWG. The only question raised by members was related to whether the customer or the market pays for the costs of redispatch. Matt confirmed this revision is meant to correct the Tariff to line up with how the market is currently working, which allocates the cost of redispatch to the entire market footprint.

Motion: Noman Williams moved that the TWG had reviewed RR-067 and found no impact to reliability. Jason Shook seconded the motion.

Discussion continued on this Revision Request. Dan Lenihan asked if the redispatch described in the Revision Request is long-term or only used until planned upgrades are placed in service. Staff answered that it only applies until upgrades are placed in service as written in Attachment Z1 of the Tariff.

The motion passed unanimously.

TRR-071 Matt began discussing TRR-071 (Attachment 4b, 4c – RR71 Recommendation Report, SIS with Counteroffer Flowchart). Members agreed with the revision and found no impacts to reliability

Motion: Scott Benson made a motion that the TWG had reviewed RR-071 and found no impact to reliability. Noman Williams seconded the motion which passed unopposed.

Agenda Item 6 – 2015 NERC Assessments Update

2015 TPL-001-4 Steady State Assessment Update Jason Terhune, SPP staff, presented the group an update (Attachment 5 – 2015 TPL Steady State Assessment Update). Jason mentioned the upcoming milestones, including the distribution of the violations to the members. The group had a short discussion on how the stakeholder meetings for non-consequential load loss would be done. 2015 Dynamic Stability Assessment Update Doug Bowman, SPP staff, updated the group on the progress of the 2015 TPL Dynamic Assessment. He informed the members on the large number of contingencies staff was going to have to analyze. He stated that they are working to use staff’s Enfuzion node computing capabilities. If this approach is unsuccessful, consulting resources may be needed. Doug asked the members to review their list of submitted contingencies to determine if any could be removed for evaluation. Short Circuit Update William Holden, SPP staff, updated the group on the progress of the study. He stated that the deadline for CAP submission was August 31st.

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Agenda Item 7 – CIP-014-2 Scope

Jonathan Hayes, SPP staff, presented the RCWG approved CIP-014-2 Scope document (Attachment 6 – CIP-014-2 Scope) for TWG review and approval. Members did not agree with the RCWG approved language that allowed staff the ability to refuse to be a 3rd party reviewer. The group suggested that if SPP received more review requests than it could handle the total cost for the staff time and consultants should be socialized among those entities requesting a 3rd party review. Jonathan informed the TWG that language related to the socialization of costs would be added to the contract. Modifications were made to the scope by the members. Kirk pointed out to the members that a full SPP Legal and RCWG review would be needed if the scope document was approved as modified.

Motion: Alan Myers made a motion to approve the CIP-014-2 scope as modified during the meeting. Randy seconded the motion. The motion carried unanimously.

Agenda Item 8 – Fast Fault Benchmarking

Doug Bowman presented his results of the Fast Fault Benchmarking analysis (Attachment 7 – Fast Fault Benchmarking Presentation) requested by the TWG. Members had no issues with Doug’s benchmarking results.

Agenda Item 9 – Market Impact of Transmission Expansion

Catherine Mooney, SPP staff, gave a presentation (Attachment 8 – MMU ASOM Congestion and Losses TWG) to the group on how the transmission expansion within SPP has been affecting congestion in the Integrated Marketplace. She noted several lines placed in-service within the last year that altered flows and lowered congestion.

Agenda Item 10 – TWG Reports

TPLTF Update Jason Terhune, SPP staff, provided the final results of the TPLTF (Attachment 9a, 9b – TPLTF Update, TPLTF Findings) on its dive into NERC Standard TPL-001-4. On behalf of the TPITF, Jason also requested the TWG accept the documentation provided by the TPLTF as the findings per the TPLTF Charter and officially recognize the transition from the NERC TPL-001-4 standard to the NERC TPL-007-1 standard as the primary focus.

Motion: Alan Myers made a motion to recognize the transition from the NERC TPL-001-4 standard to the NERC TPL-007-1 standard as the primary focus. Noman Williams seconded the motion. Mo Awad requested a friendly amendment to the motion seen in the slide deck that accepted the five documents produced by the TPLTF as its findings to the TWG per the TPLTF charter. Alan and Noman accepted the friendly amendment. The motion passed with one abstention from Travis Hyde.

During the meeting Travis voiced his reasoning for abstention was due to the lack of identification of this item as a voting item on the agenda. MDWG Report Nate Morris, MDWG Chair, gave the group an update from the MDWG (Attachment 9c, 9d – MDWG Report, 2015 MDWG Model Build Schedule). Nate pointed out 3 important points in the MDWG schedule: 1) Load will not be able to be modified after Pass 2 is finalized 2) Each pass must be finalized by the TO submitting corrections in the form of an idev and committing to submitting a project in MOD for the next pass 3) the 2015 MDWG Models will be built using PSSE version 33.

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AQITF Jim McAvoy provided an update (Attachment 9e – AQITF Update) the TWG on the progress on the AQITF. Jim informed the TWG that the goal is to submit Business Practice revisions and revised Tariff language by September 1st. TWG Work Schedule Kirk then discussed the TWG Work Schedule (Attachment 9f, 9g – TWG Work Schedule, TWG Work Schedule with Gantt Chart). He noted the important items occurring before the next Quarterly TWG meeting. He also noted that the background material included the information in a Gantt chart format requested as part of a TWG Action Item. MITF Disbandment Kirk then requested that Mo disband the Model Improvement Task Force. Mo agreed and formally disbanded the MITF.

Agenda Item 11 – SPP.org Redesign

Derek Wingfield, SPP staff, updated the group on the progress (Attachment 10 – SPP.org Redesign) of the SPP.org website redesign. Derek highlighted the process for being added to the website as a user from a working group member perspective and non-working group member perspective. Derek also pointed out the enhanced search functionality and the improved calendar/meeting information.

Agenda Item 12 – Generator Interconnection Update

Limited Operation of GIs Recommendation Charles Hendrix, SPP staff, provided the TWG with a summary (Attachment 11a, 11b – MOPC Action Item 2016 Presentation, MOPC Action Item 206 Recommendation) of their comments related to MOPC Action Item 206 on Limited Operation of GIs for their approval before being sent back to the MOPC.

Motion: Dan Lenihan made a motion to accept staff’s recommendation and the language in the document as reflective of its position on MOPC Action Item 206. Alan Myers seconded Dan’s motion, which passed with no opposition.

NRIS Update Charles then updated the group on the potential modifications to the NRIS process (Attachment 11c,11d – NRIS Update, BPR XXX Generator Interconnection Service Draft) due to the implementation of the Integrated Marketplace. Charles provided his first look at changes to Business Practice 7250. Charles asked the group to provide feedback to his revisions to Business Practice 7250. Randy Lindstrom feels that the 20% TDF is excessive, and suggested 5% for PTDF and 3% for OTDF. He also suggested treating NRIS and ERIS the same. Charles did express his concern that lowering the TDF thresholds would create a backlog in his process.

Agenda Item 13 – Flowgate Update

Mo Awad reminded the group that Flowgate approvals are considered market sensitive and asked those who participate on the market side of SPP to leave the room. WAPA Flowgate Assessment TRM Approval Champy Gahagan, SPP staff, gave an overview of what staff was requesting. He stated that he had not received feedback from WAPA on these TRM values and no representative was available to comment on the validity of the calculations. Mo suggested moving this item to the September 16 net conference to allow for comments and agreement from WAPA. DC Tie Flowgate Removal

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Will Tootle, SPP staff, requested the TWG approve the removal of the DC Tie Flowgates because they are not the main tool for monitoring the DC ties. Members asked how curtailment of DC ties for reliability reasons would be handled. Will stated that Operations would create a flowgate.

Motion: John Fulton made a motion, seconded by Randy Lindstrom, to remove the DC Ties from the SPP Book of Flowgates. The motion passed unopposed.

Flowgate Educational Session Moses Rotich, SPP staff, presented an educational session to the members on the process staff uses to perform the Annual Flowgate Assessment. Travis Hyde pointed out the disconnect between the planning models and current congestion. Other issues with the assessment were voiced such as flowgates continuing to be permanent even though no TLR has been called in years and unrealistic transfers. Staff agreed to continue work on this action item and agreed to come back in the future with improvements prior to the next assessment starting.

Agenda Item 14 – Regional Review of Potential Interregional Projects

Jason Speer, SPP staff, and Brett Hooton, SPP staff, began discussion on the Regional Review of Potential Interregional Projects (Attachment 12 – CSP Regional Review Results). A question was asked on whether the calculation methods are the same as the one in RCAR. Brett responded that the calculation method is different and needed a different name to get rid of confusion. Discussion then centered on what the SPP Board of Directors would do if MISO did not approve a project in their Regional Review. Brett stated that the Board would have a decision to make on whether that project should get an NTC.

Agenda Item 15 – RR-056

Tony Green, SPP staff, presented the recommendation report for RR-056 (Attachment 13 – RR-056 Recommendation Report). Members asked to clarify the term local facility and altering existing ROW. Members also discussed how the substation cost would be counted when determining whether a project had an allocated cost of 80% rebuild vs. 20% new. Tony responded that substation costs would be counted in the rebuild category.

Motion: Noman Williams made a motion to approve Revision Request 56. Dan Lenihan seconded the motion, which passed unanimously.

Agenda Item 16 – Reliability Project Selection Metrics

Michael Odom, SPP staff, presented staff developed metrics (Attachment 14 – Reliability Project Selection Metrics) to help select reliability projects in the ITP processes. A clarifying question was asked on whether this metrics applies to one model or all models. Kirk responded that these metrics were there to help identify the best project for an individual need and will help with a ranking of comparable projects. Randy pointed out that one of the main inputs to the metrics is the estimated cost and does not want this to be the only metric used in the evaluation. Antoine Lucas, SPP staff, responded that staff uses the best information available when estimating costs for projects and agrees that staff will continue to use engineering judgment when selecting projects for the final portfolio. Members generally agreed that they were not ready to vote on this item and asked for additional information about how projects get displaced. Wayman Smith asked the reasoning for giving a lesser weight to projects that increased the voltage above 1.0 per unit, and if staff plans to consider if a project increases the loading on a transmission line while mitigating an overload.

Action Item: Staff to explain the displacement process for selecting projects and provide a real world example on how this process would work.

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Agenda Item 17 – 2016 ITPNT Update

Non-Competitive Cost Estimates Discussion Jason Davis, SPP staff, presented to the group the stakeholder developed solution (Attachment 15a, 15b – Non-Competitive Cost Estimates Discussion, Solution 2A Timeline) getting cost estimates for non-competitive projects in the ITP process to alleviate the amount of NTC re-evaluations due to cost variance from the 2015 ITPNT and 2015 ITP10 studies. The solution for this issue is to determine whether a project is competitive or non-competitive early in the process and ask the incumbent TO to provide cost estimates for all non-competitive solutions. This concept was agreed to by the MOPC and SPP Board of Directors with the understanding that there would be a review of SPP Governing Documents and study scopes to make sure the processes could accommodate this solution. Jason then reviewed the impacts to the schedule with the TWG to determine what changes need to be made based upon this solution. Staff determined that they would need two additional weeks after the non-competitive estimates are submitted to review the costs as well as stakeholder feedback prior to finalizing the portfolio. Because of this, staff recommended the TOs time to develop non-competitive cost estimates be reduced from 6 weeks to 4 weeks. Scott Rainbolt and John Fulton expressed their concern that 4 weeks was not enough time to complete a ±30% cost estimate. Other members generally agreed with the 4 week estimate and it was determined that the TWG was OK with the shortened timeline to provide their estimates from 6 weeks down to 4 weeks based on staff’s recommendation. 2016 ITPNT Scope Modification Kirk presented the changes to the scope to account for the shortened review timeline of the draft portfolio in the high level schedule found in the 2016 ITPNT Scope (Attachment 15c – 2016 ITPNT Scope) and asked the TWG for approval.

Motion: Noman Williams made a motion to accept staff’s recommended changes to the 2016 ITPNT Scope based upon the solution to receive non-competitive cost estimates. Randy Lindstrom seconded the motion which passed with no opposition.

Agenda Item 18 – Non Transmission Solutions

Kirk discussed the new concepts staff is developing to fairly evaluate non-transmission solutions in the ITP and Transmission Service processes (Attachment 16 – Non-Transmission Solution Submissions). Members questioned staff’s identification of a non-transmission solution. Kirk pointed out that all non-transmission solutions, including legacy transmission operating guides, would need to be submitted to SPP staff through SPP’s Request Management System if you wanted it to be evaluated against other solutions. Members responded that a separate form for legacy transmission operating guides would be helpful. Staff plans to revisit this topic with the TWG in the future to identify the evaluation process.

Agenda Item 19 – Non-Standard Project Evaluation

Kirk updated the TWG on staff’s progress with developing a process to evaluate non-standard solutions in the ITP processes. Staff plans to determine a set of non-standard solution types then identify a list of decision-making studies that would need to be performed for each project type to ensure that these studies are performed before a decision is made on whether the project should be selected or not. A clarifying question was asked on whether these decision-making studies were required with the submission. Kirk responded that at this point the studies may not be required with the solution but performed after the project is submitted. Staff plans to continue working this item through the stakeholder process and would like the TWG to endorse staff’s list of decision-making studies for each project type.

Agenda Item 20 – 2017 ITP Discussion

Chris Jamieson, SPP staff, discussed a few upcoming items with the TWG, including items staff planned to request approval for during the August 19-20 ESWG meeting. Those items included inclusion of Non-Designated Resources, amounts of solar generation in the models, how to deal with energy efficiency,

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and amount of retirements due to the Clean Power Plan. Kirk also noted a few TWG items staff would be requesting soon to allow the 2017 ITP10 Scope to be approved during the October MOPC. Those items include the reliability hours, determining reliability needs in the ITP10, constraint assessment methodology, and identification of generator outlet facilities.

Agenda Item 21 – NERC Standards Group Update

Kirk reviewed the updates from SPP’s NERC Standard group (Attachment 17 – NERC Standards Group Update). Members had no questions.

Agenda Item 22 – Interconnection Updates

Kirk asked if any members had updates or wanted to inform the TWG on upcoming Interconnection studies to satisfy SPP Criteria 3.5. John Fulton, SPS, informed the group that the Criteria 3.5 studies for the Walkemeyer Tap project on the Hitchland – Finney 345 kV line would be starting soon and encourage participation from potentially interested parties.

Agenda Item 23 – Summary of Action Items

Kirk reviewed the action items with the group:

MDWG to engage with owners of DC Ties (or data submitters) to propose an action for this issue by the end of the year.

Staff to explain the displacement process for selecting projects and provide a real world example on how this process would work.

Agenda Item 22 – Discussion of Future Meetings

Mo reminded the group of the next scheduled meetings. Kirk pointed out there would be a full agenda for the September 16th Net Conference. He asked for the call to be moved to 8:30 am – 11:30 am. Members agreed that would be acceptable. Seeing there was no further business, the meeting was adjourned at 11:03 am. Respectfully Submitted, Kirk Hall Secretary

SPP Antitrust Guidelines

Prohibited Discussions

• Pricing information, especially margin (profit) and internal cost.

• Information and participants’ expectations as to their future prices or internal costs.

• Participant’s marketing strategies.

• How customers and geographical areas are to be divided among competitors.

• Exclusion of competitors from markets.

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Prohibited Discussions cont

• Boycotting or group refusals to deal with competitors, vendors or suppliers.

• No decisions should be made nor any actions taken during SPP activities for the purpose of giving an industry participant or group of participants a competitive advantage over other participants.

• In particular, decisions with respect to setting, revising, or assessing compliance with SPP reliability standards should not be influenced by anti‐competitive motivations.

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Permitted Discussions• Reliability matters relating to the bulk power system,

including operation and planning matters such as establishing or revising reliability standards, special operating procedures, operating transfer capabilities, and plans for new facilities.

• Matters relating to the impact of reliability standards for the bulk power system on electricity markets, and the impact of electricity market operations on the reliability of the bulk power system.

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Permitted Discussions cont• Proposed filings or other communications with state

or federal regulatory authorities or other governmental entities.

• Matters relating to the internal governance, management and operation of SPP, such as nominations for vacant committee positions, budgeting and assessments.

• Procedural matters such as planning and scheduling meetings.

• Any other matters that do not clearly fall within these guidelines should be reviewed with SPP’s General Counsel before being discussed.

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http://www.spp.orgGeneral Inquiries: 501‐614‐[email protected]

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May 19-20, 2015

Sheraton Downtown – Oklahoma City, OK


1. Approved previous meeting minutes.

2. Approved the meeting agenda.

3. Approved the 2015 TPL Stability Scope.

4. Approved a waiver to include the 2nd Elk City unit in the 2016 ITPNT models.

5. Approved a waiver to include the Gaines generator in the 2016 ITPNT models.

6. Approved a waiver to include GRDA’s GREC3 unit in the 2016 ITPNT models.

7. Approved RR 84 which retires BP 7050.

8. Approved Quarterly Flowgate additions.

9. Approved TRM values associated with the Quarterly Flowgate additions.

10. Endorsed staff’s practice of studying all in group wind and solar at 100% nameplate for thermal and stability in Interconnection Studies.

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November 18, 2014

SPP Corporate Campus – Little Rock, AR

• M I N U T E S •


Call to Order SPP Chair Mo Awad called the meeting to order at 8:01 a.m. The following members were in attendance (Attachment 1a – Attendance) or represented by proxy:

Mo Awad, Westar Energy, Inc. Scott Benson, Lincoln Electric System, on phone John Boshears, City Utilities of Springfield, on phone Joe Fultz, Grand River Dam Authority John Fulton, Southwestern Public Service Co., on phone Travis Hyde, Oklahoma Gas & Electric Dan Lenihan, Omaha Public Power District Randy Lindstrom, Nebraska Public Power District Jim McAvoy, Oklahoma Municipal Power Authority, on phone Matt McGee, American Electric Power Nate Morris, Empire District Electric Michael Mueller, Arkansas Electric Cooperative Corporation, on phone Alan Myers, ITC Great Plains Gayle Nansel, Western Area Power Administration John Payne, Kansas Electric Power Cooperative, Inc., on phone Jason Shook, GDS Associates representing ETEC, on phone Tim Smith, Western Farmers Electric Cooperative Jeff Stebbins, Tri-County Electric Cooperative Noman Williams, South Central MCN Harold Wyble, Kansas City Power and Light

Kirk Hall, SPP Staff, confirmed that there was a quorum. Proxies Kirk informed the group there were no proxies. Antitrust Guidelines Kirk reviewed the Antitrust Guidelines (Attachment 1b – Antitrust Guidelines) with the group. Previous Meeting Minutes Mo asked the group if there needed to be any changes to the meeting minutes (Attachment 1c, ,1d, 1e – February 17-18 Face-to-Face Meeting Minutes, March 18th Net Conference Meeting Minutes, March 25th Net Conference Meeting Minutes) before approval. No changes were requested.

Travis Hyde made a motion to accept the meeting minutes. Harold Wyble seconded the motion. The motion was approved unanimously.

Agenda Approval

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Mo requested any modifications to the meeting agenda (Attachment 1g – Meeting Agenda). Matt McGee, AEP, noted that the Criteria 3.5 Interconnection request between AEP and Entergy was no longer an ongoing project and should be removed from the agenda. Nate Morris, Empire District Electric, also requested the TWG report be moved to Day 2 of the agenda. Kirk also requested an informational discussion on NERC Standard IRO-017-1 be added to the 2015 NERC Assessments portion of the agenda.

Alan Myers made a motion to accept the meeting agenda as modified. Nate Morris seconded the motion, which passed unopposed.

Background Materials Mo asked the members if they had any comments related to the meeting materials posted. Kirk pointed out to the member that the TRM values for the SPP Operations requested flowgates were posted on Wednesday and the PRC-023-3 list was not included with the meeting materials.

Agenda Item 2 – Review of Past Action Items

Kirk reviewed the Action Items (Attachment 2 – Action Items) list with the members, specifically discussing how to proceed with the older action items that were discussed individually between meetings with Mo. The members requested no change to the recommendations for each item. Kirk did specifically discuss the revival of the AQ Improvement Task Force (AQITF). He mentioned that Jason Speer, SPP staff, had reached out to the members of the task force to determine if they were still interested in participation. Most members wanted to stay involved. Kirk also asked if any other members would like to join the task force, including members from the Integrated System. Jim McAvoy, AQITF Chair, stated that he would like to add a member from the Regional Tariff Working Group (RTWG) to help revise the tariff language.

Agenda Item 3 – MOPC/BOD Update

Mo updated the group on the April round of Markets and Operations Policy Committee (MOPC) and Board of Directors (Board) meetings. He noted that the MOPC and Board approved the inclusion of the informational analysis of TPL contingencies described in the 2016 ITPNT Scope as well as the 2016 ITPNT Scope as a whole. He also stated the MOPC approved the revisions to the TWG Charter. Kirk mentioned that the charter revisions must still go to the Corporate Governance Committee and the Board before the membership limit could be official. The MOPC and Board also heard presentations on the 2017 ITP10 futures. The MOPC approved 2 futures with the possibility of a 3rd, but the Board approved a 3rd future that did not include the Clean Power Plan, which is a major driver for Futures 1 and 2. The MOPC and Board also voted on the re-evaluation of the 21 mile 115 kV line from Walkemeyer – N. Liberal and associated projects in the 2015 ITP10. He noted that the MOPC was unable to come to a consensus, but the Board approved the recommendation of SPP staff, which was to issue the RFP/NTCs as described in the 2015 ITPNT and 2015 ITP10 reports. This resulted in SPP’s first competitive project under FERC Order 1000.

Agenda Item 4 – SPPR Tool

Doug Bowman, SPP staff, reviewed a presentation (Attachment 3 – SPPR Calculation Tool) on the SuccessiveSingle Positive Peak Ratio Tool (SPPR Tool) that was developed at the request of the members to help SPP evaluate the stability of the system against SPP’s Disturbance Performance Requirements. The members had no questions related to the tool, but were interested if they would be able to use the tool as well. Doug informed the members that he would provide it to them at their request.

Agenda Item 5 – Series Compensation Requirements

Doug Bowman also gave a presentation (Attachment 4 – Series Compensation Studies) to the TWG on the potential study requirements and associated time and cost estimates associated for Series

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Compensation projects to be installed on the transmission system in SPP’s footprint. The TWG discussed how series compensation projects and other more exotic transmission solutions could be evaluated fairly in the competitive process required by Order 1000 since the study requirements for these projects are both time and money intensive and may not fit within the DPP response windows that are only 30 days. Members also mentioned the costs for mitigations that may be required due to series compensation on the system or mitigations that may be needed in situations where a line with series compensation is tapped. A few members thought these costs should be borne by the project submitted, but could potentially be recoverable. Another additional cost could be an independent 3rd party review of the assessments done by the project submitter.

Action Item: Staff to examine how FACTS devices, HVDC lines, and other exotic projects could be evaluated fairly in the competitive Order 1000 process and develop a process for evaluation.

Agenda Item 6 – 2015 NERC Assessments

2015 TPL-001-4 Steady State Assessment Update Jason Terhune, SPP staff, presented the group an update (Attachment 5a – 2015 TPL Steady State Assessment Update). Jason mentioned the upcoming milestones, including the distribution of the violations to the members. 2015 Dynamic Stability Assessment Scope Doug Bowman reviewed the 2015 Dynamic Stability Assessment Scope (Attachment 5b – 2015 Dynamic Stability Assessment Scope) written to outline the scope of the dynamic portion of the 2015 NERC TPL-001-4 Assessment. Members asked if the scope had any definition in it to determine that cascading had been avoided. Doug stated that the TPLTF is still working through the definition and may use the PCM module from POM as the definition. John Fulton asked about the confidentiality of data that would be put in the report and think a decision needs to be made about what information is included. The ability to submit PSA files was also added to the scope at a member’s request.

John Boshears made a motion to approve the TPL Stability Scope as modified during the meeting. Alan Myers seconded the motion. Dan Lenihan offered a friendly amendment to the motion requesting that the document be updated to describe the cascading evaluation by the PCM module. John and Alan both accepted the friendly amendment. The motion passed with one abstention from John Fulton (SPS).

John Fulton provided the following reasoning for his abstention:

“SPS Abstained on this vote for several reasons listed below. The TPL Task Force has done well in resolving many of the issues, but a few issues remain that were not resolved. 1. The process for transmission owners to submit their own ready-to-run simulation files was not

documented in the scope. Requiring submitters to submit the information in a spreadsheet format is unduly costly. The transmission owners have spent years working on modeling their systems in the format required by Siemens PTI Stability program. The effort to decode this information and place it in a spreadsheet will require additional time and effort on behalf of the submitters, and will introduce another opportunity for errors.

2. This topic area of how simulations (which require interaction with the submitter) will be run

not is provided in the document. Category P3 and P6 require adjustment between complex contingencies. P3 and P6 events were not requested by SPP for the steady-state analysis since system adjustments between events are required. SPP needs to work with members

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on the system adjustments that will be made as part of SPP’s analysis. There is no information as to how that process will be managed by SPP and what will be required from the transmission owner.

3. Data Confidentiality of Submitted Disturbance Timing Instructions – the detailed timing

information provided in ready-to-run simulation files or SPP’s spreadsheet represents confidential information that SPS doesn’t want made public. FERC defines Critical Energy Infrastructure Information (CEII) as “specific engineering, vulnerability or detailed design information about proposed or existing critical infrastructure (physical or virtual) that 1) relates details about the production, generation, transmission or distribution of energy, 2) could be useful to a person planning an attack on critical infrastructure, . . . 4) give strategic information beyond the location of the critical infrastructure”. There seems little doubt that the type of information that would be required in these instructions would include details that would pinpoint vulnerabilities and strategic information about the providers system; information which could certainly aid a person planning an attack on critical infrastructure. No part of the scope document addressed what would be included in the report, made public, or provided to TWG and other SPP stakeholders as this process moves forward or what data would be considered confidential data, or how this information would be presented to SPP stakeholders while protecting the critical energy infrastructure information.”

TPL-007-1 Update Doug Bowman presented an update (Attachment 5c – TPL-007-1 TWG) on the progress of NERC Standard TPL-007-1. Doug recommended a task force be created to ensure that compliance with the standard is achieved. Mo requested the TPL TF take on compliance with this issue.

Action Item: TPLTF to modify its charter to account for TPL-007-1 and present to the TWG at the June TWG Net Conference.

CIP-014-2 Update Jonathan Hayes, SPP staff, revealed the latest template (Attachment 5d – CIP-014-2 Template) for members to submit their CIP-014-2 assessment to SPP for a 3rd party review. He mentioned there was one piece of feedback he had received since the document was posted, that would be included in the final version. Jonathan informed the TWG that the service agreement was currently being reviewed by SPP’s Legal Department. Members expressed no concerns with the template.

Action Item: Staff to identify IROLs for Planning and Operations separately. PRC-023-3 Attachment B.4 Facilities Kirk reviewed the analysis SPP completed to create its draft list of facilities for PRC-023-3. He noted all feedback for approval of these facilities had not been provided, so endorsement would not be requested during the meeting. Kirk asked for feedback on whether a facility should be represented multiple times for different contingencies or multiple times for common contingencies in different seasons. Members agreed that a facility should only be shown once by selecting the earliest season and the worst contingency it meets the requirements described in Attachment B.4. IRO-017-1 Jonathan also updated the members on SPP’s initial discussions related to NERC Standard IRO-017-1 which would require coordination between planning and operations on determining the impacts of planned outages of generators. Staff agreed to inform the stakeholders as discussions continue.

Agenda Item 7 – 2016 ITPNT Generation Waiver Requests

Elk Station CT

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Lloyd Kolb, Golden Spread Electric Cooperative, requested the TWG approve a waiver (Attachment 6a – GSEC Waiver Request) for the 2nd Elk City CT to be included in the 2016 ITPNT models. Members asked if any upgrades were required for the generation to be interconnected. Lloyd stated that there were no direct-assigned upgrades and all upgrades in the area had already received NTCs.

Jeff Stebbins made a motion to approve the waiver to allow Golden Spread Electric Cooperative’s Elk City 2 unit to be included in the 2016 ITPNT models. Noman Williams seconded the motion. The motion passed unanimously.

Gaines Generator John Fulton, SPS, requested the TWG approve a waiver for the Gaines generator (Attachment 6b – SPS Gaines Waiver Request) to be included in the 2016 ITPNT models. John was asked what upgrades have been required. He stated that most upgrades needed already have NTCs from the 2015 ITPNT, but one additional rebuild may be needed. Nate Morris expressed his concern that most requirements for the waiver had not been met.

Joe Fultz made a motion to accept the inclusion of the Gaines generator in the 2016 ITPNT models. John Payne seconded the motion. The motion passed with one abstention from Nate Morris (Empire District Electric).

After the meeting Nate Morris provided the following reason for his abstention:

“As stated in the meeting, EDE’s concerns are focused around the large number of unmet requirements to be taken into account as spelled out in the ITP manual. As a result, EDE abstained from the vote.”

GRDA GREC3 Joe Fultz, Grand River Dam Authority, requested the TWG approve a waiver (Attachment 6c – GRDA GREC3 Waiver Request) for the GREC3 combined cycle unit. Members asked if this unit was meant to replace existing unit. Joe stated that it would be placed in-service after the existing unit is requiredretired. The retirement of the existing unit is also explicitly detailed in the Generation Interconnection Agreement.

Joe Fultz made a motion to approve the inclusion of GRDA’s GREC3 combined cycle unit in the 2016 ITPNT models. Alan Myers seconded the motion, which passed without opposition.

Agenda Item 8 – Revision Request 84: Retirement of BP 7050

Cary Frizzell, SPP staff, presented Revision Request 84 (Attachment 7 – RR 84), which would retire Business Practice 7050.

Noman Williams made a motion to approve RR 84. Harold Wyble seconded the motion. The motion passed unanimously.

Agenda Item 9 – Flowgate Modifications

Mo Awad reminded the group that Flowgate approvals are considered market sensitive and asked those who participate on the market side of SPP to leave the room. Quarterly Flowgate Approvals Kirk reviewed the permanent candidate flowgates to the members pointing out some of the potential permanent flowgates that were tie-lines to MISO members and the limiting element was owned by the MISO entity. Therefore, these flowgates would be owned by MISO and not require SPP approval. The flowgates did meet the joint requirements between SPP and MISO. Members did not provide any comments related to these flowgates.

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Harold Wyble made a motion to approve the Quarterly Flowgate additions. John Fulton seconded the motion, which passed unanimously.

Quarterly Flowgate TRM Calculation Kirk reviewed the TRM calculation values for the Quarterly Flowgate that had just been approved. The members had no comments related to the calculated values.

Harold Wyble made a motion to approve the TRM values for the Quarterly Flowgate additions. Scott Benson seconded the motion. The motion passed with none in opposition.

2015 Flowgate Assessment Additions/Removals Kirk then showed the TWG the flowgate addition/removal candidates resulting from the 2015 Flowgate Assessment. The file included member feedback; however, feedback had not been provided by all members. Members provided additional feedback to the flowgates, but did not feel appropriate approving the flowgate change candidates. Members questioned why certain facilities were being recommended as a permanent flowgate even though no operational issues were identified in the last year for those facilities. Staff reminded the members that there are two distinct analysis that are completed as part of the flowgate assessment. The first analysis is based upon the planning models and the second is based upon operational considerations, but both analyses should be considered separately when considering adding or removing permanent flowgates 2015 Flowgate Assessment TRM Approval Kirk showed the member the updated TRM calculations with member feedback included. Matt McGee, AEP, pointed out that the TRM values for 11 flowgates were calculated with a model error nearby and the TRM values did not look correct. He recommended staff use the previous year’s TRM values calculated for those flowgates. Staff noted that there is a requirement to calculate TRM on all flowgates each year so the value would need to be recalculated for approval.

Action Item: Staff to update the Flowgate change candidates and TRM value spreadsheets and redistribute to the members for a special net conference to be set up for a vote, which would occur no less than 1 week after the files have been distributed. Action Item: Staff to provide the TWG with an educational session on how the Flowgate Assessment is performed.

Members also pointed that in the past reasoning for not including certain flowgates may not have been consistent between facilities. Members were encouraged to submit for reconsideration permanent flowgates to staff to determine if it should continue to be a permanent flowgate.

Agenda Item 10 – Limited Operations of Generator Interconnections (MOPC AI 206)

Grant Wilkerson, Business Practices Working Group (BPWG) Chair, introduced MOPC Action Item 206 to the TWG. Grant mentioned that this item had been given to the TWG to by the MOPC at the recommendation from the BPWG because they did not feel they had the expertise to discuss the issue appropriately. Charles Hendrix, SPP staff, presented a proposal (Attachment 8 – GI Update) to the TWG on how to deal with generators that wanted to interconnect to the system on a limited basis when a variable resource was not available or running. Members were generally opposed to the recommendation proposed to solve the issue in question. Direction was given from the TWG to draft a response to the request and bring back to the TWG at a later meeting.

Action Item: Staff to compile comments from the members and draft a response to the request for Limited Operation of a Generator for presentation to the TWG at a later meeting.

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Charles also asked to discuss a few additional items with the TWG. He first requested feedback on the Network Resource Interconnection Service (NRIS) modifications staff has proposed due to implementation of the Integrated Marketplace. Charles asked the TWG to provide feedback on the proposal which included the following:

Studying NRIS using the entire SPP footprint similar to ERIS Using Scenario 5 models Not including ERIS generators unless firm service or are under study for firm service Study using a 3% TDF mitigation of constraints

Charles next discussion item was related to generator uprates and how/if they should be studied in the GI process. Charles asked for feedback from the TWG on the proposed changes to a generators rating if they owner requests an uprate. Charles final item was a request to the TWG to endorse a staff proposed methodology to dispatch wind and solar requests at 100% nameplate for thermal and stability analysis. The TWG agreed with staff’s proposal.

Randy made a motion to endorse staff’s practice of studying all in group wind and solar at 100% nameplate for thermal and stability in Interconnection Studies. The motion was seconded by Dan Lenihan. The motion was passed unanimously.

Agenda Item 11 – 2017 ITP10 Update

Schedule Update Kelsey Allen, SPP staff, discussed the schedule (Attachment 9a – 2017 ITP10 Schedule and Futures) for the 2017 ITP10 highlighting the current milestones and progress of the study. Kelsey also discussed at a high level the futures that have been reviewed by the MOPC and approved by the BOD. He noted that the MOPC requested 2 futures and a potential third future, but the Board of Directors approved three futures. Resource Expansion Methodology Kelsey also discussed a revision to the Resource Expansion process (Attachment 9b – Resource Expansion Methodology). Staff is proposing to add generators from the Generation Interconnection Queue to the 2017 ITP10 models if there is a high likelihood a unit will go into service. Members asked if the upgrades needed for interconnection would be included with the unit. Staff stated they would. Members offered a few suggestions for improving the selections of generators that could be added to the 2017 ITP10 model. Siting Methodology Chris Jamieson, SPP staff, review potential improvements to the 2017 ITP10 Siting Plan (Attachment 9c – SPP Resource Siting Methodology).

Agenda Item 12 – RCAR II Update

Josh Ross, SPP staff, updated the TWG on the progress of the RCAR II assessment. His main point was to inform the members that the study had been delayed until July 2016 instead of July 2015. The reason for this was to allow the assessment to be performed using the 2017 ITP10 models in the assessment. Wayman Smith, AEP, asked if the methodology for determining constraints would be revisited. Josh told the group that it would be revisited for a better potential long term solution.

Agenda Item 13 – TWG Reports

MDWG Report

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Nate Morris, MDWG Chair, provided the group with an update on the work being performed by the MDWG (Attachment 10a – MDWG Report). Mo asked Nate for a review of the improvements implemented in the 2015 MDWG model build. Nate believed that progress had been made on the improvements being implemented, but additional improvements could still be made. Nate also reviewed the MDWG Model Build report card. TWG Work Schedule Kirk reviewed the TWG Work Schedule (Attachment 10b – TWG Work Schedule) pointing out the items that would need focus or review from the TWG before the next face-to-face TWG meeting. He pointed out the 2016 ITPNT model schedule and that the group would be approving those models in June.

Agenda Item 14 – NERC Standards Update

Shannon Mickens, SPP staff, updated the group on the development of new NERC Standards (Attachment 11 – NERC Standards Update). Mo suggested an improvement to the provided materials that the applicability be included on each standard so it would be clear who is required to comply with the standard.

Agenda Item 21 – Summary of Action Items

Kirk reviewed the action items with the group:

Staff to examine how FACTS devices, HVDC lines, and other exotic projects could be evaluated fairly in the competitive Order 1000 process and develop a process for evaluation.

TPLTF to modify its charter to account for TPL-007-1 and present to the TWG at the June TWG Net Conference.

Staff to identify IROLs for Planning and Operations separately. Staff to update the Flowgate change candidates and TRM value spreadsheets and

redistribute to the members for a special net conference to be set up for a vote, which would occur no less than 1 week after the files have been distributed.

Staff to provide the TWG with an educational session on how the Flowgate Assessment is performed.

Staff to compile comments from the members and draft a response to the request for Limited Operation of a Generator for presentation to the TWG at a later meeting.

Agenda Item 22 – Discussion of Future Meetings

Mo reminded the group of the next scheduled meetings as well as the yet-to-be scheduled conference call to approve the 2015 Flowgate Assessment. Seeing there was no further business, the meeting was adjourned at 11:48 am. Respectfully Submitted, Kirk Hall Secretary

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

Southwest Power Pool, Inc.

TWG NET CONFERENCE

June 3, 2015

Net Conference – Little Rock, Arkansas


1. Approved 2015 Flowgate Assessment Aadditions

2. Approved the 2015 Flowgate Assessment Additionsremovals

3. Approved the TRM values for permanent flowgates




TWG NET CONFERENCE

June 3, 2015


• MINUTES •


TWG Chair Mo Awad called the meeting to order at 9:12 a.m. The following members were in attendance (Attachment 1a, 1b – Attendance, Proxies) or represented by proxy:

Mo Awad, Westar Energy, Inc. Scott Benson, Lincoln Electric System John Boshears, City Utilities of Springfield John Fulton, Southwestern Public Service Co. Joe Fultz, Grand River Dam Authority Travis Hyde, Oklahoma Gas & Electric Randy Lindstrom, Nebraska Public Power District Nate Morris, Empire District Electric Michael Mueller, Arkansas Electric Cooperative Corporation Gimod Olapurayil, ITC Great Plains, proxy for Alan Myers Jim McAvoy, Oklahoma Municipal Power Authority Tim Smith, Western Farmers Electric Cooperative Tony Tong, American Electric Power proxy for Matt McGee Josh Verzal, Omaha Public Power District proxy for Dan Lenihan Harold Wyble, Kansas City Power & Light

Kirk Hall, SPP staff, confirmed that there was a quorum.

Agenda Item 1 – 2015 Flowgate Assessment

Flowgate Additions Kirk began by discussing the work done since the May TWG meeting in Oklahoma City where the action item was to compile all comments from stakeholders and redistribute the change candidates and recalculated TRM values. Kirk stated that the flowgate change candidates and the TRM values send out prior to the meeting had not changed. He asked the members for a motion to approve the flowgate additions identified from the 2015 Flowgate Assessment.

Harold Wyble motioned to accept the flowgate additions identified in the 2015 Flowgate Assessment. Tim Smith seconded the motion which passed unanimously.

John Boshears and John Fulton joined the meeting.

Flowgate Removals Kirk brought up the candidates for removal identified during the 2015 Flowgate Assessment. Nathan McNeil, Westar Energy, voiced Westar’s disagreement with staff’s recommendation for Flowgate 5489 stating that their disagreement comes from the fact that the line cannot physically overload first due to the next segments lower rating, SPP Operations supported the deletion. Kirk let Nathan that staff does agree



with Westar’s opinion, but the process staff follows does not support the removal of that flowgate. As a follow up to staff’s action item to provide the TWG with an education session on the flowgate assessment procedure, staff believes it should revisit its flowgate process to identify potential improvements.

Travis Hyde made a motion to accept the flowgate removals identified in the 2015 Flowgate Assessment. Scott Benson seconded the motion which passed unopposed.

TRM Values Kirk then quickly discussed the TRM values that were provided for approval highlighting that the values for 11 flowgates requested by AEP for recalculation had been recalculated with AEP’s agreement on the new values.

Randy Lindstrom made a motion to approve the recommended TRM values. Travis Hyde seconded the motion. The motion received no opposition.

Members asked staff for a timeline for the educational session and process improvements for the flowgate assessment. Staff stated that the education session is planned to be a topic for the August meeting. Staff would also like to discuss improvements to the process at that time, but there may not be enough time to complete the improvements. Mo also suggested a scope document for the 2016 Flowgate Assessment as a potential improvement. Seeing there was no further business, the meeting was adjourned.

Respectfully Submitted, Kirk Hall Secretary




TWG NET CONFERENCE

June 19, 2015



1. Endorsed the changes to Attachment B.4 of the PRC-023-3 list.

2. Approved the TPL-001-4 Guidance Document

3. Approved the withdrawal of the NTC for the cap banks at Mingo and Ruleton

4. Approved staff’s recommendation to deny a waiver request for the South Waverly 161/69 kV transformer




TWG NET CONFERENCE

June 19, 2015


• MINUTES •


TWG Chair Mo Awad called the meeting to order at 9:12 a.m. The following members were in attendance (Attachment 1a, 1b – Attendance, Proxies) or represented by proxy:

Mo Awad, Westar Energy, Inc. Scott Benson, Lincoln Electric System John Boshears, City Utilities of Springfield John Fulton, Southwestern Public Service Co. Steve Hardebeck, Oklahoma Gas & Electric proxy for Travis Hyde Jody Holland, South Central MCN, proxy for Noman Williams Dan Lenihan, Omaha Public Power District Randy Lindstrom, Nebraska Public Power District Michael Mueller, Arkansas Electric Cooperative Corporation Alan Myers, ITC Great Plains Gayle Nansel, Western Area Power Authority John Payne, Kansas Electric Power Cooperatives Scott Rainbolt, American Electric Power proxy for Matt McGee Rey Rodriguez, Western Farmers Electric Cooperative proxy for Tim Smith Jason Shook, GDS Associates representing ETEC Jeff Stebbins, Tri-County Electric Cooperatives Harold Wyble, Kansas City Power & Light

Kirk Hall, SPP staff, confirmed that there was a quorum.

Agenda Item 2 – PRC-023-3 Endorsement

Blake Poole, SPP staff, reviewed the list of facilities (Attachment 2a, 2b – PRC-023-3 Att B.4, Draft List of PRC-023-3 Att B.4) determined to meet the requirements of Attachment B.4 of PRC-023-3. He highlighted staff’s analysis as well as the feedback received during the review period and requested endorsement from the TWG.

Jason Shook made a motion to endorse the changes to the list of facilities identified on SPP’s PRC-023-3 list. Scott Benson seconded the motion. The motion carried with no opposition.

Agenda Item 3 – Regional Review

Brett Hooton, SPP staff, gave a presentation (Attachment 3 – TWG Regional Review) to the TWG on the ongoing efforts of the SPP/MISO CSP. Members asked a few questions related to the potential projects that have been identified for the regional review.



Action Item: Staff to investigate the ability for the Series Reactor project to be variable instead of fixed with MISO

Agenda Item 4 – TPL Update

2015 TPL Schedule Update

Jason Terhune, SPP staff, updated the members on the progress of the 2015 TPL Schedule (Attachment 4a – TPL-001-4 Steady State Update). TPL-001-4 Guidance Document R.2-R.6, R8 Jason then presented the TPL-001-4 Guidance Document (Attachment 4b – TPL-001-4 Guidance Document for approval from the TPLTF. The members did not request any changes to the document.

Randy Lindstrom made a motion to approve the TPL-001-4 Guidance Document. Harold Wyble seconded the motion, which passed with no opposition.

Agenda Item 5 – NTC Re-evaluation

Dee Edmondson, SPP staff, presented the NTC re-evaluation (Attachment 5 – NTC Re-evaluation) of the Mingo and Ruleton 115 kV cap banks to the group requesting approval for their withdrawal. Members asked about the cost recovery for the cap banks and the previously withdrawn second Mingo 345/115 kV transformer. A question was raised related to a mitigation for the low voltage issues with the loss of the Mingo 345/115 kV transformer. Sunflower informed the group that an Op Guide is in place until the upgrade can be placed in-service.

Action Item: Staff to investigate with regulatory on the cost recovery for the cap banks and transformer. Action Item: Staff to coordinate the sharing of the Transmission Operating Guide for the Mingo 345/115 kV transformer with Jerry Brinkman at Midwest Energy.

Agenda Item 6 – South Waverly 161/69 kV Waiver Request

Michael Odom, SPP staff, presented staff’s evaluation (Attachment 6 – South Waverly 161/69 Waiver Request) of KCP&L’s waiver request for the South Waverly 161/69 kV transformer. Harold Wyble, KCP&L mentioned that the transformer provides benefit to multiple zones and should be considered for a wiaver to the high side voltage cost allocation.

Jason Shook made a motion to accept staff’s recommendation not to approve KCP&L’s waiver request for the South Waverly 161/69 kV transformer. John Fulton seconded the motion. The motion passed with one ‘No’ vote from Harold Wyble and one abstention from Alan Myers.

Agenda Item 7 – NERC Activities Update

Shannon Mickens, SPP staff, presented the current NERC Activities (Attachment 7 – NERC Reliability Standards Activities Update) to the members. The members had no comments or questions. Mo requested any other items that needed to be discussed prior to adjourning the meeting. John Mills, SPP staff, mentioned the two sets of 2016 ITPNT Scenario 0 and 5 models that the TWG would vote to approve. He thought the group should discuss which dispatch should be used in the 2016 ITPNT and 2015 TPL assessments. The group had a short discussion on the differences between the models. Mo asked for staff to form a recommendation prior to the vote and distribute to the members.



Seeing there was no further business, the meeting was adjourned.





TWG NET CONFERENCE

July 22, 2015



1. Approved constraint file for use in the Regional Review

2. Approved the 2015 Flowgate Assessment Report

3. Approved MDWG Charter Revisions




TWG NET CONFERENCE

July 22, 2015


• MINUTES •


TWG Chair Mo Awad called the meeting to order at 9:02 a.m. The following TWG members were in attendance (Attachment 1a, 1b – Attendance, Proxies) or represented by proxy:

Mo Awad, Westar Energy, Inc. John Boshears, City Utilities of Springfield Alan Burbach, Lincoln Electric System proxy for Scott Benson Josie Daggett, Western Area Power Authority proxy for Gayle Nansel John Fulton, Southwestern Public Service Co. Dan Lenihan, Omaha Public Power District Randy Lindstrom, Nebraska Public Power District Jim McAvoy, Oklahoma Municipal Power Authority Matt McGee, American Electric Power Michael Mueller, Arkansas Electric Cooperative Corporation John Payne, Kansas Electric Power Cooperatives Jason Shook, GDS Associates representing ETEC Tim Smith, Western Farmers Electric Cooperative Michael Wegner, ITC Great Plains proxy for Alan Myers Harold Wyble, Kansas City Power & Light

Kirk Hall, SPP staff, confirmed that there was a quorum for the TWG.

Agenda Item 2 – CIP-014-2 Scope Approval

Constraint Assessment Brett Hooton, SPP staff, reviewed the Regional Review Constraint Assessment Update (Attachment 2a – Regional Review Constraint Assessment) and asked for approval of the constraint file. Brett noted that all feedback had been from the stakeholders had been reviewed and incorporated for the file that was posted for the TWG review.

Harold Wyble made a motion to approve staff’s recommendation. Jason Shook seconded the motion. The motion was passed unopposed.

Model Discussion Adam Bell, SPP staff, discussed the models (Attachment 2b –CSP Regional Review) being used for the reliability metrics. Adam described the metrics being calculated for the 3 projects in the Regional Review. A question was raised as to whether voltage issue will be reviewed. Adam replied that they would be accounted for in the No Harm evaluation, but the ESWG approved metrics do not incorporate voltage issues.



Next Steps Adam then discussed the next steps for the Regional Review. The TWG will be given the opportunity to review the metrics results in August at the face-to-face TWG meeting in Denver. Agenda Item 3 – Flowgate Assessment Report Moses Rotich, SPP staff, discussed the 2015 Flowgate Assessment Report. He informed the stakeholders that it was posted for feedback and he received one piece of feedback and had incorporated that into the report and reposted to TrueShare.

Matt McGee made a motion to approve the 2015 Flowgate Assessment as modified. Randy Lindstrom seconded the motion, which passed with no opposition.

Agenda Item 4 – BRR-056 Tony Green, SPP staff, reviewed BRR-056 (Attachment 3 – BRR-056) with the members. He noted that the document was being reviewed for feedback with multiple working groups and that a final approval would be requested at the August face-to-face meeting. Members expressed their viewpoint that the Short-term Reliability process is repetitive since the ITPNT report notes the need dates identified for all projects and questioned the need for this approval since it seems to delay the issuance of NTCs for projects needed very quickly. Tony responded that this is to satisfy requirements in the Tariff for project identified in the Short-Term Reliability Window. Agenda Item 5 – MDWG Charter Revision Anthony Cook, SPP staff, informed the TWG (Attachment 4a, 4b – MDWG Charter, 2016 Series Schedule and Model Selection) of the request by the MDWG to add members to the group. Anthony noted that there was an initial request for 2 seats from members of the IS, but open position had already been filled by a stakeholder from the IS. Anthony requested the TWG approve the charter revision so it could be voted on by the Corporate Governance Committee the following week. Agenda Item 6 – 2017 ITP10 Update Kirk Hall discussed the 2017 ITP10 Update (Attachment 5 – 2017 ITP10 Update). He introduced many items that would need to be discussed at the August face-to-face meeting. These items included determining limits for interfaces monitored at a lower value than their facility rating, consolidation methodology, siting and generator outlet facilities, and the determination of reliability violations. Members discussed how to study the planning limits and agreed with the staff concept. They did, however, point out that determining these limits can be a long process. Staff asked if members had an issue with staff beginning to reach out now to begin work on these issues. Members did not express any concern with staff reaching out now. Before discussion the next agenda items, Kirk asked Jason Davis, SPP staff, to discuss a policy decision made during the July 2015 MOPC meeting. The decision would require SPP to determine non-competitive projects during the study process and send all non-competitive projects to the incumbent TO for cost estimation purposes. Jason informed the group that this would most likely impact the TWG and the TOs resources since they would be required to come up with the cost estimates during the study process. Jason also pointed out that it would compress the study timeline and information may be made available to the stakeholder later in the process. Members expressed no issues with this addition to the ITPNT schedule. Agenda Item 7 – TRR-067 Ken Quimby, SPP staff, reviewed TRR – 067 for the stakeholders (Attachment 6 – TRR-067) which updates tariff language to describe more accurately SPP’s process for re-dispatching the market prior to transmission service upgrades being placed in-service. Members generally agreed with the approach that the Integrated Market is a more efficient and economic avenue for determining redispatch until



upgrades are completed. It was determined that this TRR should be reviewed again and approved during the August face-to-face TWG meeting. Agenda Item 8 – TRR-071 Ken the reviewed TRR-071 (Attachment 7a, 7b – TRR-071, SIS with Counteroffer). Due to time constraints this item was determined to be discussed during the August TWG face-to-face meeting. Seeing there was no further business, the meeting was adjourned.




August 18-19, 2015

Magnolia Hotel – Denver, CO

• A G E N D A •

Tuesday 8:00 a.m. – 5:00 p.m.

1. Administrative Items ................................................................................................. Mo Awad (10 min.) a. Call to Order b. Proxies c. Antitrust Guidelines d. Previous Meeting Minutes (Action Item)

i. May 19-20, 2015 TWG Face-to-Face Meeting Minutes ii. June 3, 2015 TWG Net Conference Meeting Minutes iii. June 19, 2015 TWG Net Conference Meeting Minutes iv. July 6, 2015 Joint TWG/RCWG Net Conference Meeting Minutes v. July 22, 2015 TWG Net Conference Meeting Minutes

e. Agenda review (Action Item) f. Meeting Materials

2. Review of Past Action Items ...................................................................................... Kirk Hall (10 min.)

3. MOPC/Board Update ............................................................................................... Mo Awad (10 min.)

4. TPITF Update and Discussion ...................................................................................... Mo Awad (1 hr.) a. Standardization of NT/TPL scopes in ITP Manual b. Discussion on Scenario 0 vs Scenario 5 c. Combining the TPL with the ITP d. Use of CBA model in TPL Assessment e. Modeling of DC ties from most constraining perspective

5. Tariff Revision Requests .................................................................................... Matt Harward (30 min.)

a. TRR-067 (Action Item) b. TRR-071 (Action Item)

..................................................................................................................................................................... 5.6. 2015 NERC Assessments Update ................................................................................... Staff (30 min.)

a. Steady State Assessment Update – Jason Terhune b. Stability Assessment Update – Doug Bowman c. Short Circuit Update – William Holden

6.7. CIP-014-2 Scope (Action Item) ..................................................................... Jonathan Hayes (30 min.) 7.8. Fast Fault Benchmarking ................................................................................. Doug Bowman (30 min.) 8.9. Market Impacts of Transmission Expansion ............................................... Catherine Mooney (30 min.)

Formatted: No bullets or numbering

9.1. Tariff Revision Requests .................................................................................... Matt Harward (30 min.)

a. TRR-067 (Action Item) a. TRR-071 (Action Item)

10. TWG Reports ...................................................................................................................... All (45 min.)

a. TPLTF Update – Jason Terhune b. MDWG Update – Nate Morris c. AQITF Update – Jim McAvoy d. 2015 TWG Work Schedule – Kirk Hall e. MITF Disbandment – Kirk Hall (Action Item)

11. SPP Website Update ..................................................................................... Derek Wingfield (15 min.)

12. Generator Interconnection Update ................................................................. Charles Hendrix (30 min.)

a. Limited Operations of GIs Recommendation (Action Item) – Charles Hendrix b. NRIS Update

13. Flowgate Update ................................................................................................................. Staff (1 hr.)1 lowgate Update ................................................................................................................... Staff (1 hr.)1

a. WAPA Flowgate Assessment TRM Approval – Champy Gahagan (Action Item) b. DC Tie Flowgate Removal – Will Tootle (Action Item) c. Flowgate Educational Session – Moses Rotich

Wednesday 8:00 a.m. – 12:00 p.m.

14. Regional Review of Potential Interregional Projects ....................... Jason Speer/Brett Hooton (15 min.)

15. RR – 056 BRR-066 (Action Item) ......................................................................... Tony Green (30 min.)

16. Reliability Project Selection Metrics ............................................................................ Michael (30 min.)

17. 2016 ITPNT Update ............................................................................................................. Staff (1 hr.)

a. Non-Competitive Cost Estimates Discussion b. 2016 ITPNT Scope Modification (Action Item)

18. Non-Transmission Solution Submission ..................................................................... Kirk Hall (30 min.)

19. Non-Standard Project Evaluation ............................................................................... Kirk Hall (30 min.)

20. 2017 ITP10 Discussion .................................................................................................... Staff (15 min.)

1 Closed Session, Separate Dial-In and WebEx information will be distributed, all materials posted to SPP’s TrueShare under TWG Confidential and Protected > Flowgate Assessment > 2015 Flowgate Assessment

21. NERC Standards Group Update ................................................................... Shannon Mickens (5 min.)

22. Interconnection Updates ....................................................................................................... All (5 min.)

23. Summary of Action Items ............................................................................................. Kirk Hall (5 min.)

24. Discussion of Future Meetings ................................................................................... Mo Awad (2 min.) a. Net Conference – September 16, 2015 b. Net Conference – October 21, 2015 c. Face-to-Face – November 17-18, 2015: Little Rock, AR

Southwest Power Pool, Inc.TRANSMISSION WORKING GROUP

Action Item Status Report

Item Date Originated Action Item Updates

Status(Not

Started, In Progress, Closure Pending, On Hold, Closed)

Owner Notes/Comments

33 August 21-22, 2012

RTO and RE staff to work with the MDWG to address data reporting requirements and enforceability for merchant/independently-owned generation and transmission assets. Define 1) who is responsible for the data exchange, 2) when data exchange is required, 3) how to enforce the exchange of data.

April 01, 2015: The new MOD-032-1 standard specifically requirements R1 (07/01/2015 effective date) and R2 (07/01/2016 effective date) will help answer this action item.

R1. Each Planning Coordinator and each of its Transmission Planners shall jointly developsteady-state, dynamics, and short circuit modeling data requirements and reportingprocedures for the Planning Coordinator’s planning area that include: [Violation RiskFactor: Lower] [Time Horizon: Long-term Planning] 1.1. The data listed in Attachment 1. 1.2. Specifications of the following items consistent with procedures for building the Interconnection-wide case(s): 1.2.1. Data format; 1.2.2. Level of detail to which equipment shall be modeled; 1.2.3. Case types or scenarios to be modeled; and 1.2.4. A schedule for submission of data at least once every 13 calendar months. 1.3. Specifications for distribution or posting of the data requirements and reporting procedures so that they are available to those entities responsible for providing the data.

R2. Each Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner,Transmission Owner, and Transmission Service Provider shall provide steady-state,dynamics, and short circuit modeling data to its Transmission Planner(s) and PlanningCoordinator(s) according to the data requirements and reporting proceduresdeveloped by its Planning Coordinator and Transmission Planner in Requirement R1.For data that has not changed since the last submission, a written confirmation thatthe data has not changed is sufficient

In Progress MDWG

37 August 21-22, 2012Staff to work with volunteers to develop language to add to Appendix 11.

Staff has sought volunteers’ opinions on topic. Currently working on draft language.In Progress Kirk Hall

Review old HVDC interconnection agreements for baseline language

86 November 18-19, 2013Staff to work on scoping study to analyze the reactive requirements on the system

May 20-21, 2014: Brought scope to the TWG in May. TWG requested some additional detail to be provided before approving the scope for RFP Issuance.

Closed

89 November 18-19, 2013Staff to share AQ Improvement Task Force revised tariff language as well as the business practice before taking it to the MOPC

May 20-21, 2014: TWG did not agree with what the RTWG approved and remanded additional work to the AQITFMay 18-19, 2015: AQITF was revived In Meeting

AQITF Update: Agenda Item 10c

106 February 11-12, 2014SPP Staff to develop a whitepaper for all 3 possibilities on how to deal with upgrades to de-rated facilities, including costs and consequences

In ProgressContinue forward with this issue based upon internal SPP direction

119 May 20-21, 2014SPP Staff to research effects of Criteria 12.2 removal on cost allocation

August 5, 2015: Research underway with legal and other key staffIn Progress

123 August 12-13, 2014

Staff to overlay the proposed ITPNT schedules with the TWG work schedule

February 10, 2015: Staff has worked through the 2016 ITPNT schedule and is in the process of reviewing other Planning Schedules to ensure members input periods have been taken into account and will not overlap. November 11, 2014: The 2016 ITPNT schedule is currently under development. As soon as it is finalized this information will be made available for members

Complete

Agenda Item 10d

127 August 12-13, 2014Staff to look into cost for 3rd party review May 12, 2015: SPP has worked to create study template for study submission. TWG directed SPP to act as the 3rd

party reviewer while not affecting the administration fee. August 11, 2015: RCWG voted to approve the draft version of the CIP-014-2 Scope

In Meeting Aaron StewartAgenda Item 6

130 December 18, 2014

Staff to review Criteria 4 and add specificity as it relates the TWG's ability to approve flowgates and also coordinating JOA language updates if necessary to be presented at the April MOPC

May 12, 2015: Legal is reviewing TWG's request as it relates to this issue. August 11, 2015: SPP Legal - The Tariff requirements relate to TOs adding flowgates and would not be applicable to MISO flowgates

Complete Will Tootle/Kirk Hall

131 December 18, 2014Staff to present on the Fast Fault Screening Tool and provide a comparative analysis of the tool at the February TWG meeting

August 11, 2015: Doug presented an educational session on the FFS Tool at the May TWG meetingIn Meeting Doug Bowman

Agenda Item 7

133 February 17-18, 2014Staff/TPL TF to request documentation of each member’s spare equipment strategy

August 11, 2015: Members' long lead time equipment has been accounted for to remain compliant with the TPL-001-4 standard

Complete

141 March 25, 2015Staff to follow up on determining if SPP Criteria 3.5 conflicts with BPR-059

In progress

142 March 25, 2015Staff to investigate whether local planning criteria is considered CEII

In progress

143 May 18-19, 2015Staff to examine how FACTS devices, HVDC lines, and other exotic projects could be evaluated fairly in the competitive Order 1000 process and develop a process for evaluation

In MeetingAgenda Item 19

144 May 18-19, 2015TPLTF to modify its charter to account for TPL-007-1 and present to the TWG at the June TWG Net Conference

In Progress Jason Terhune

145 May 18-19, 2015 Staff to identify IROLs for Planning and Operations separately August 11, 2015: Planning IROLs will be identified through FAC-014 analysis Complete Aaron Stewart In relation to CIP-014-2

147 May 18-19, 2015Staff to provide the TWG with an educational session on how the Flowgate Assessment is performed

In Meeting Moses RotichAgenda Item 12c

148 May 18-19, 2015Staff to compile comments from the members and draft a response to the request for Limited Operation of a Generator for presentation to the TWG at a later meeting

In Meeting Charles HendrixAgenda Item 13a

149 June 19, 2015Staff to investigate the ability for the Series Reactor project to be variable instead of fixed with MISO

In Progress

Page 1 of 2

Southwest Power Pool, Inc.TRANSMISSION WORKING GROUP

Action Item Status Report

Item Date Originated Action Item Updates

Status(Not

Started, In Progress, Closure Pending, On Hold, Closed)

Owner Notes/Comments

150 June 19, 2015Staff to coordinate the sharing of the Transmission Operating Guide for the Mingo 345/115 kV transformer with Jerry Brinkman at Midwest Energy

In Progress Dee Edmondson

151 June 19, 2015Staff to investigate with regulatory on the cost recovery for the cap banks and transformer

August 11, 2015: Staff followed up with the Regulatorty Department and determined that the previously withdrawn Mingo 345/115 kV transformer is not in the RRR file. Also no cost recovery for the Mingo and Ruleton 115 kV cap banks.

Complete Dee Edmondson

Page 2 of 2

TPITF ‐ ITP Assessment Scope TemplateAugust 6, 2015

Working Group Involvement

• ESWG • TWG• CAWG• SSC• RARTF

• RSC• MOPC• SPC• BOD

Stakeholder Review• Load Forecast• Generator Review• Renewable Survey• Policy Survey• Economic/Power Flow Model

• Sensitivity Analysis• GOFs• Solutions• Benefit Metrics

• Generation/ Conventional Resource Plans

• Futures• Reliability Assessment• Constraint Assessment• Policy Assessment• Economic Assessment• Transmission Plan Development

• Report

Study Process

• TBD

Data Inputs• Economic model• Economic model generation parameters

– Startup cost, operating costs, Min/Max Operating Levels, etc.

• Market structure– The Integrated Marketplace and CBA will be baseline assumptions– No market, individual BA scenario based models (Scenario 0 & 5)

• Futures– Set of assumptions representing potential future system characteristics

• Environmental policy (CPP, emissions)– Emission price forecasts for SO2, NOX, and CO2 for the study year

• Load Forecasts– Coincident/non‐coincident peak load

• System topology – Approved ITPNT model set +…– Necessary modifications

Data Inputs cont.• Transmission service

– Market simulation substitutes firm transmission scheduling– Account for confirmed long‐term transmission service (S0 & S5)

• CBA– Account for the impacts of the Integrated Marketplace

• Resource plans• Renewables

– Hourly generation profiles for renewable generation, primarily wind, hydro, solar, and bio‐fuel

• Siting– Expected location of future generation

• DC ties and lines– WECC, ERCOT, and Eastern Interconnect systems

Data Inputs cont.• Fuel prices

– Ventyx Reference Case, NYMECX, DOE Annual Energy Outlook

• Policy survey– New and existing wind capacity

• Renewable survey– Renewable energy totals for model years based on state and utility

mandates and goals

• Hurdle rates– Set as needed to model minimal and reasonable exchange between

SPP and neighboring systems

• Benchmarking– Economic model benchmarked against historical system behavior to

assess the reasonability of the simulations

Data Inputs cont.• Generation resources

– Unit Retirements

• Exports/imports ‐ first tier – AC systems will be determined by the economic dispatch model.

Exports and imports between – DC interconnections will be based on historical hourly scheduling of

long‐term firm transmission service

Analysis• Define constraints

– Identification of congested facilities and by performing transfer analyses

• Needs assessments – economic/policy/reliability• DPP window• Cost estimates

– Conceptual and Study• Solution development – economic/policy/reliability • Interregional considerations

– SPP will collaborate with neighboring entities regarding the identified needs, benefits, potential solutions, and costs

• Final portfolio– Reliability, policy, and economic solutions will be grouped together

and refined to create a portfolio for each future and consolidated into a single portfolio

• 40‐year financial analysis– Assess the cost effectiveness of the recommended portfolio over a

forty‐year time horizon in accordance with Section III.3.c of Attachment O

Analysis• Benefit metrics

– Used to measure the value of the final portfolio • Sensitivities

– Natural gas price, Demand levels, Increased input prices• Staging

– Final portfolio structured such that each element can be implemented in a staged manner as actual system developments approach the assumptions resulting in the need for that element

• Reactive needs– If any 300 kV and above upgrades are identified as solutions in the

portfolio, line‐end reactive requirements analysis will be performed for the new transmission lines greater than 300 kV system to provide an indicative amount of reactor needs before design level studies are completed

• Stability assessment• NERC TPL‐001‐4*

– Identify potential violations using the NERC TPL‐001‐4 standard Table 1 planning events that do not allow for non‐consequential load loss or curtailment of firm transmission service

TPITF Scope of Activities#3: The appropriateness of planning cycle assessments, including but not limited to:

• The effectiveness of using production cost modeling in more assessments;

• Development, use, and weighting of futures, scenarios, and sensitives;

• The metrics used to evaluate proposed projects, in particular those that evaluate the impact on rate payers; and

• Planning the transmission system beyond traditional planning criteria of first contingency (N‐1) in accordance with the approved NERC Standard TPL‐001‐4

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Revision Request Recommendation Report

RR #: 67 Date: 6/11/2015

RR Title: Firm Service with Redispatch Clean Up

SUBMITTER INFORMATION

Submitter Name: Steve Purdy and Matt Harward Company: SPP

Email: [email protected]; [email protected] Phone: 501-688-1757; 501-614-3371

OBJECTIVE OF REVISION

This RR removes outdated language related to transmission service requests (TSRs) subject to redispatch. There are multiple references to the Transmission Provider’s responsibilities with respect to offering redispatch options to TSRs. Many of the references are rendered obsolete as a result of the operation of the Integrated Marketplace. Under the market structure, all resources are already involved in a system-wide “redispatch” as a part of the Security Constrained Economic Dispatch algorithm. Any redispatch costs incurred to relieve a system constraint is collected and paid as part of Integrated Marketplace settlements and procedures described under Attachment AE. FERC approved that transmission customers having Firm Point-To-Point Transmission Service subject to redispatch are eligible to nominate Candidate Auction Revenue Rights associated with that service only for those times of the year and for only the amounts of service that are not subject to redispatch. This RR removes outdated language and replaces it with language consistent with existing practices and points to Attachment AE

EXECUTIVE SUMMARY AND RECOMMENDATION

IMPACT ANALYSIS REQUIRED: Yes No

Estimated Cost: $ Cost is a rough order of magnitude estimate, approx. +/-50%

Estimated Duration: months Duration is a rough order of magnitude estimate, approx. +/-50%

Priority Rank for System Change: 1 – Critical 2 – High 3 – Medium 4 – Low

SPP DOCUMENTS IMPACTED

Market Protocols Protocol Section(s): Protocol Version:

Criteria Criteria Section(s): Criteria Date:

Tariff (OATT) Tariff Section(s): 13.5, 27, 34.6, Attachments K, Z1 and F; Schedule 7

Business Practice Business Practice Number: WORKING GROUP REVIEWS AND RECOMMENDATIONS

List Primary and any Secondary/Impacted WG Recommendations as appropriate

Primary Working Group: RTWG

Date: 6/25/2015

Vote: Approved

Abstained: OPPD, NPPD, Westar

Opposed:

Reason for Opposition:

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Secondary Working Group:

Date:

Vote:

Abstained:

Opposed:

Reasons for Opposition:


Date:

Vote:

Abstained:

Opposed:



Date:

Vote:

Abstained:

Opposed:


MOPC Recommendation:

Date:

Vote:

Abstained:

Opposed:


BOD/Member Committee Recommendation:

Date:

Vote:

Abstained:

Opposed:


COMMENTS

Comment Author:

Description of Comments:

Status:

Comment Author:

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Status:

PROPOSED REVISION(S) TO SPP DOCUMENTS

Market Protocols

Tariff (OATT)

Proposed Tariff Language Revisions (Redlined)

ATTACHMENT K

REDISPATCH PROCEDURES AND REDISPATCH COSTS

I. Redispatch to Accommodate a request for Firm Transmission Service

A. Purpose

This Procedure shall apply only to entities that, when applying for Firm Point-To-Point or

Network Integration Transmission Service, were told that the service could be provided only if redispatch

occurs, and that agreed to pay redispatch costs. If an entity in these circumstances does not agree to pay

redispatch coststhe limited Auction Revenue Rights or Long-Term Congestion Rights as provided in

Section 13.5 of this Tariff, then its request for Firm Point-to-Point or Network Integration Transmission

Service will be denied in whole or in part. To the extent the Transmission Provider can relieve any

system constraint for Firm Point-To-Point or Network Integration Transmission Service through operation

of the Energy and Operating Reserve Markets described in Attachment AE of this Tariffby redispatching

the generation resources of the Transmission Owner(s) or other willing generators, it shall do so, provided

that the Eligible Customer agrees to compensate the Transmission Providerthe limitations on Auction

Revenue Rights and Long-Term Congestion Rights pursuant to the terms of Section 27 13.5 of this Tariff

and this procedure. The procedure under this Section I is not for the purpose of sustaining non-firm

service.

B. Obligations

The Transmission Provider shall arrange for the redispatch of the generation resources of the

Transmission Owner(s) or other willing generators for the stated purpose. As a condition precedent to

receiving Firm Point-to-Point or Network Integration Transmission Service, a Transmission Customer

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agrees to pay (1) the applicable Transmission Service charges described in Schedules 1 through 11; and

(2) the actual redispatch cost necessary to relieve transmission constraints. To the extent practical, the

redispatch of all such resources shall be on a least cost

basis. The total charges to be paid by the Transmission Customer under this Tariff shall not

exceed the total charges the Transmission Customer would have paid under the Transmission Service

Tariffs of the Transmission Owners for the Transmission Service in the same amount from the same Point

of Receipt to the same Point of Delivery unless any additional charges to the Transmission Customer are

permitted by Commission policy.

CB. Assessment Process

Upon receipt of an Application for Firm Point-to-Point or Network Integration Transmission

Service, the Transmission Provider shall make a determination of the availability of the requested Firm

Transmission Service. The Transmission Provider's Security Coordination Center will identify

transmission constraints utilizing generally accepted power system analysis techniques. Where the

requested Firm Transmission Service is determined to be not fully available because of transmission

constraints, then the Transmission Provider will assess the need for redispatch of generation.

The procedure to be implemented is as follows:

1. Determine the available transmission capacity for the requested Firm Transmission Service

utilizing a load flow computer simulation of the transmission system recognizing all firm uses of

the system.

2. Determine the owned generation resources of the Transmission Owners or others that will relieve

the transmission constraint and the amount of transmission capacity available through redispatch.

3. The Transmission Provider shall inform the Eligible Customer if the Transmission Provider

concludes that redispatch can sustain the requested Firm Transmission Service.

4. Any disputes as to compensation for service under this Tariff shall go to dispute resolution in

accord with the provisions of this Tariff.

DC. Redispatch Costs

If redispatch services are provided pursuant to this Attachment K, the Transmission Provider will

in good faith attempt to relieve the constraint through operation of the Energy and Operating Reserve

Markets described in Attachment AE of this Tariff. Costs associated with redispatch services shall be

collected and paid in accordance with the Energy and Operating Reserve Markets settlement procedures

described in Attachment AE of this Tariff.

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II. POINT-TO POINT TRANSMISSION SERVICE

13.5 Transmission Customer Obligations for Facility Additions or Redispatch Costs:

In cases where the Transmission Provider determines that the Transmission System is not

capable of providing Firm Point-To-Point Transmission Service without (1) degrading or impairing the

reliability of service to Native Load Customers, Network Customers and other Transmission Customers

taking Firm Point-To-Point Transmission Service, or (2) interfering with a(the) Transmission Owner's(s’)

ability to meet prior firm contractual commitments to others, the relevant Transmission Owner(s) will be

obligated to expand or upgrade its (their) Transmission System(s) pursuant to the terms of Section 15.4 of

this Tariff. The Transmission Customer must agree to pay the Transmission Provider for any necessary

transmission facility additions pursuant to the terms of Section 27 of this Tariff. Network Upgrade or Direct

Assignment Facilities costs to be charged to the Transmission Customer on an incremental basis under the

Tariff will be specified in the Service Agreement prior to initiating service. To the extent that the

Transmission Provider can relieve a system constraint by redispatching resources registered to participate

in the Energy and Operating Reserve Markets, it shall do so, provided that the Eligible Customer agrees to

compensate the Transmission Provider pursuant to the terms of Section 27. Any redispatch, Network

Upgrade or Direct Assignment Facilities costs to be charged to the Transmission Customer on an

incremental basis under the Tariff will be specified in the Service Agreement prior to initiating service.

Any redispatch costs incurred to relieve a system constraint to be charged to the Transmission Customer

shall be calculated collected and paid as part of the Energy and Operating Reserve Market settlement

procedures described under Attachment AE of this Tariff. Transmissions customers having Firm Point-To-

Point transmission serviceTransmission Service with subject to redispatch obligations will be eligible to

nominate Candidate Auction Revenue Rights associated with that service only for those times of the year

and for only the amounts of service that are not subject to the redispatch obligation. A Long-Term

Congestion Right is a year-long product entitling its owner to a Transmission Congestion Right that covers

the period from the month of June through the following month of May. Accordingly, Long Term Firm

Transmission Service with a redispatch requirement will not be eligible for any Candidate Long-Term

Congestion Rights because it does not have continuous service covering the entirety of the associated

Transmission Congestion Right year.

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27 Compensation for New Facilities and Redispatch Costs

a) Whenever an Aggregate Facilities Study performed by the Transmission Provider in

connection with the provision of Long-Term Firm Point-To-Point Transmission Service identifies the

need for new facilities, the recovery of such costs shall be governed by Attachments J and Z1 of this

Tariff. Whenever an Aggregate Facilities Study performed by the Transmission Provider in connection

with the provision of Long-Term Firm Point-To-Point Transmission Service identifies capacity

constraints that may be relieved by redispatching electric generating resources to eliminate such

constraints, redispatch will be handled in accordance with Attachment K of this Tariff. The Transmission

Customer shall be responsible for the redispatch costs as detailed in Schedule 7 and as determined by the

procedures in Attachment K.

b) Whenever a System Impact Study performed by the Transmission Provider in connection

with the provision of Short-Term Firm Point-To-Point Transmission Service identifies capacity

constraints that may be relieved by redispatching electric generating resources to eliminate such

constraints, redispatch will be handled in accordance with Attachment K of this Tariff. The Transmission

Customer shall be responsible for the redispatch costs as detailed in Schedule 7 and as determined by the

procedures in Attachment K.

34.6 Network Customer Obligations for Redispatch ChargeCosts:

The Network Customer shall pay redispatch costs associated with its transactions through the

operation and settlement of the Energy and Operating Reserve Markets as described in Attachment AE of

this Tariff. Network Customers having service subject to redispatch will be eligible to nominate Candidate

Auction Revenue Rights and Candidate Long-Term Congestion Rights associated with that service.

SCHEDULE 7

LONG-TERM FIRM AND SHORT-TERM FIRM POINT-TO-POINT TRANSMISSION SERVICE

The Transmission Customer shall compensate the Transmission Provider each month for

Reserved Capacity at the sum of the applicable charges set forth below in addition to other applicable

charges specified in the Tariff. All effective rates under this schedule shall be posted on the SPP

OASIS.

[Excerpted]

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3. Redispatch Costs: The redispatch costs shall be calculated in accordance with the

formula and protocols shown on Attachment K.

ATTACHMENT Z1

AGGREGATE TRANSMISSION SERVICE STUDY PROCEDURES AND COST ALLOCATION AND RECOVERY FOR SERVICE UPGRADES

IV. Cost Allocation for Service Upgrades

The cost of Service Upgrades shall be allocated in accordance with this Section.

a. For the purpose of determining the cost responsibility for each transmission service

request, all upgrades required to provide transmission service for all transmission service

reservations included in an Aggregate Facilities Study shall be included in an Aggregate

Cost Allocation Assessment. The cost of each transmission upgrade component will be

allocated to each customer in the aggregation group on a pro-rata impact basis as

provided in paragraph b. With regard to the cost allocation, the Transmission Provider

shall review all upgrades and determine the earliest date that each upgrade is required to

be in-service in order to provide the requested transmission service. This date is the Date

Upgrade Needed. The cost of a facility upgrade shall be allocated to all customers in the

aggregate group whose reservation period begins after the Date Upgrade Needed or

extends past the Date Upgrade Needed, whether or not an interim redispatch option is

available. If the Date Upgrade Needed for the upgrade is after completion of service, no

cost will be allocated to the customer for the upgrade under consideration.

All requests that have a positive impact on the upgrade and for which the service has not

been completed prior to the Date Upgrade Needed for such upgrade, shall be allocated

costs for the upgrade; and the Transmission Provider shall review these requests in order

to determine the amortization period for the facility. For this determination, the start date

of the amortization period shall be the expected in-service date of the facility. The end

date for the amortization period shall be the end of the term of the request that ends at the

latest point in time as adjusted for deferral of any requests.

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In the event the expected in-service date of the upgrade is after the Date Upgrade Needed,

the customers whose requests span a portion of the time between the Date Upgrade

Needed and the expected in-service date may:

1. Defer the start of the request until the expected in-service date of the upgrade; or

2. Request interim redispatch, if available.

If the customer selects the interim redispatch option, the Transmission Provider will

evaluate curtailment of existing confirmed service or interim redispatch of units to

provide service prior to completion of any allocated network upgrades. The

Transmission Provider will provide the top 100determine whether a feasible redispatch

pairs, if available,solution exists to relieve the incremental MW impact on the limiting

facilities. This redispatch option will be used to allow the customer to begin transmission

service based on an earlier start date than the deferred date. Redispatch services shall be

provided in accordance with Attachment K of the this Tariff.

SPP Criteria

SPP Business Practices


RR #: 71 Date: 6/26/2015

RR Title: Revisions to Reflect System Impact Study Process Under Integrated Marketplace


Submitter Name: Matt Harward Company: SPP

Email: [email protected] Phone: 501-614-3560


Describe the problem/issue this revision request will resolve.

With the implementation of the Integrated Marketplace, the process for studying and granting short-term service has changed. The current Tariff reflects the old process; therefore, the current language describing the System Impact Study process for short-term service requests is obsolete and does not accurately describe the process.

Describe the benefits that will be realized from this revision.

Revisions proposed in RR 71 will update the tariff language in the target sections to accurately reflect the current methodology SPP utilizes to process requests for short-term service, including the System Impact Study process when insufficient capacity on the transmission system exists to grant the request. The proposed Tariff language also clarifies when counteroffers for partial service may be offered by SPP within the context of the overall process.

EXECUTIVE SUMMARY AND RECOMMENDATION

This Revision Request will update the process for studying and granting short-term service and clarifies when counteroffers for partial service may be offered by SPP within the context of the overall process.








Tariff (OATT) Tariff Section(s): Section 19.2 and 32.2, Attachments D and AC

Business Practice Business Practice Number: WORKING GROUP REVIEWS AND RECOMMENDATIONS


Primary Working Group: RTWG

Date: 6/25/2015

Vote: Unanimously Approved

Abstained: NA

Opposed: NA


Date:

Vote:

Abstained:

Opposed:



Date:

Vote:

Abstained:

Opposed:


MOPC:

Date:

Vote:

Abstained:

Opposed:


BOD/Member Committee:

Date:

Vote:

Abstained:

Opposed:


COMMENTS

Comment Author:


Status:

Comment Author:


Status:


Market Protocols

NA

Tariff (OATT)

19.2 System Impact Study Agreement and Cost Reimbursement:

The Eligible Transmission Customer’s completion of the OASIS

reservation with the following statement in the customer comment field “exercise

System Impact Study option” shall provide the Transmission Provider with the

required notification to that the TransmissionEligible Customer’s elects to move

forward with the System Impact Study optionconsider the reservation a Qualifying

Request, as defined provided in Attachment AC of this Tariff. Completing the

reservation in this manner constitutes Eligible Customer’s agreement to pay for all

System Impact Studies necessary to support the evaluation of the service.

32.2 System Impact Study Agreement and Cost Reimbursement:

The Eligible Customer’s completion of the OASIS reservation with the

following statement in the customer comment field “exercise System Impact

Study option” shall provide the Transmission Provider with the required

notification to consider the reservation a Qualifying request. Completing the

reservation in this manner constitutes Eligible Customer’s agreement to pay for

all System Impact Studies necessary to support the evaluation of the service.

ATTACHMENT D METHODOLOGY FOR COMPLETING A SYSTEM IMPACT STUDY

Upon receipt of a TransmissionEligible Customer’s Completed Application for Short-

Term Service and non-firm Transmission Service requests of less than one year, the Transmission

Provider will evaluate the request in accordance with the provisions of Attachment C of this Tariff

to determine whether sufficient transmission capacity exists to satisfy the request.determine

whether transmission transfer capability ("Available Transfer Capability" or "ATC") will be

available to accommodate the transmission service requested in such Application by applying the

criteria and practices described in Attachment C to this Tariff. If sufficient transmission ATC will

capacity exists to support the transaction described in the Eligible Customer's Applicationrequest,

as supplemented with necessary details such as the sources and sinks of the power to be scheduled

under the request, the Transmission Provider will so inform the Eligible Customeraccept the

reservation. If the Transmission Provider determines that existing transmission ATC capacity is

insufficient to provide the requested service, the Transmission Provider will initiate the

Rreservation Pprocessing Mmethodology pursuant to Section 3 of Attachment AC of theisthis

Tariff, and perform a System Impact Study, if requested by the TransmissionEligible Customer in

accordance with Sections 19.2 and 32 of theisthis Tariffnotify the Eligible Customer.

Upon a request by the Eligible Customer, the Transmission Provider will tender a Study

Agreement to the Eligible Customer for a System Impact Study.

Upon receipt of a completed System Impact Study Agreement, the Transmission Provider,

in coordination with the affected Transmission Owners, will perform a System Impact Study to

determine whether the request for transmission service can be accommodated through construction

of Direct Assignment Facilities or Network Upgrades or through redispatch, if available. The

System Impact Study will provide an estimate of the cost of redispatch. The System Impact Study

will provide (i) information about the system constraints that prohibit Transmission Provider’s

acceptance of the requested service; and (ii) whether redispatch will permit Transmission Provider

to accept the reservation. The Transmission Provider shall post the results of the sSystem iImpact

sStudy on the OASIS.

If the studies predict that a constraint will occur in the system of a non-SPP transmission

provider or external Balancing Authority Area, the Transmission Provider will so inform the

Eligible Customer requesting service. The Transmission Provider and Eligible Customer will need

to work with the appropriate parties to determine if the limitation is valid and to determine the

facility additions or redispatch that may be required by others to support the transfer. The Eligible

Customer requesting service shall have the option to reduce the request to a level that can be

sustained without experiencing the constraint.

System Impact Studies are not performed for Long-Term Service requests. Long-Term

Service requests are evaluated through an Aggregate Facilities Study in accordance with the

procedures set forth in Attachment Z1 toof this Tariff.

ATTACHMENT AC RESERVATION PROCESSING METHOD FOR SHORT TERM FIRM

TRANSMISSION SERVICE SHORT-TERM SERVICE- SYSTEM IMPACT STUDY PROCESS

1. IntroductionShort-Term Service Request and Initial Validation

1.1. Definitions

1.1.1. Qualifying Request – a daily, weekly or monthly request for short-term

firm transmission service for which Customer has requested the application of this processing

method pursuant to the notification requirements set out below.

1.1.2. Qualifying Redispatch Options – any generation redispatch provisions,

confirmed firm service curtailment provisions, or combination thereof.

1.2. Nature of the Process

This Reservation Processing Method For Short Term Firm Transmission Service provides

the standard evaluation process applied to daily, weekly and monthly firm transmission

service requests and an associated mechanism for administration of related energy

schedules. A request for Short-Term Service may be submitted by a TransmissionEligible

Customer on the Transmission Provider’s OASIS in the following increments: Daily,

Weekly, and Monthly. Upon receipt of the TransmissionEligible Customer’s request for

Short-Term Service the Transmission Provider will evaluate the request in accordance with

the provisions of Attachment C of this Tariff to determine whether sufficient

systemtransmission capacity exists to satisfy the request. A Short-Term Service request

that passes such initial validation will be accepted by the Transmission Provider within the

timeframes provided in Attachment P of this Tariff.

Customers requesting daily, weekly and monthly short term firm transmission service will have

the opportunity to request, obtain and pay for system impact studies that provide information about

the system constraints that prohibit Transmission Provider’s acceptance of the requested service

and redispatch options that may alleviate those constraints. Additionally, customer response time

requirements will be adjusted to provide an opportunity for Customer to contract for any redispatch

mitigation necessary for Transmission Provider’s acceptance of the requested service.

2. Requests that Fail Initial Validation

2.1 System Impact Study Option

3. Reservation Processing Provisions

3.1. Customer Request for Application of These Procedures

This Reservation Processing Method For Short Term Firm Transmission Service will be

used to process short-term firm requests upon notification by Customer requesting the

service. Short-Term Service requests that do not pass initial validation will be processed

in accordance with Section 3 of this Attachment AC of this Tariff if requested by the

TransmissionEligible Customer. Such requests shall be made by the TransmissionEligible

Customer notification shall be made only by including the following statement in the

customer comment field of such reservation: “exercise sSystem iImpact sStudy option.” In

accordance with the provisions of Section 19.2 of this Tariff. Entry of this comment

constitutes customer’s agreement to pay for all sSystem iImpact sStudies necessary to

support the evaluation of this service. Such request will, by this notification, become a

Qualifying Request.

2.2 Counteroffer

Short-Term Service requests that do not pass initial validation and where the

TransmissionEligible Customer does not exercise the System Impact Study option shall be

reviewed by the Transmission Provider to determine if partial service can be offered. If

partial service can be offered the Transmission Provider shall counteroffer the available

transmission capacity to the TransmissionEligible Customer.

3. System Impact Study Process

3.12. Initial Feasibility Analysis

Upon receipt of such Qualifying Request, SPPFor Short-Term Service requests that do not

pass initial validation and where the TransmissionEligible Customer has exercised the

System Impact Study option, the Transmission Provider shall conduct an initial analysis of

the feasibility of such reservation request at no cost to the TransmissionEligible cCustomer.

This preliminary study will be posted on the SPP OASIS web site. Such reservation request

shall be deemed feasible if: (1) the number of internal flowgate constraints areis three or

less; and (2) either (i) the Available Flowgate Capacity required is either (i) the lesser

thanof the TRM Value minus the transmission capacity used by other reservations requests

granted pursuant to these procedures or (ii) less than fifteen percent of the Available

Fflowgate Ccapacity minus the transmission capacity used by other reservations requests

granted pursuant to this methodthese procedures. If the reservation is not deemed to be

feasible, it will be processed according to the normal methodology used for short-term firm

service requests provided for in this Tariff. Upon conclusion of the feasibility analysis, the

TransmissionEligible cCustomer will be notified of the results of the analysis and if the

reservation request is deemed to be feasible. AFor Short-Term Service requests that is

notare deemed infeasible, the Transmission Provider shall counteroffer partial service to

the extent it is available; and if partial service is not available the Transmission Provider

will refuse the request.will be refused by the Transmission Provider, the response time

provisions of Addendum 1 to this Attachment AC will become effective.

3.3.32. Redispatch Option IdentificationNotification and Request for System

Impact Study

Upon notification by the Transmission Provider that the reservation request is feasible, the

TransmissionEligible cCustomer shall notify the Transmission Provider of its election to

move forwardcontinue with the System Impact Study. this process or terminate itthe

request. If the TransmissionEligible Customer elects to terminate this processthe

requestSystem Impact Study, the Transmission Provider shall counteroffer partial service

to the extent it is available; and if partial service is not available the Transmission Provider

will refuse the request.such reservation request will be refused by the Transmission

Providerprocessed according to the normal methodology used for short-term firm service

requests otherwise provided for in this Tariff, including the provision of a counter offer

when appropriate. If Customer elects to move forward with this process, Customer shall

make notification to the Transmission Provider pursuant to Addendum 1 to this Attachment

AC of the Qualifying Redispatch Options it believes permits acceptance of the requested

reservation.

3.43. Redispatch System Impact Study

If the TransmissionEligible Customer elects to move forward with the System Impact

Study, the Transmission Provider will perform a System Impact Study in accordance with

the provisions of Attachment D of this Tariff.

4. Acceptance and Confirmation of Short-Term Service Request Subject to Redispatch

Once Customer has proposed the Qualifying Redispatch Options, Transmission Provider

will determine whether the proposed redispatch will permit Transmission Provider to

accept the reservation. Transmission Provider will provide a timely response to Customer,

pursuant to the response times specified on Addendum 1 to this Attachment AC, and post

the results of the study on its OASIS. If the System Impact Study determines that the

redispatch options will permit the Transmission Provider to accept the reservationrequest,

the Transmission Provider will respond in accordance with the Customer will be

responsible to negotiate and contract for such redispatch service from the provider or

providers of Qualifying Redispatch Options and provide copies of such agreements within

the response times specified on Addendum 1 to this Attachment AC. If

TransmissionEligible Customer confirms the request, any redispatch costs incurred to

relieve a system constraint to be charged to the TransmissionEligible Customer shall be

collected and paid as part of the Energy and Operating Reserve Market settlement

procedures described under Attachment AE of this Tariff and through the limitations on

Auction Revenue Rights and Long-Term Congestion Rights pursuant to the terms of

Section 13.5 of this Tariff. Upon demonstration of such agreement, Transmission Provider

will accept the reservation. In the event the customer does not provide demonstration of

such agreement within the required time, the request will be deemed withdrawn.

5. Refusal ofProcessing of Short-Term Service Requests due to lack of Redispatch

Optionsthat fail the System Impact Study

Transmission Provider will refuse For Short-Term Service requests that fail the System

Impact Study, the Transmission Provider shall counteroffer .partial service to the extent it

is available; and if partial service is not available the Transmission Provider will refuse

the request.

Scheduling Requirements and Redispatch Implementation

6.1. Scheduling Requirements

Any tag associated with a reservation requiring specification of redispatch provisions must

be submitted not later than one hour prior to its start. The Transmission Provider’s

Reliability Coordinator will determine whether redispatch will be required during the next

clock hour and inform Customer not later than thirty minutes prior to the top of the hour.

6.2. Conditions under which redispatch would be required

In the event that such reservation impacts a flowgate that is currently in or is expected to

be in a TLR level 3 or higher and curtailment of existing non-firm schedules is not adequate

to reduce flowgate loading to an acceptable level, Customer will be informed of the

required action for relief. Customer will be required to take the required action at the top

of the hour. Implementation of redispatch options will be required subsequent to a relevant

impacted flowgate being in TLR level 3 and prior to TLR Level 5. In the event that the

Reliability Coordinator determines that required redispatch has not been implemented, the

reservation(s) will be terminated for the remainder of the hour.

of 10

Addendum 1 to Attachment AC

Time Frames for Short-Term System Impact Studies

Term

TransmissionEligible Customer Responds

to Preliminary StudyFeasibility

Analysis

SPP Studies and Post

System Impact Study

TransmissionEligible Customer Meets

RequirementsConfirms Request

Customer Meets Requirements

(Reservation Pending)1

Monthly (more than 1 month)

1 Business Day 10 Business Days 7 Business Days 4 Days

Weekly 4 Business Hours 3 Business Days 3 Business Days 2 Days

Multi-Dayily (up to 1 week)

2 Business Hours 2 Business Days 2 Business Days 24 Hours

Daily 2 Business Hours 2 Business Days 2 Business Days 2 Hours

Daily (Day Prior) 1 Business Hour 1 Business Day 1 Business Day 2 Hours

Note: Business Hour: One Hour between 8 AM through 5 PM, Central Prevailing Time, during one business day. Business Day: Monday through Friday, except NERC Holidays.

_________________________ 1 Pending Reservation is a reservation that would be accepted if the reservation in System Impact Study were to be refused. This situation demands a shorter time frame.

SPP Criteria

NA


NA

Transmission

Customer submits

a TSR

Tariff Admin

evaluates request

for sufficient AFC

Full AFC exist?Tariff Admin moves request status to

ACCEPTEDYes

Can Partial

Service be

Granted?

Tariff Admin

moves request

status to

COUNTEROFFER

Yes

Transmission Customer moves

request status to CONFIRMED or

WITHDRAWN

Tariff Admin moves request status to

REFUSED

Does TSR

request a SIS?

Request forwarded

to Ops

Engineering to

begin SIS process

Ops Engineering

performs

Feasibility Test

Request

Feasible?

Ops Engineering

contacts TC to

confirm desire to

perform SIS (Cost

incurred here)

Yes

TC authorizes Ops

Engineering to

perform SIS?

No

Ops Engineering

performs SIS

TC accepts SIS

results?

SPP will REFUSE request

Yes

SPP will ACCEPT request

Yes

No

Yes

No

No

No

Can Partial

Service be

Granted?

Tariff Admin

moves request

status to

COUNTEROFFER

Transmission Customer moves

request status to CONFIRMED or

WITHDRAWN

Yes

No

System Impact Study – Proposed Process Flow

No

2015 TPL‐001‐4 Steady State Update

1

Jason [email protected]

2

Owner Scheduled Activities Date

PC Send MDWG potential violations to TPs and request CAPs Mon., August 3

PC Start verifying TP submitted CAPs upon reception ------------

TP Deadline for providing Protection Scheme Contingencies Tue., August 11

PC Send additional potential violations to TPs and request CAPs Mon., August 17

TWG Begin Stakeholder meetings to shed NCLL (if needed) Tue., August 18

TP Deadline for providing ALL CAPs Fri., September 18

PC Begin Drafting Steady State TPL Assessment Tue., October 20

TWG End Stakeholder meetings to shed NCLL Wed., October 21

PC Complete verification of TP submitted Steady State CAPs Tue., November 10

PC Post Draft TPL Comprehensive Assessment to TWG Tue , November 10

TWG TWG approval of 2015 Comprehensive TPL Assessment Wed, December 9

2015 TPL‐001‐4 Steady State Update

SPP CIP-014 Third Party Review

Scope Engineering7/27/2015

SPP CIP-014 Assessment Review Scope 1

RevisionHistory

Date or Version Number Author Change Description

6/23/2015 SPP Staff Draft

7/6/2015 SPP Staff Updated with Stakeholder Feedback

7/23/2015 SPP Staff Updated with Stakeholder Feedback

7/27/2015 SPP Staff Updated with Legal review / Template formatting


TableofContents Revision History ...........................................................................................................................................1

Overview .......................................................................................................................................................3

Data inputs ....................................................................................................................................................4

Data required by the Planning Coordinator (PC) ..................................................................................... 4

CIP-014 R2 Risk Assessment Verification .................................................................................................5

CIP-014 R2 Risk Assessment Verification .............................................................................................. 5

CIP-014 R2 Risk Assessment Review Verification Scope ...................................................................... 5

CIP-014 R1 Risk Assessment Applicability Verification ........................................................................ 5

CIP-014 R1 Risk Assessment Model Verification ................................................................................... 5

CIP-014 R1 Risk Assessment Performance Verification ......................................................................... 5

Deliverables ..................................................................................................................................................6

Deliverables .............................................................................................................................................. 6

Appendix A ...................................................................................................................................................07


Overview

This document establishes the scope of work for the NERC CIP-014 Requirement 2 unaffiliated third party verification.


Datainputs

DatarequiredbythePlanningCoordinator1(PC)

Data required by the Southwest Power Pool (SPP) PC to perform the CIP-014 Requirement 2 unaffiliated third party verification will be provided through the Third Party Risk Assessment Template (Appendix A).

1 SPP is a NERC registered PC


CIP‐014R2RiskAssessmentVerification

CIP‐014R2RiskAssessmentVerification

The SPP PC may perform the unaffiliated third party verification required by CIP-014 R2 if requested to do so by a Transmission Owner that is a SPP Member. SPP will develop a 15 day third party review request window. Transmission Owners will have the opportunity to submit their CIP-014-2 requests during this window. The SPP PC, in its sole discretion, reserves the right to decline to perform the verification for late submittals. if it determines in its sole discretion that it does not have the resources to perform the verification within the timeframe required under CIP-014 R2. If the SPP PC agrees to perform the risk assessment, then the SPP PC and the Transmission Owner shall execute an agreement for the performance of the CIP-014 R2 Risk Assessment Verification.

CIP‐014R2RiskAssessmentReviewVerificationScope

The SPP PC third party verification will consist of: 1) verifying the scope of Transmission stations and Transmission substations in the Transmission Owner’s risk assessment; 2) verifying the Transmission Owner’s CIP-014 R1 risk assessment model; 3) verifying the Transmission Owner performed the CIP-014 R1 risk assessment based on the methodology provided in the CIP-014 Third Party Risk Assessment Template; and 4) verifying the Transmission Owner performed the CIP-014 R1 risk assessment based on the data and results provided in the CIP-014 Third Party Risk Assessment Template.

CIP‐014R1RiskAssessmentApplicabilityVerification

The SPP PC will confirm that the Transmission Owner’s CIP-014 R1 risk assessment includes all Transmission stations and Transmission substations that meet the criteria established in CIP-014 applicability section 4.1.1.1-4.1.1.4.

CIP‐014R1RiskAssessmentModelVerification

The SPP PC will review the Transmission Owner’s model to ensure it contains sufficient system topology by performing a comparison of the Transmission Owner’s model and corresponding MDWG model. The SPP PC will also verify specified changes to the system topology in the Transmission Owner’s model based on response files (IDEV/Python) provided by the Transmission Owner’s.

CIP‐014R1RiskAssessmentPerformanceVerification

The SPP PC will verify that the Transmission Owner’s risk assessment results are consistent with the Transmission Owner’s methodology.


Deliverables

Deliverables

The SPP PC will provide a written report to the Transmission Owner. The report will 1) verify that the Transmission Owner’s risk assessment performed under CIP-014 Requirement R1 is complete and consistent with the Transmission Owner’s methodology; and / or 2) the report will include recommendations as well as justifications for those recommendations.


AppendixA

CIP-014 Third Party Risk Assessment Template Transmission Owners (TOs) should complete this template when requesting that SPP perform the CIP-014 R2 unaffiliated third party verification. SPP will review the request and notify the TO if it is able to perform the verification. The submitted information/methodologies should be adequately detailed for SPP to perform the verification.

Requestor Contact Information Requestor Name: Click Here – Entity Name Requestor Contact: Click Here – Entity Contact Requestor Address: Click Here – Entity Address Requestor Phone Number: Click Here – Entity Phone Number Requestor Email: Click Here – Entity Email Address

Risk Assessment Preparer Information (if other than requestor) Vendor Name: Click Here – Entity Name Vendor Contact: Click Here – Entity Contact Vendor Address: Click Here – Entity Address Vendor Phone Number: Click Here – Entity Phone Number Vendor Email: Click Here – Entity Email Address


CIP 014 R1 Evaluation Results Click here to provide a summary of your R1 evaluation

Steady State Information / Model Provide model used to perform Risk Assessment (True share) List of Facilities That Meet CIP-014 Criteria (Substations): Click Here – List of CIP-014 Criteria Facilities List of Facilities that are part of an IROL Click Here – List of Facilities that are part of an IROL List of Facilities that are part of an NPIIPR Click Here – List of Facilities that have a NPIIPR Model Series: Click Here – Model Series Model Year: Click Here – Model Year Model Season: Click Here – Model Season Model Peak/Other Modifications: Click Here – Model Peak/Other Please Specify the Type of Software Used if not PSSE: If using software other than PSSE, please provide a .raw file Click Here – Model Software Used

Assumptions / Planning Criteria

Cascading Definition: Click Here – Cascading Definition Methodology Used To Perform Assessment: Click Here – Methodology Assessment Please provide Software powerflow parameters: Click Here – Parameters of the powerflow solution SPP Criteria: ☐ or Local Criteria: ☐ (If local is selected please provide limits below) Low Voltage Limit: Click Here - Low Voltage Limit. High Voltage Limit: Click Here - High Voltage Limit. Thermal Limit: Click Here - High Thermal Limit.


Base Case Topology Changes with response files (IDEVs/Python): Click Here – Summary Base Case Topology Changes with IDEVs Summary of why Base Case Topology changes were made: Click Here – Reasons for Base Case Topology Changes Generator Dispatch Changes with response files (IDEVs/Python): Click Here – Summary Generator Dispatch Changes with IDEVs Summary of why Generator Dispatch Changes were made: Click Here – Reasons for Generator Dispatch Changes Load Changes with response files (IDEVs/Python): Click Here – Summary Load Changes with IDEVs Summary of why Load Changes were made: Click Here – Reasons for Load Changes

Study Information Including Bus Numbers, Format (Excel, Word Doc, Txt File) Contingency Files

Sub-System Files

Monitored Files

Automation Files

Steady State Results Table, Format (Excel, Word Doc, Txt File) Provide Risk Assessment Report

Provide The List Of Facilities That Caused Adverse Reliability Impacts (Substations)

Provide The List Of Facilities That Did Not Cause Adverse Reliability Impacts.

List Of Impacted Facilities Associated With Each Of The Facilities Listed Above (Other Facilities)

Steady State – Voltage/Thermal Response Of Impacted Facilities


Transient Information / Model

Provide model used to perform Risk Assessment (True share) List of Facilities That Meet CIP-014 Criteria (Substations): Click Here – List of CIP-014 Criteria Facilities Model Series: Click Here – Model Series Model Year: Click Here – Model Year Model Season: Click Here – Model Season Model Peak/Other modifications: Click Here – Model Peak/Other Please Specify the Type of Software Used if not PSSE: If using software other than PSSE, please provide a .raw file Click Here - Software Used Assumptions Instability Definition: Click Here - Definition of Instability. List of DYR File Revisions Different from the SPP Dynamic Model: Click Here – Summary of DYR File Revisions Summary of why DYR File Revisions Different from the SPP Dynamic Model were made: Click Here – Reasons for DYR File Revisions Assumed Relay Actions During Assessment: Describe Normal Clearing To Delayed Clearing By Summarizing Clearing Times Used For Simulated Events: Click Here - Summary of Assumed Relay Actions - Normal and Delayed Clearing Times Timeframe of Simulation: Click Here – Simulation Timeframe(s) Assumed Fault Values (-j2e^-9 MVA, Calculated Value) Single Line to Ground or 3 Phase. Click Here - Assumed Fault Values Method used to calculate Fault – (I.E. ASCC or SCMU PSS/E activities) Click Here - Summary of Fault Types and Calculations Please provide Software Solution parameters: Click Here – Transient Solution Parameters


Provide Contingencies Performed During Assessment (PSA Files If Available) Provide All Transient Results In Following Format: Provide Risk Assessment Report

Provide The List Of Facilities That Caused Adverse Reliability Impacts (Substations) In Your Dynamics Assessment.

Provide The List Of Facilities That Did Not Cause Adverse Reliability Impacts In Your Dynamics Assessment.

System Response Of Impacted Facilities With Bus Numbers In Your Dynamics Assessment (Table Format In Excel Or Word)

Plots (I.E. Speed, Angle, Voltage, P, Q) (PDF Of Dynamic Plots)

DO NOT FILL OUT INFORMATION BEYOND THIS POINT


SPP Contact: Click Here – Entity Contact SPP Address: 201 Worthen Drive Little Rock, AR 72223 SPP Phone Number: Click Here – Entity Phone Number SPP Fax Number: Click Here – Entity Fax Number SPP Date Received: Click Here – Date Received Study Agreement Number: Click Here – Study Agreement Number SPP Completion Date: Click Here – Completion Date SPP Return Submission Method: Click Here – Submission Date

☐ Via Email ☐ Via Post

Disclaimer The information contained herein or attached is compiled and maintained by the Steady State Planning Team and is provided to recipients for informational purposes only. The contents herein do not constitute advice upon which the recipient should solely rely, and should not be a substitute for direct guidance obtained by the recipient through due diligence, and based upon particular circumstances. The contents herein contain general information and recipients should not act, or refrain from acting, on the basis of the contents herein. Southwest Power Pool, Inc. expressly disclaims all liability relating to action taken or not taken based on any or all of the contents herein.

Fast Fault Screening ToolBenchmarkTWG MeetingDenver, COAugust 18 & 19, 2015

Douglas Bowman, [email protected] ∙ 501.688.1640

Background and Method

• TWG requested SPP to determine validity of Fast Fault Screening results against PSS/E

• Method

– Determine Critical Clearing Time from Fast Fault Screening

– Determine Critical Clearing Time in PSS/E

– Compare

• Two Data Sets

– 2015 Light Load Case Category B faults

– 2020 Summer Peak Case Category C Faults 2

15L Category B Results

Bus Number Bus Name Bus Base

Power From Bus

Power To Bus Generation

Generation 1 Bus Away

Kinetic Energy

Electric Torque Deviation

Voltage Drop Slip

Ranking Index FFS CCT prediction

Actual CCT

(kV) (MW) (MW) (MW) (MW) (s) (cycles) (cycles)659131 LARAMIE3 345 465 465 500 0 0.001 ‐0.1116 0.3298 0.0187 21.752 0.1 6 7507454TURK 4 138 614 614 616 0 0.0009 ‐0.2079 0.3128 0.0176 19.7984 0.12 7.2 7.7512648MAID 5 161 246 246 240 240 0.0009 ‐0.7978 0.1142 0.0201 16.1059 0.18 10.8 10.8532797WOLFCRK7 345 1233 1233 1261 0 0.0008 ‐0.3274 0.2478 0.014 14.609 0.14 8.4 7.4512650GRDA1 7 345 497 497 497 0 0.0008 ‐0.5047 0.1558 0.0149 13.3466 0.18 10.8 10.3510406N.E.S.‐7 345 928 928 930 0 0.0009 ‐1.3056 0.2685 0.0187 12.7262 0.18 10.8 7.8652509FTRANDL4 230 221 221 222 0 0.0009 ‐0.8553 0.0928 0.0171 12.5595 0.19 11.4 11.4542982 IATAN 7 345 899 899 900 0 0.0005 ‐0.433 0.1859 0.0133 12.3648 0.23 13.8 13.8532766 JEC N 7 345 614 614 680 0 0.0008 ‐0.8331 0.2188 0.0155 12.2474 0.19 11.4 11.4532853 LAWHILL6 230 344 344 344 344 0.0006 ‐0.8797 0.1881 0.0141 10.2015 0.19 11.4 11.4659106 LELANDO4 230 320 320 345 235 0.0002 0.0851 0.1474 0.007 9.051 0.25 15 14.5549954 JTEC 5 161 232 232 233 0 0.0006 ‐1.0085 0.0981 0.0148 9.0203 0.19 11.4 10.9549969BROOKLINE 5 161 220 220 233 233 0.0006 ‐1.0169 0.0809 0.014 7.9859 0.19 11.4 11.9645451S3451 3 345 517 517 528 0 0.0004 ‐0.4007 0.0826 0.0076 5.8345 0.29 17.4 15.9645458S3458 3 345 463 463 411 0 0.0003 ‐0.8718 0.0984 0.0105 5.5266 0.29 17.4 16.9541250SIBLEYPL 161 245 245 210 0 0.0001 ‐1.0081 0.0681 0.006 ‐0.2622 0.42 25.2 24.2509807ONETA‐‐7 345 1059 1059 930 930 0 ‐0.9726 0.1349 0.0028 ‐2.5924 0.23 13.8 11.3

3

• PSS/E simulation output with fault cleared in 14.5 cycles

• FFS CCT 15 cycles

15L Category B example: Leland Olds

4

15L Category B example: Leland Olds

• PSS/E simulation output Plot with fault clear in 15 cycles

• Note channel 737 (green channel)

• Actual CCT recorded as 14.5 cycles

5

20S Category C ResultsBus Number Bus Name

Bus Base

Power From Bus

Power To Bus Generation

Generation 1 Bus Away

Kinetic Energy

Electric Torque Deviation

Voltage Drop Slip

Ranking Index FFS CCT prediction

Actual CCT

(kV) (MW) (MW) (MW) (MW) (s) (cycles) (cycles)532766 JEC N 7 345 1442 1442 2310 770 0.0016 0.1067 0.3803 0.0224 27.6491 0.05 3 4542982 IATAN 7 345 1554 1554 1556 0 0.0014 ‐0.4662 0.3111 0.0248 25.4625 0.12 7.2 8.2531445GRDNCTY3 115 204 204 209 0 0.0013 ‐0.3198 0.322 0.0228 24.5461 0.1 6 8532852 JEC 6 230 668 703 770 0 0.0014 ‐0.1846 0.3288 0.021 23.8093 0.12 7.2 7.7542981LACYGNE7 345 1633 1647 1400 0 0.0013 ‐0.4274 0.2654 0.0228 23.1979 0.08 4.8 5.3547476ASB349 5 161 185 185 185 0 0.0013 ‐0.6528 0.2441 0.023 21.5687 0.14 8.4 8.9532768EMPEC 7 345 701 701 630 0 0.0009 ‐1.4002 0.2697 0.0279 21.3606 0.16 9.6 10.1507454TURK 4 138 614 614 616 0 0.0009 ‐0.1171 0.3124 0.0179 20.778 0.1 6 7.5645458S3458 3 345 1326 1326 1421 0 0.0012 ‐0.5197 0.217 0.0209 20.092 0.14 8.4 8.9532797WOLFCRK7 345 1187 1187 1261 0 0.0011 0.0756 0.2929 0.0156 19.5632 0.05 3 4520948HUGO PP4 138 439 439 440 0 0.0011 ‐0.5153 0.2611 0.0188 18.3459 0.16 9.6 9.1510406N.E.S.‐7 345 468 468 469 0 0.0011 ‐0.8846 0.2313 0.0215 18.2459 0.16 9.6 9.1533040EVANS N4 138 587 602 520 0 0.0011 ‐0.8405 0.2097 0.0207 17.5296 0.16 9.6 10.165027584&BLUFF 7 115 192 192 171 4 0.0009 ‐0.1192 0.2727 0.0148 17.1966 0.16 9.6 9.6549954 JTEC 5 161 454 454 455 0 0.001 ‐0.6137 0.1671 0.0185 16.4291 0.19 11.4 11.4520814ANADARK4 138 572 580 1017 466 0.0009 ‐0.6539 0.2371 0.0172 15.4735 0.19 11.4 11.9503902FITZHUGH 5 161 183 183 248 83 0.001 ‐0.7199 0.1551 0.0181 15.1618 0.18 10.8 10.8510396N.E.S.‐4 138 841 848 851 0 0.0009 ‐0.8727 0.2358 0.0177 14.4559 0.19 11.4 10.4512656GRDA1 5 161 527 527 998 510 0.0009 ‐1.016 0.1731 0.0188 13.949 0.16 9.6 10.6546653NEARMAN5 161 209 234 235 235 0.001 ‐1.034 0.141 0.0192 13.9232 0.18 10.8 10.8652519OAHE 4 230 580 580 582 0 0.0008 ‐0.5689 0.1853 0.0154 13.6675 0.19 11.4 10.9532853LAWHILL6 230 344 344 345 345 0.0007 ‐0.719 0.1429 0.015 11.7598 0.21 12.6 12.6505460BULL SH5 161 330 330 317 0 0.0008 ‐0.8737 0.0836 0.0165 11.639 0.19 11.4 10.9547498STL439 5 161 587 587 590 0 0.0007 ‐0.6074 0.1565 0.0127 10.3967 0.23 13.8 13.3646211S1211 5 161 434 447 450 0 0.0008 ‐0.9538 0.1197 0.0152 10.0909 0.23 13.8 13.8

549969BROOKLINE 5 161 461 461 455 455 0.0006 ‐1.0459 0.0856 0.0146 8.4501 0.23 13.8 13.3541225PHILL 5 161 521 521 450 0 0.0005 ‐0.6485 0.1171 0.0114 8.2778 0.29 17.4 16.9

6

• PSS/E simulation output with fault cleared in 13.8 cycles

(FFS CCT 13.8)

20S Category C example: S1211 5

7

• PSS/E Simulation with Plot with fault cleared in 14.3 cycles

• Actual CCT recorded as 13.8 cycles

20S Category C example: S1211 5

8

Conclusion

• In most cases, the FFS CCT is within 1 cycle of the PSS/E calculated CCT.

• Minor differences due to different programs, modeling methods, techniques

• Significant time savings when CCT calculations are needed

9

Annual State of the Market – Congestion and Losses Transmission Working Group Meeting

August 18, 2015

Market Monitoring Unit

Topics

• Locational Marginal Prices

• Geographic Congestion Pattern

• Frequently Constrained Areas

• Recent Transmission Expansion

• Losses

2

Locational Marginal Prices

• LMPs ensure least cost dispatch of generation in presence of transmission reliability constraints.

– Efficient short run dispatch signals

– Efficient long run signals for investment

• Marginal Cost of Energy + Marginal Cost of Congestion + Marginal Cost of Losses

𝐿𝑀𝑃=𝑀𝐸𝐶+𝑀𝐶𝐶+𝑀𝐿𝐶

• Annual average LMPs ranged geographically from about $20 to $40/MWh.

• 75% geographic difference is congestion, 25% losses.

3

4

Energy Price Contour Maps – 1st Twelve Months

Day-Ahead Market Real-Time Balancing Market

Day-Ahead Marginal Loss and Congestion

5

Marginal Congestion Component Marginal Loss Component

Frequently Constrained Areas

• Texas Panhandle

– Historically most congested area, frequent presence of market power

– Congestion costs fell dramatically during the year

Randall to Amarillo South, Tuco to Woodward

• Western Oklahoma

– New issue this year

– Expansion around Woodward lowered market congestion costs, created new bottleneck

6

Frequently Constrained Areas (cont.)

• Kansas City/Omaha

– Major reductions in congestion and market power in last two years

– Eastowne Transformer, Iatan to Nashua

• Northwest Kansas

– Historic congestion largely eliminated

– Post Rock to Spearville, Axtel to Post Rock

7

8

Congestion by Shadow Price

OSGCANBUSDEA Osage Switch-Canyon East (115) ftlo Bushland-Deaf Smith (230) [SPS]WDWFPLWDWTAT Woodward-FPL Switch (138) ftlo Woodward EHV-Tatonga (345) [OGE]IATSTRSTJHAW* Iatan-Stranger Creek (345) ftlo St. Joe-Hawthorn (345) [KCPL-WR-GMOC]SUNAMOTOLYOA Sundown-Amoco (230) ftlo Tolk-Yoakum (230) [SPS]NEORIVNEOBLC Neosho-Riverton (161) [WR-EDE] ftlo Neosho-Blackberry (345) [WR-AECI]SHAHAYKNOXFR South Hays - Hays (115) ftlo Knoll Xfmr (230/115) [MIDW]BRKXF2BRKXF1 Brookline Xfmr 1 (345/161) [AECI] ftlo Brookline Xfmr 2 (345/161) [SPRM]WDWFPLTATNOW Woodward-FPL Switch (138) ftlo Woodward EHV-Northwest (345) [OGE]REDWILLMINGO* Red Willow [NPPD] - Mingo [SECI] (345)GENTLMREDWIL* Gentleman-Red Willow (345) [NPPD]

* Reciprocally Coordinated Flowgate with MISO

KC-Omaha Corridor

Flowgate Name Region Flowgate LocationTexas Panhandle

Western Oklahoma

West SPP N-S Corridor

Texas PanhandleSE Kansas

Central KansasSW Missouri

Western OklahomaWest SPP N-S Corridor

0%

15%

30%

45%

60%

75%

$0

$20

$40

$60

$80

$100

% C

on

gest

ed

Shad

ow

Pri

ce (

$/M

Wh

)

% Intervals Congested includes both breached and binding intervals

DA Average Shadow Price

RT Average Shadow Price

DA % Intervals Congested

RT % Intervals Congested

9

Transmission Expansion

Projects to Relieve Congestion Issues Flowgate Name Region Location Projects that may provide mitigation

OSGCANBUSDEA

Texas Panhandle

Osage Switch - Canyon East (115) ftlo Bushland - Deaf Smith (230) [SPS]

Canyon East Sub –Randall County Interchange 115 kV line (March 2018 – Aggregate Studies)

SUNAMOTOLYOA Sundown - Amoco (230) ftlo Tolk - Yoakum

(230) [SPS]

1. Tuco Interchange – Yoakum 345 kV Ckt 1 (June 2020 – HPILS) 2. Amoco - Sundown 230 kV Terminal Upgrades (April 2019 - 2015 ITP10)

WDWFPLWDWTAT Western Oklahoma Woodward - FPL Switch (138) ftlo

Woodward EHV - Tatonga (345) [OGE] Woodward – Tatonga ck2 345 kV (March 2021 - ITP10)

WDWFPLTATNOW Western Oklahoma Woodward - FPL Switch (138) ftlo Tatonga -

Northwest (345) [OGE]

1. Matthewson - Tatonga 345 kV Ckt 2 (March 2021 – ITP10) 2. Elk City - Red Hills 138 kV Ckt 1 Reconductor (June 2015, ITPNT)

IATSTRSTJHAW* KC-Omaha Corridor Iatan - Stranger Creek (345) ftlo St. Joe -

Hawthorn (345) [KCPL-WR-GMOC] Sibley – Mullin Creek 345 kV (December 2016 – High Priority)

NEORIVNEOBLC SE Kansas Neosho - Riverton (161) ftlo Neosho -

Blackberry (345) [WR-EDE-AECI] No projects identified at time of report publication.

BRKXF2BRKXF1 SW Missouri Brookline Xfmr 1 (345/161) [AECI] ftlo

Brookline Xfmr 2 (345/161) [SPRM] No projects identified at time of report publication.

REDWILLMINGO*

Western SPP N-S Corridor

Red Willow [NPPD] - Mingo [SECI] (345) Gentleman - Cherry Co. - Holt 345 kV Ckt 1 (January 2018 – ITP10)

GENTLMREDWIL* Gentleman - Red Willow (345) [NPPD] Gentleman - Cherry Co. - Holt 345 kV Ckt 1 (January 2018 – ITP10)

* Reciprocally Coordinated Flowgate with MISO 10

Marginal Losses

• Variable losses for first year of market were 2.6% of the market energy obligation.

• West to east reduction in marginal loss costs in winter 2014-15 vs. annual average

– Dodge City, KS MLC smaller by $3.70/MWh

– Gerald Gentleman Station in Nebraska $1/MWh smaller

11

Summary

• Ongoing transmission expansion in SPP

– Reduces the cost of congestion and losses in the market

– Reduces structural market power

– Creates new congestion points

• MMU provides analysis of trends, especially with respect to market efficiency, and education on market economics.

– How else can we help?

12

SPP Market Monitoring Unit

[email protected]

13

TPLTF Update

1

Jason [email protected]

TPLTF Purpose

The TPL Task Force will review the TPL‐001‐4 standard, determine if any process changes or additions are warranted, and make a recommendation to the TWG of its findings.

2

TPLTF formed: February 12, 2014

Scope of Activities Determine new data requirements for facilities, modeling, and

contingencies to meet required compliance. This includes interface between PA and TP.

Define the SPP and member requirements and responsibilities. Determine R1 modeling requirements and present results to

TWG by August 2014. Determine which model Year 1 should be. Evaluate the Table 1 planning events for changes and/or

modifications to contingencies currently being assessed. Review the new BES definition as defined by NERC and

determine if any changes, modifications, or additions to the existing planning assessment processes and procedures are needed.

3

TPLTF Documents

TPL‐001‐4 Guidance Document

TPL‐001‐4 Steady State Scope

TPL‐001‐4 Short Circuit Scope

TPL‐001‐4 Stability Scope

• TPL‐001‐4 Gap Analysis

– Requirements

– Table 1

4

= TWG Reviewed

Recommendations

• The TPLTF recommends the TWG accept the five documents produced by the TPLTF as findings to the TWG per the TPLTF charter

• The TPLTF recommends that the TWG officially recognize the transition from the NERC TPL‐001‐4 standard to the NERC TPL‐007‐1 standard as the primary focus of the TPLTF

5


MODEL DEVELOPMENT WORKING GROUP

Report to the Transmission Working Group

August 10, 2015

Organizational Roster

The following members and staff represent the Model Development Working Group (MDWG):

Nate Morris, Chairman – Empire District Electric (EDE) Derek Brown, Vice-Chairman – Westar Energy (WR) Joe Fultz – Grand River Dam Authority (GRDA) Scott Rainbolt – American Electric Power (AEP) Dustin Betz – Nebraska Public Power District (NPPD) John Boshears – City Utilities of Springfield (CUS) Reené Miranda – Southwestern Public Service (SPS) Scott Schichtl – Arkansas Electric Cooperative Corporation (AECC) Jason Shook – GDS Associates (GDS) Brian Wilson – Kansas City Power & Light (KCPL) Liam Stringham –Sunflower Electric Power Corporation Holli Krizek – Western Area Power Administration Anthony Cook, Secretary – Southwest Power Pool (SPP)

Activity Update

The 2016 Series model list was set and made contingent on the changes of the ERAG MMWG 2016 Series model set.

The 2016 Series schedule was set and includes changes proposed by the Modeling Lean Initiative.

The MDWG updated the MDWG Procedure Manual to be compliant with MOD-032-R1 by the July 1, 2015 deadline.

The 2015 Series Dynamic model set was finalized August 3, 2015.

Respectfully submitted,

Anthony Cook, MDWG Secretary

ID Task Mode

Task Name Duration Start Finish Predecessors Resource Names

1 2016 MDWG Model Series (Powerflow, Short Circuit, Dynamics) 381 days Mon 3/2/15 Thu 8/25/162 Monthly Model Topology Updates (Based on Modeling Contact Submissions) (March ‐ August) 129 days Mon 3/2/15 Mon 8/31/153 March 22 days Mon 3/2/15 Tue 3/31/154 Email Notification for Data Submission 0 days Mon 3/2/15 Mon 3/2/155 Modeling Contacts Submit Topology/Profile Updates to MOD 21 days Mon 3/2/15 Mon 3/30/15 46 SPP ‐ Post Updated Model 1 day Tue 3/31/15 Tue 3/31/15 57 April 22 days Tue 3/31/15 Thu 4/30/158 Email Notification for Data Submission 0 days Tue 3/31/15 Tue 3/31/15 69 Modeling Contacts Submit Topology/Profile Updates to MOD 21 days Wed 4/1/15 Wed 4/29/15 610 SPP ‐ Post Updated Model 1 day Thu 4/30/15 Thu 4/30/15 911 May 20 days Thu 4/30/15 Fri 5/29/1512 Email Notification for Data Submission 0 days Thu 4/30/15 Thu 4/30/15 1013 Modeling Contacts Submit Topology/Profile Updates to MOD 19 days Fri 5/1/15 Thu 5/28/15 1014 2016 Series MDWG Case Set Finalized 0 days Fri 5/22/15 Fri 5/22/1515 SPP ‐ Post Updated Model 1 day Fri 5/29/15 Fri 5/29/15 1316 June 22 days Fri 5/29/15 Tue 6/30/1517 Email Notification for Data Submission 0 days Fri 5/29/15 Fri 5/29/15 1518 Modeling Contacts Submit Topology/Profile Updates to MOD 21 days Mon 6/1/15 Mon 6/29/15 1519 Modeling Kick‐Off/Training Workshop 2 days Tue 6/23/15 Wed 6/24/1520 SPP ‐ Post Updated Model 1 day Tue 6/30/15 Tue 6/30/15 1821 July 22 days Tue 6/30/15 Fri 7/31/1522 Email Notification for Data Submission 0 days Tue 6/30/15 Tue 6/30/15 2023 Modeling Contacts Submit Topology/Profile Updates to MOD 21 days Wed 7/1/15 Thu 7/30/15 2024 SPP ‐ Post Updated Model 1 day Fri 7/31/15 Fri 7/31/15 2325 August (Pass 0) 21 days Fri 7/31/15 Mon 8/31/1526 Email Notification for Data Submission 0 days Fri 7/31/15 Fri 7/31/15 2427 Modeling Contacts Submit Topology/Profile Updates to MOD 10 days Mon 8/3/15 Fri 8/14/15 2428 SPP Staff Builds Pass 0 Model (Dispatched by SPP if necessary to solve) 10 days Mon 8/17/15 Fri 8/28/15 2729 SPP ‐ Post Updated Model 1 day Mon 8/31/15 Mon 8/31/15 2830 2016 MDWG Powerflow Models 109 days Mon 8/31/15 Fri 2/5/1631 Pass 1 32 days Mon 8/31/15 Wed 10/14/1532 Pass 1 ‐ Member Review August Model/Data submission 12 days Mon 8/31/15 Wed 9/16/1533 Modeling Contacts Gen/Load Profiles, Data Submittal WB & Topology Updates 12 days Mon 8/31/15 Wed 9/16/15 2834 Pass 1 ‐ Model Update Meeting 2 days Tue 9/15/15 Wed 9/16/1535 Pass 1 ‐ Lock Down MOD 20 days Thu 9/17/15 Wed 10/14/15 3236 Pass 1 ‐ SPP Staff Review of Member Data Submissions 3 days Thu 9/17/15 Mon 9/21/15 3237 Pass 1 ‐ SPP Staff Builds Preliminary Powerflow Models 5 days Tue 9/22/15 Mon 9/28/15 3638 Pass 1 ‐ SPP Staff Posts Preliminary Pass 1 Powerflow Models/Docucheck Corrections Needs Workbook 0 days Mon 9/28/15 Mon 9/28/15 3739 Pass 1 ‐ Members Submit Docucheck Corrections (Idev format) 5 days Tue 9/29/15 Mon 10/5/15 3840 Pass 1 ‐ SPP Staff Builds Final Pass 1 Powerflow Models 5 days Tue 10/6/15 Mon 10/12/15 3941 Pass 1 ‐ Modeling Contact Accountability Process 1 day Mon 10/12/15 Mon 10/12/15 40FS‐1 day42 Pass 1 ‐ SPP Staff Posts Final Pass 1 Powerflow Models/Docucheck Corrections Needs Workbook 0 days Mon 10/12/15 Mon 10/12/15 4043 Pass 2 38 days Tue 10/13/15 Mon 12/7/1544 Pass 2 ‐ Member Review Pass 1 Powerflow Models/Data submission 12 days Tue 10/13/15 Wed 10/28/1545 Modeling Contacts Gen/Load Profiles, Data Submittal WB & Topology Updates 12 days Tue 10/13/15 Wed 10/28/15 4246 Modeling Contacts Submit Docucheck Correction idevs to MOD 12 days Tue 10/13/15 Wed 10/28/15 4247 Pass 2 ‐ Lock Down MOD 26 days Thu 10/29/15 Mon 12/7/15 4448 Pass 2 ‐ SPP Staff Review of Member Data Submissions 5 days Thu 10/29/15 Wed 11/4/15 4449 Pass 2 ‐ SPP Staff Builds Preliminary Powerflow Models (Merge with MMWG Current or Prior year) 5 days Thu 11/5/15 Wed 11/11/15 4850 Pass 2 ‐ SPP Staff Posts Preliminary Pass 2 Powerflow Models/Docucheck Corrections Needs Workbook 0 days Wed 11/11/15 Wed 11/11/15 4951 Pass 2 ‐ Members Submit Docucheck Corrections (Idev format) 11 days Thu 11/12/15 Mon 11/30/15 5052 Pass 2 ‐ SPP Staff Builds Final Pass 2 Powerflow Models 5 days Tue 12/1/15 Mon 12/7/15 5153 Pass 2 ‐ Modeling Contact Accountability Process 1 day Mon 12/7/15 Mon 12/7/15 52FS‐1 day54 Pass 2 ‐ SPP Staff Posts Final Pass 2 Powerflow Models/Docucheck Corrections Needs Workbook 0 days Mon 12/7/15 Mon 12/7/15 5255 Pass 3 ‐ Final 41 days Tue 12/8/15 Fri 2/5/1656 Pass 3 ‐ Member Review Pass 2 Powerflow Models/Final Data submission (Loads Locked Down from P2) 21 days Tue 12/8/15 Fri 1/8/16 5457 Modeling Contacts Submit Docucheck Correction idevs to MOD 21 days Tue 12/8/15 Fri 1/8/16 5458 Pass 3 ‐ Lock Down MOD 20 days Mon 1/11/16 Fri 2/5/16 5659 Pass 3 ‐ SPP Staff Review of Member Data Submissions 5 days Mon 1/11/16 Fri 1/15/16 5660 Pass 3 ‐ SPP Staff Builds Preliminary Powerflow Models 5 days Mon 1/18/16 Fri 1/22/16 5961 Pass 3 ‐ SPP Staff Posts Preliminary Pass 3 Powerflow Models/Docucheck Corrections Needs Workbook 0 days Fri 1/22/16 Fri 1/22/16 6062 Pass 3 ‐ Members Submit Docucheck Corrections (Idev format) 5 days Mon 1/25/16 Fri 1/29/16 6163 Pass 3 ‐ SPP Staff Builds Final Powerflow Models 5 days Mon 2/1/16 Fri 2/5/16 6264 Pass 3 ‐ Modeling Contact Accountability Process 1 day Fri 2/5/16 Fri 2/5/16 63FS‐1 day65 Pass 3 ‐ SPP Staff Posts Final Powerflow Models/Docucheck Corrections Needs Workbook 0 days Fri 2/5/16 Fri 2/5/16 6366 2016 MDWG Short Circuit Models 206 days Thu 11/5/15 Thu 8/25/1667 Pass 1 21 days Thu 11/5/15 Mon 12/7/1568 Pass 1 ‐ SPP Staff Builds Preliminary Short Circuit Models 5 days Thu 11/5/15 Wed 11/11/15 4869 Pass 1 ‐ SPP Staff Posts Preliminary Pass 1 Short Circuit Models/Docucheck Corrections Needs Workbook 0 days Wed 11/11/15 Wed 11/11/15 4970 Pass 1 ‐ Members Submit Docucheck Corrections (Idev format) 11 days Thu 11/12/15 Mon 11/30/15 5071 Pass 1 ‐ SPP Staff Builds Final Pass 1 Models 5 days Tue 12/1/15 Mon 12/7/15 5172 Pass 1 ‐ SPP Staff Posts Final Pass 1 Models/Docucheck Corrections Needs Workbook 0 days Mon 12/7/15 Mon 12/7/15 5273 Pass 2 ‐ Final 15 days Mon 1/18/16 Fri 2/5/16

3/2

3/31

S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W TMar 1, '15 Mar 8, '15 Mar 15, '15 Mar 22, '15 Mar 29, '15 Apr 5, '15 Apr 12, '15 Apr 19, '15 Apr 26, '15

Task

Split

Milestone

Summary

Project Summary

Inactive Task

Inactive Milestone

Inactive Summary

Manual Task

Duration-only

Manual Summary Rollup

Manual Summary

Start-only

Finish-only

External Tasks

External Milestone

Deadline

Progress

Manual Progress

Page 1

Project: 2016 Series MDWG PoDate: Tue 5/26/15

ID Task Mode

Task Name Duration Start Finish Predecessors Resource Names

74 Pass 2 ‐ SPP Staff Builds Preliminary Short Circuit Models 5 days Mon 1/18/16 Fri 1/22/16 5975 Pass 2 ‐ SPP Staff Posts Preliminary Final Short Circuit Models/Docucheck Corrections Needs Workbook 0 days Fri 1/22/16 Fri 1/22/16 7476 Pass 2 ‐ Members Submit Docucheck Corrections (Idev format) 5 days Mon 1/25/16 Fri 1/29/16 7577 Pass 2 ‐ SPP Staff Builds Final Short Circuit Models 5 days Mon 2/1/16 Fri 2/5/16 7678 Pass 2 ‐ SPP Staff Posts Final Short Circuit Models/Docucheck Corrections Needs Workbook 0 days Fri 2/5/16 Fri 2/5/16 7779 2016 MDWG Powerflow/Short Circuit Model Finalization 6 days Mon 2/8/16 Mon 2/15/1680 Final 6 days Mon 2/8/16 Mon 2/15/1681 Members Review for Finalization of 2016 Series MDWG Powerflow & Short Circuit Models 5 days Mon 2/8/16 Fri 2/12/16 65,7882 Finalization ‐ Conference Call Vote 1 day Mon 2/15/16 Mon 2/15/16 8183 2016 MDWG DYNAMICS MODELS 191 days Mon 11/30/15 Thu 8/25/1684 MMWG 2015 Series Dynamic Models 1 day Fri 1/15/16 Fri 1/15/1685 Receive ERAG MMWG SDDB (Dynamics Database) 1 day Fri 1/15/16 Fri 1/15/1686 Initial Data Update 53 days Mon 11/30/15 Mon 2/15/1687 Initial Data Update ‐ Build and Post DYRE Files, Wind Farm Data, and Docureport 10 days Mon 11/30/15 Fri 12/11/1588 Initial Data Update ‐ Build and Post DYRE Files, Wind Farm Data, and Docureport 10 days Mon 11/30/15 Fri 12/11/1589 Initial Data Update ‐ Members Submit Data Updates 43 days Mon 12/14/15 Mon 2/15/16 8890 Initial Data Update ‐ Member Data Due 0 days Mon 2/15/16 Mon 2/15/16 8991 Powerflow Adjustments 20 days Tue 2/16/16 Mon 3/14/1692 Powerflow Updates 10 days Tue 2/16/16 Mon 2/29/16 8293 Wind Farm Topology and GI Updates 10 days Tue 3/1/16 Mon 3/14/16 9294 Dynamic Case Adjustments 37 days Tue 3/1/16 Wed 4/20/1695 Update SDDB (ERAG/MMWG Dynamic Database) 4 days Tue 3/1/16 Fri 3/4/16 9296 Duplicate Models 2 days Mon 3/7/16 Tue 3/8/16 9597 Generator Data Checks 2 days Wed 3/9/16 Thu 3/10/16 9698 SDDB Governor Limits and Small Time Constant Reset 2 days Fri 3/11/16 Mon 3/14/16 9799 WMOD/Generic WTG Checks 2 days Tue 3/15/16 Wed 3/16/16 98

100 CONL & GNET Files Updates 4 days Thu 3/17/16 Tue 3/22/16 99101 Post Member Feedback for Dynamic Data & Case Issues 1 day Wed 3/23/16 Wed 3/23/16 100102 Members Submit Data Updates 15 days Thu 3/24/16 Wed 4/13/16 101103 Member Data Due 0 days Wed 4/13/16 Wed 4/13/16 102104 Process SPP Member Updates 5 days Thu 4/14/16 Wed 4/20/16 103105 Dynamic Case Initialization 15 days Thu 4/21/16 Wed 5/11/16106 Case & Dyre File Corrections based on Initialization Messages 15 days Thu 4/21/16 Wed 5/11/16 104107 Build Final Models 35 days Thu 5/12/16 Wed 6/29/16108 20 Second No‐fault Test & Case Adjustment 10 days Thu 5/12/16 Wed 5/25/16 106109 60 Second Ring‐Down Test & Case Adjustment 10 days Thu 5/26/16 Wed 6/8/16 108110 NERC B&C Faults Test & Case Adjustment 5 days Thu 6/9/16 Wed 6/15/16 109111 Dynamic Case Reduction 10 days Thu 6/16/16 Wed 6/29/16 110112 Dynamic Case Review and Finalization 41 days Thu 6/30/16 Thu 8/25/16113 Post Initial Models 5 days Thu 6/30/16 Wed 7/6/16 111114 Member Review of Initial Models 10 days Thu 7/7/16 Wed 7/20/16 113115 Member Data Due 0 days Wed 7/20/16 Wed 7/20/16 114116 Final Data Update ‐ Build Final Models 10 days Thu 7/21/16 Wed 8/3/16 115117 Post Final Models 1 day Thu 8/4/16 Thu 8/4/16 116118 Member Review for Finalization of Dynamic Models 10 days Fri 8/5/16 Thu 8/18/16 117119 MDWG Vote 5 days Fri 8/19/16 Thu 8/25/16 118

S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W T F S S M T W TMar 1, '15 Mar 8, '15 Mar 15, '15 Mar 22, '15 Mar 29, '15 Apr 5, '15 Apr 12, '15 Apr 19, '15 Apr 26, '15

Task

Split

Milestone

Summary

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Deadline

Progress

Manual Progress

Page 2

Project: 2016 Series MDWG PoDate: Tue 5/26/15

MMWG MDWGPower Flow Model

DynamicModel Year Year Season

Power Flow Model

DynamicModel

Short Circuit Model

2016 Spring X2016 Summer X X

2016Summer Shoulder

X

2016 Fall X2016 Winter X2017 Light Load X X2017 Spring X2017 Summer X X

2017Summer Shoulder

X X

2017 Fall X2017 Winter X X2018 Spring X2018 Summer X X2018 Winter X2021 Light Load X X2021 Summer X X X2021 Winter X X2026 Summer X X2026 Winter X

MMWG: Multiregional Modeling Working GroupMDWG: Model Development Working Group

*MMWG will be populated after July meeting

MMWG* MDWG

2016 Series Model Selection

Attachment AQ Improvement Task Force

TWGAugust 18‐19, 2015

Task Force Goals

• Review Attachment AQ process

• Determine improvements in the AQ process

• Revise the tariff language

• Develop business practice incorporating desired process changes

2

Attachment AQ Tariff Changes

• Certain changes do not require AQ process including:

• New or modified loads captured in Attachment O ITP process

• Any capacity changes at a delivery point without corresponding load change

• Any distribution transformer changes without a corresponding load change

• Modification to a delivery point facility rating, i.e. relay change/setting, CT settings, etc.

4

Attachment AQ Tariff Changes (cont.)• Transmission Owner decides whether to put project

through ITP or AQ based off timing

• Transmission Owner determines if a Load Connection Study (LCS) is required

• SPP staff will review the LCS and determine if a delivery point network study (DPNS) will need to be performed

• Once staff either approves the LCS or completes a DPNS, NTCs may be issued

5

Next Steps

• The AQITF will finalize the following documents before bringing them to the TWG and the other appropriate working groups.• Updated Attachment AQ tariff language

• New Delivery Point Addition Business Practice

6

ID % Name <Unavailable>Duration Start Finish Resource Names

0 54% SPP 2015 TWG Work Schedule - 08-11-2015 478 days Mon 11/3/14 Wed 8/31/161 0% 2015 TWG Meeting Schedule 87 days Tue 8/18/15 Wed 12/16/15

2 0% TWG August Meeting - Denver, CO 2 days Tue 8/18/15 Wed 8/19/15 Members,SPP

3 0% TWG Net Conference September 1 day Wed 9/16/15 Wed 9/16/15 Members,SPP

4 0% TWG Net Conference October 1 day Wed 10/21/15 Wed 10/21/15 Members,SPP

5 0% TWG November Meeting - SPP Little Rock 2 days Tue 11/17/15 Wed 11/18/15 Members,SPP

6 0% TWG Net Conference December 1 day Wed 12/9/15 Wed 12/9/15 Members,SPP

7 0% TWG Net Conference December 1 day Wed 12/16/15 Wed 12/16/15 Members,SPP

8 0% 2016 TWG Meeting Schedule 50 days Mon 1/18/16 Fri 3/25/16

9 0% TWG January Meeting 1 day Mon 1/18/16 Mon 1/18/16 Members,SPP

10 0% TWG February Meeting 1 day Fri 2/19/16 Fri 2/19/16 Members,SPP

11 0% TWG March Meeting 1 day Fri 3/25/16 Fri 3/25/16 Members,SPP

12 75% SPP Project Tracking 478 days Mon 11/3/14 Wed 8/31/16

13 100% Project Tracking 1st Quarter 30 days Mon 11/3/14 Fri 12/12/14

14 100% T.O.s submit updates 10 days Mon 11/3/14 Fri 11/14/14 Members

15 100% T.O.s provide cost increase justifications 6 days Wed 11/19/14 Wed 11/26/14 Members

16 100% T.O.s submit mitigation plans 18 days Wed 11/19/14 Fri 12/12/14 Members

17 100% Project Tracking 2nd Quarter 30 days Mon 2/2/15 Fri 3/13/15


19 100% T.O.s provide cost increase justifications 4 days Thu 2/19/15 Tue 2/24/15 Members

20 100% T.O.s submit mitigation plans 17 days Thu 2/19/15 Fri 3/13/15 Members

21 100% Project Tracking 3rd Quarter 31 days Fri 5/1/15 Fri 6/12/15

22 100% T.O.s submit updates 11 days Fri 5/1/15 Fri 5/15/15 Members

23 100% T.O.s provide cost increase justifications 5 days Wed 5/20/15 Tue 5/26/15 Members


25 0% Project Tracking 4th Quarter 30 days Mon 8/3/15 Fri 9/11/15


27 0% T.O.s provide cost increase justifications 5 days Wed 8/19/15 Tue 8/25/15 Members


29 100% 2015 MDWG Powerflow Models 76 days Wed 11/26/14 Wed 3/11/15

30 100% Pass 4 MDWG Powerflow Models 26 days Wed 11/26/14 Wed 12/31/14

31 100% Pass 4 - Members Review/Submit Changes to Pass 4 Powerflow Models 26 days Wed 11/26/14 Wed 12/31/14 Members

32 100% Pass 4 - Member Review/Changes Due 0 days Wed 12/31/14 Wed 12/31/14 Members

33 100% Build Pass 5 MDWG Powerflow Models (Unscheduled) 1 day Wed 11/26/14 Wed 11/26/14 SPP

34 100% Pass 5 (Unscheduled) - MDWG Powerflow Models 6 days Fri 1/30/15 Fri 2/6/15

35 100% Pass 5 - Posted for Members to submit DocuCheck corrections 3 days Fri 1/30/15 Tue 2/3/15 Members,SPP

36 100% Build Pass 6 MDWG Powerflow Models (Unscheduled) 3 days Wed 2/4/15 Fri 2/6/15 SPP

37 100% Pass 6 (Unscheduled) - MDWG Powerflow Models 6 days Fri 2/6/15 Fri 2/13/15

38 100% Pass 6 - Posted for Members to submit DocuCheck corrections 3 days Fri 2/6/15 Tue 2/10/15 SPP,Members

39 100% Build Final MDWG Powerflow Models 3 days Wed 2/11/15 Fri 2/13/15 SPP

40 100% Final MDWG Powerflow Models 6 days Wed 3/4/15 Wed 3/11/15

41 100% Final - Members Review for Finalization of MDWG Powerflow Models 5 days Wed 3/4/15 Tue 3/10/15 Members

42 100% Finalization - Conference Call Vote 1 day Wed 3/11/15 Wed 3/11/15 Members

43 100% 2015 MDWG Short Circuit Models 72 days Fri 12/19/14 Mon 3/30/15

44 100% Short Circuit Models Pass 1 66 days Fri 12/19/14 Fri 3/20/15

45 100% Pass 1 - Members Review/Submit Changes to Pass 1 Short Circuit Models 24 days Fri 12/19/14 Wed 1/21/15 SPP

46 100% Pass 1 - Member Review/Changes Due 0 days Wed 1/21/15 Wed 1/21/15 Members

47 100% Pass 1 - Build Final Short Circuit Models 43 days Wed 1/21/15 Fri 3/20/15 SPP

48 100% Pass 1 - Post MDWG 2015 Series Final Short Circuit Models 0 days Fri 3/20/15 Fri 3/20/15 SPP,Members

49 100% Short Circuit Models Final Pass 6 days Mon 3/23/15 Mon 3/30/15

50 100% Final - Member Review for Finalization of Short Circuit Models 5 days Mon 3/23/15 Fri 3/27/15 SPP

51 100% Finalization - Conference Call Vote 1 day Mon 3/30/15 Mon 3/30/15 Members

52 100% 2015 MDWG Dynamic Models 193 days Wed 11/26/14 Fri 8/21/15

53 100% Initial Data Update 60 days Wed 11/26/14 Tue 2/17/15

54 100% Build and Post DYRE Files, Wind Farm Data, and Docureport 12 days Wed 11/26/14 Thu 12/11/14 SPP

55 100% Members submit data updates 48 days Fri 12/12/14 Tue 2/17/15 Members

56 100% Build Final MDWG Dynamic Models 73 days Mon 4/27/15 Wed 8/5/15

57 100% 20 Second No-fault Test & Case Adjustment 61 days Mon 5/11/15 Mon 8/3/15 SPP

58 100% 60 Second Ring-Down Test & Case Adjustment 73 days Mon 4/27/15 Wed 8/5/15 SPP

Members,SPP

Members,SPP

Members,SPP

Members,SPP

Members,SPP

Members,SPP

Members,SPP

Members,SPP

Members,SPP

Members

Members

Members

Members

Members

Members

Members

Members

Members

Members

Members

Members

Members

SPP

Members,SPP

SPP

SPP,Members

SPP

Members

Members

SPP

SPP

SPP

Members

SPP

Members

SPP

SPP

Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul3rd Quarter 4th Quarter 1st Quarter 2nd Quarter 3rd Quarter

Page 1


59 100% NERC B&C Faults Test & Case Adjustment 63 days Thu 5/7/15 Mon 8/3/15 SPP

60 100% Dynamic Case Reduction 7 days Mon 5/18/15 Tue 5/26/15 SPP

61 100% MDWG Dynamic Case Review and Finalization 42 days Thu 6/25/15 Fri 8/21/15

62 100% Post Initial Models 1 day Fri 5/15/15 Fri 5/15/15 SPP

63 100% Member Review of Initial Models 11 days Mon 5/18/15 Mon 6/1/15 Members

64 100% Member Data Due 0 days Mon 6/1/15 Mon 6/1/15 Members

65 100% Final Data Update - Build Final Models 32 days Mon 6/1/15 Tue 7/14/15 SPP

66 100% Post Final Models 0 days Tue 7/14/15 Tue 7/14/15 SPP

67 100% Member Review for Finalization of MDWG Dynamic Models 10 days Tue 7/14/15 Mon 7/27/15 Members

68 100% Apply Member Feedback 10 days Tue 7/7/15 Mon 7/20/15 SPP

69 100% Re-post Final Models 0 days Fri 7/17/15 Fri 7/17/15 SPP

70 100% Member Review for Finalization of MDWG Dynamic Models 8 days Mon 7/20/15 Wed 7/29/15 Members

71 100% MDWG Dynamic Models - MDWG Vote 5 days Thu 7/30/15 Wed 8/5/15 Members

72 100% ERAG MRSS 2015 Summer Transmission Assessment 44 days Fri 2/6/15 Wed 4/8/15

73 100% ERAG MRSS 2015 Summer Transmission Assessment Study 32 days Fri 2/6/15 Mon 3/23/15 Members

74 100% TWG Comments on Report 6 days Wed 4/1/15 Wed 4/8/15 Members

75 100% TWG Approve SPP Section of Report 1 day Wed 4/8/15 Wed 4/8/15 Members

76 100% 2015 Annual Flowgate Assessment 74 days Fri 2/20/15 Wed 6/3/15

77 100% T.O.s review of all subsystem files 17 days Fri 2/20/15 Mon 3/16/15 Members

78 100% Staff run AC analysis 5 days Wed 4/8/15 Tue 4/14/15 SPP

79 100% T.O.s review of FG assessment 6 days Tue 5/12/15 Tue 5/19/15 Members

80 100% TWG Review/Approval 0 days Tue 5/19/15 Tue 5/19/15 Members

81 100% ORWG Review/Approval 0 days Wed 6/3/15 Wed 6/3/15 Members

82 100% TRM Assessment 32 days Mon 4/20/15 Wed 6/3/15

83 100% Staff calculate existing and new FG TRMs 17 days Mon 4/20/15 Tue 5/12/15 SPP

84 100% T.O.s review of TRM values 6 days Tue 5/12/15 Tue 5/19/15 Members

85 100% TWG Review/Approval 1 day Tue 5/19/15 Tue 5/19/15 Members

86 100% ORWG Review/Approval 0 days Wed 6/3/15 Wed 6/3/15 Members

87 100% FERC 715 Filing 5 days Tue 3/24/15 Mon 3/30/15

88 100% Staff to report the SPP filing is complete 5 days Tue 3/24/15 Mon 3/30/15 SPP

89 100% NERC RAS Summer Report 6 days Mon 3/23/15 Mon 3/30/15

90 100% TWG Comments on Report 6 days Mon 3/23/15 Mon 3/30/15 Members

91 100% Annual Review of ATC Process 15 days Thu 2/12/15 Wed 3/4/15

92 100% ATC Review 15 days Thu 2/12/15 Wed 3/4/15 SPP

93 42% 2015 NERC TPL-001-4 205 days Thu 2/26/15 Wed 12/9/15

94 56% NERC TPL Steady State Assessment, TPL 001-4 205 days Thu 2/26/15 Wed 12/9/15

95 100% TWG Scope Approval 1 day Wed 3/18/15 Wed 3/18/15 Members

96 56% NERC TPL Steady State Assessment, TPL 001-4 184 days Thu 2/26/15 Fri 11/13/15 SPP

97 0% TWG approval of 2015 Comprehensive TPL Assessment 1 day Wed 12/9/15 Wed 12/9/15 Members

98 29% NERC TPL Stability Study, TPL 001-4 147 days Tue 5/19/15 Wed 12/9/15

99 100% TWG Scope Approval 1 day Tue 5/19/15 Tue 5/19/15 Members

100 28% NERC TPL Stability Study, TPL 001-4 74 days Wed 8/19/15 Mon 11/30/15 SPP


102 34% NERC TPL Short Circuit Study, TPL 001-4 202 days Tue 3/3/15 Wed 12/9/15

103 100% TWG Scope Approval 1 day Wed 3/18/15 Wed 3/18/15 Members

104 34% NERC TPL Short Circuit Study, TPL 001-4 170 days Tue 3/3/15 Mon 10/26/15 SPP


106 23% ERAG MRSS 2015 Winter Transmission Assessment 98 days Tue 7/21/15 Thu 12/3/15

107 23% ERAG MRSS 2015 Summer Transmission Assessment Study 98 days Tue 7/21/15 Thu 12/3/15 Members,SPP

108 0% NERC RAS Winter Report 5 days Tue 9/15/15 Mon 9/21/15

109 0% TWG Comments on Report 5 days Tue 9/15/15 Mon 9/21/15 Members

110 36% SPP 2016 ITP Near-Term (12-month cycle) 398 days Tue 12/16/14 Thu 6/23/16

111 100% ITPNT Scope 96 days Tue 12/16/14 Tue 4/28/15

112 100% Finalize 2016 ITPNT Scope 96 days Tue 12/16/14 Tue 4/28/15 Members,SPP

113 100% ITPNT Models 97 days Tue 2/17/15 Wed 7/1/15

114 100% Develop Firm Service Scenario Models 69 days Tue 2/17/15 Fri 5/22/15 SPP

115 100% TWG Review Models 6 days Wed 6/24/15 Wed 7/1/15 Members

116 100% Develop CBA Scenario Models 53 days Mon 4/20/15 Wed 7/1/15 SPP[102%]

117 100% TWG Review CBA Scenario 6 days Wed 6/24/15 Wed 7/1/15 Members

SPP

SPP

SPP

Members

SPP

Members

SPP

Members

Members

Members

Members

Members

Members

SPP

Members

SPP

Members

Members

SPP

Members

SPP

Members

SPP

Members

Members

SPP

Members

Members

SPP

Members

Members,SPP

Members

Members,SPP

SPP

Members

SPP[102%]

Members


Page 2


118 5% ITPNT Study Work 257 days Wed 7/1/15 Thu 6/23/16

119 50% Needs Assessment 44 days Wed 7/1/15 Mon 8/31/15 SPP

120 0% DPP Window (includes cure period) 30 days Tue 9/1/15 Mon 10/12/15 Stakeholders,SPP

121 0% Solution Development 30 days Wed 10/28/15 Tue 12/8/15 SPP,Members,Stakeholders (DPP)

122 0% Conceptual Cost Estimates 30 days Thu 10/1/15 Wed 11/11/15 SPP

123 0% Develop 2016 ITPNT Draft Portfolio 33 days Thu 11/12/15 Mon 12/28/15 SPP,Members

124 0% Upgrade Determination (New 2A Process) 5 days Tue 12/29/15 Mon 1/4/16 SPP

125 0% TWG Review of initial Draft Portfolio 1 day Mon 1/18/16 Mon 1/18/16 Members

126 0% Study Cost Estimates (Non-competitive-TO's and Competitive - SPP) (New 2A Process)

39 days Tue 1/5/16 Fri 2/26/16 SPP,Members

127 0% TWG Review of Draft Final Portfolio 1 day Fri 3/25/16 Fri 3/25/16 Members

128 0% Final Portfolio Development 67 days Tue 12/29/15 Wed 3/30/16 SPP,Members

129 0% NERC TPL-001-4 Table 1 Planning Events 108 days Mon 11/2/15 Wed 3/30/16 SPP

130 0% ATRR / Rate Impacts on Final Portfolio 23 days Mon 2/29/16 Wed 3/30/16 SPP

131 0% 2016 ITPNT Report for MOPC/BOD 20 days Fri 4/1/16 Thu 4/28/16 SPP,Members

132 0% Short-Term Reliability Project Process 40 days Fri 4/29/16 Thu 6/23/16 SPP,Members

133 39% SPP 2017 ITP10 (18-month cycle) 268 days Wed 1/21/15 Fri 1/29/16

134 30% Scoping 192 days Wed 1/21/15 Thu 10/15/15

135 58% Create Draft Scope 192 days Wed 1/21/15 Thu 10/15/15 SPP,Members

136 0% TWG Review (Constraint Assessment) 183 days Tue 2/3/15 Thu 10/15/15 Members,SPP

137 0% TWG Approval 1 day Thu 10/15/15 Thu 10/15/15 Members

138 0% Post Final Scope 1 day Thu 10/15/15 Thu 10/15/15 SPP

139 85% Load Review 51 days Fri 5/1/15 Fri 7/10/15

140 100% Review ESWG/Tier 1 Feedback (Load Data) 14 days Fri 5/1/15 Wed 5/20/15 SPP,Members

141 100% ESWG Materials Development (Load Data) 3 days Mon 6/8/15 Wed 6/10/15 SPP,Members

142 0% TWG 1 day Wed 6/17/15 Wed 6/17/15 SPP,Members

143 75% Finalize Load Review (QAP) 16 days Fri 6/19/15 Fri 7/10/15 SPP

144 93% Generation Review 66 days Thu 5/7/15 Thu 8/6/15

145 100% Review ESWG/Tier 1 Feedback (Generation Data) 36 days Thu 5/7/15 Thu 6/25/15 SPP,Members

146 100% ESWG/TWG Materials Development (Generation Data) 12 days Wed 6/3/15 Thu 6/18/15 SPP,Members


148 87% Finalize Generation Review (QAP) 35 days Fri 6/19/15 Thu 8/6/15 SPP

149 0% Siting Plan 23 days Tue 12/1/15 Thu 12/31/15

150 0% ESWG/TWG Materials Development (Siting Plan) 3 days Tue 12/1/15 Thu 12/3/15 SPP,Members


152 0% Finalize Siting plan (QAP) 13 days Tue 12/15/15 Thu 12/31/15 SPP

153 0% Powerflow Model Development 23 days Mon 12/28/15 Wed 1/27/16

154 0% MDWG/TWG Materials Development (Powerflow Model) 4 days Mon 12/28/15 Thu 12/31/15 SPP,Members


156 0% Finalize Powerflow Model (QAP) 6 days Wed 1/20/16 Wed 1/27/16 SPP

157 0% Economic Model Development 11 days Fri 1/15/16 Fri 1/29/16

158 0% ESWG/TWG Materials Development (Economic Model) 2 days Mon 1/18/16 Tue 1/19/16 SPP,Members

159 0% Finalize Economic Model (QAP) 11 days Fri 1/15/16 Fri 1/29/16 SPP

160 0% Constraint Assessment 28 days Mon 12/21/15 Wed 1/27/16

161 0% TWG Materials development (Constraint Assessment) 9 days Mon 12/21/15 Thu 12/31/15 SPP,Members

162 0% TWG Review (Constraint Assessment) 10 days Tue 1/5/16 Mon 1/18/16 SPP,Members

163 0% Finalize Constraint Assessment (QAP) 6 days Wed 1/20/16 Wed 1/27/16 SPP

164 0% Generator Outlet Facilities 16 days Wed 11/25/15 Wed 12/16/15

165 0% ESWG/TWG Materials Development 4 days Wed 11/25/15 Mon 11/30/15 SPP,Members

166 0% ESWG/TWG Review 1 day Tue 12/15/15 Tue 12/15/15 SPP,Members

167 0% ESWG/TWG Approval 1 day Wed 12/16/15 Wed 12/16/15 SPP,Members

168 0% Engineering Planning Summit 1 day Tue 8/25/15 Tue 8/25/15

169 0% Engineering Planning Summit 1 day Tue 8/25/15 Tue 8/25/15 SPP,Members

SPP

Stakeholders,SPP

SPP,Members,Stakeholders (DPP)

SPP

SPP,Members

SPP

Members

SPP,Members

Members

SPP,Members

SPP

SPP

SPP,Members

SPP,Members

SPP,Members

Members,SPP

Members

SPP

SPP,Members

SPP,Members

SPP,Members

SPP

SPP,Members

SPP,Members

SPP,Members

SPP

SPP,Members

SPP,Members

SPP

SPP,Members

SPP,Members

SPP

SPP,Members

SPP

SPP,Members

SPP,Members

SPP

SPP,Members

SPP,Members

SPP,Members

SPP,Members


Page 3

Task

Split

Milestone

Summary

Project Summary

External Tasks

External Milestone

Inactive Task

Inactive Milestone

Inactive Summary

Manual Task

Duration-only


Manual Summary

Start-only

Finish-only

Progress

Deadline

Page 4

Project: SPP 2015 TWG Work ScheduDate: Tue 8/11/15

% Complete Name Duration Start Finish Predecessors Resource Names

47% SPP 2015 TWG Work Schedule - 08-11-2015 632 days Tue 4/1/14 Wed 8/31/16

50% 2015 TWG Meeting Schedule 217 days Tue 2/17/15 Wed 12/16/15

100% TWG February Meeting - San Antonio, TX 2 days Tue 2/17/15 Wed 2/18/15 Members,SPP

100% TWG Net Conference March 1 day Wed 3/18/15 Wed 3/18/15 Members,SPP

100% TWG Net Conference April 1 day Wed 4/22/15 Wed 4/22/15 Members,SPP

100% TWG May Meeting - Oklahoma City, OK 2 days Tue 5/19/15 Wed 5/20/15 Members,SPP

100% TWG Net Conference June 1 day Wed 6/17/15 Wed 6/17/15 Members,SPP

100% TWG Net Conference July 1 day Wed 7/22/15 Wed 7/22/15 Members,SPP

0% TWG August Meeting - Denver, CO 2 days Tue 8/18/15 Wed 8/19/15 Members,SPP

0% TWG Net Conference September 1 day Wed 9/16/15 Wed 9/16/15 Members,SPP

0% TWG Net Conference October 1 day Wed 10/21/15 Wed 10/21/15 Members,SPP

0% TWG November Meeting - SPP Little Rock 2 days Tue 11/17/15 Wed 11/18/15 Members,SPP

0% TWG Net Conference December 1 day Wed 12/9/15 Wed 12/9/15 Members,SPP

0% TWG Net Conference December 1 day Wed 12/16/15 Wed 12/16/15 Members,SPP

0% 2016 TWG Meeting Schedule 50 days Mon 1/18/16 Fri 3/25/16

0% TWG January Meeting 1 day Mon 1/18/16 Mon 1/18/16 Members,SPP

0% TWG February Meeting 1 day Fri 2/19/16 Fri 2/19/16 Members,SPP

0% TWG March Meeting 1 day Fri 3/25/16 Fri 3/25/16 Members,SPP

75% SPP Project Tracking 478 days Mon 11/3/14 Wed 8/31/16

100% Project Tracking 1st Quarter 30 days Mon 11/3/14 Fri 12/12/14

100% T.O.s submit updates 10 days Mon 11/3/14 Fri 11/14/14 Members

100% T.O.s provide cost increase justifications 6 days Wed 11/19/14 Wed 11/26/14 20 Members

100% T.O.s submit mitigation plans 18 days Wed 11/19/14 Fri 12/12/14 Members

100% Project Tracking 2nd Quarter 30 days Mon 2/2/15 Fri 3/13/15


100% T.O.s provide cost increase justifications 4 days Thu 2/19/15 Tue 2/24/15 24 Members

100% T.O.s submit mitigation plans 17 days Thu 2/19/15 Fri 3/13/15 Members

100% Project Tracking 3rd Quarter 31 days Fri 5/1/15 Fri 6/12/15

100% T.O.s submit updates 11 days Fri 5/1/15 Fri 5/15/15 Members

100% T.O.s provide cost increase justifications 5 days Wed 5/20/15 Tue 5/26/15 28 Members


0% Project Tracking 4th Quarter 30 days Mon 8/3/15 Fri 9/11/15


0% T.O.s provide cost increase justifications 5 days Wed 8/19/15 Tue 8/25/15 32 Members


100% 2015 MDWG Powerflow Models 76 days Wed 11/26/14 Wed 3/11/15

100% Pass 4 MDWG Powerflow Models 26 days Wed 11/26/14 Wed 12/31/14

100% Pass 4 - Members Review/Submit Changes to Pass 4 Powerflow Models 26 days Wed 11/26/14 Wed 12/31/14 Members

100% Pass 4 - Member Review/Changes Due 0 days Wed 12/31/14 Wed 12/31/14 Members

100% Build Pass 5 MDWG Powerflow Models (Unscheduled) 1 day Wed 11/26/14 Wed 11/26/14 SPP

100% Pass 5 (Unscheduled) - MDWG Powerflow Models 6 days Fri 1/30/15 Fri 2/6/15

100% Pass 5 - Posted for Members to submit DocuCheck corrections 3 days Fri 1/30/15 Tue 2/3/15 Members,SPP

100% Build Pass 6 MDWG Powerflow Models (Unscheduled) 3 days Wed 2/4/15 Fri 2/6/15 SPP

100% Pass 6 (Unscheduled) - MDWG Powerflow Models 6 days Fri 2/6/15 Fri 2/13/15

100% Pass 6 - Posted for Members to submit DocuCheck corrections 3 days Fri 2/6/15 Tue 2/10/15 SPP,Members

1


100% Build Final MDWG Powerflow Models 3 days Wed 2/11/15 Fri 2/13/15 SPP

100% Final MDWG Powerflow Models 6 days Wed 3/4/15 Wed 3/11/15

100% Final - Members Review for Finalization of MDWG Powerflow Models 5 days Wed 3/4/15 Tue 3/10/15 45 Members

100% Finalization - Conference Call Vote 1 day Wed 3/11/15 Wed 3/11/15 47 Members

100% 2015 MDWG Short Circuit Models 72 days Fri 12/19/14 Mon 3/30/15

100% Short Circuit Models Pass 1 66 days Fri 12/19/14 Fri 3/20/15

100% Pass 1 - Members Review/Submit Changes to Pass 1 Short Circuit Models 24 days Fri 12/19/14 Wed 1/21/15 SPP

100% Pass 1 - Member Review/Changes Due 0 days Wed 1/21/15 Wed 1/21/15 Members

100% Pass 1 - Build Final Short Circuit Models 43 days Wed 1/21/15 Fri 3/20/15 52 SPP

100% Pass 1 - Post MDWG 2015 Series Final Short Circuit Models 0 days Fri 3/20/15 Fri 3/20/15 53 SPP,Members

100% Short Circuit Models Final Pass 6 days Mon 3/23/15 Mon 3/30/15

100% Final - Member Review for Finalization of Short Circuit Models 5 days Mon 3/23/15 Fri 3/27/15 SPP

100% Finalization - Conference Call Vote 1 day Mon 3/30/15 Mon 3/30/15 56 Members

92% 2015 MDWG Dynamic Models 193 days Wed 11/26/14 Fri 8/21/15

100% Initial Data Update 60 days Wed 11/26/14 Tue 2/17/15

100% Build and Post DYRE Files, Wind Farm Data, and Docureport 12 days Wed 11/26/14 Thu 12/11/14 SPP

100% Members submit data updates 48 days Fri 12/12/14 Tue 2/17/15 Members

100% Build Final MDWG Dynamic Models 73 days Mon 4/27/15 Wed 8/5/15

100% 20 Second No-fault Test & Case Adjustment 61 days Mon 5/11/15 Mon 8/3/15 SPP

100% 60 Second Ring-Down Test & Case Adjustment 73 days Mon 4/27/15 Wed 8/5/15 63 SPP

100% NERC B&C Faults Test & Case Adjustment 63 days Thu 5/7/15 Mon 8/3/15 SPP

100% Dynamic Case Reduction 7 days Mon 5/18/15 Tue 5/26/15 SPP

61% MDWG Dynamic Case Review and Finalization 42 days Thu 6/25/15 Fri 8/21/15

100% Post Initial Models 1 day Fri 5/15/15 Fri 5/15/15 SPP

100% Member Review of Initial Models 11 days Mon 5/18/15 Mon 6/1/15 68 Members

100% Member Data Due 0 days Mon 6/1/15 Mon 6/1/15 69 Members

100% Final Data Update - Build Final Models 32 days Mon 6/1/15 Tue 7/14/15 70 SPP

100% Post Final Models 0 days Tue 7/14/15 Tue 7/14/15 71 SPP

100% Member Review for Finalization of MDWG Dynamic Models 10 days Tue 7/14/15 Mon 7/27/15 72 Members[90%]

100% Apply Member Feedback 10 days Tue 7/7/15 Mon 7/20/15 SPP

100% Re-post Final Models 0 days Fri 7/17/15 Fri 7/17/15 74 SPP

100% Member Review for Finalization of MDWG Dynamic Models 8 days Mon 7/20/15 Wed 7/29/15 75 Members[88%]

100% MDWG Dynamic Models - MDWG Vote 5 days Thu 7/30/15 Wed 8/5/15 76 Members

100% ERAG MRSS 2015 Summer Transmission Assessment 44 days Fri 2/6/15 Wed 4/8/15

100% ERAG MRSS 2015 Summer Transmission Assessment Study 32 days Fri 2/6/15 Mon 3/23/15 Members

100% TWG Comments on Report 6 days Wed 4/1/15 Wed 4/8/15 79 Members

100% TWG Approve SPP Section of Report 1 day Wed 4/8/15 Wed 4/8/15 80 Members

67% 2015 Annual Flowgate Assessment 74 days Fri 2/20/15 Wed 6/3/15

100% T.O.s review of all subsystem files 17 days Fri 2/20/15 Mon 3/16/15 Members

100% Staff run AC analysis 5 days Wed 4/8/15 Tue 4/14/15 83 SPP

100% T.O.s review of FG assessment 6 days Tue 5/12/15 Tue 5/19/15 84 Members

100% TWG Review/Approval 0 days Tue 5/19/15 Tue 5/19/15 Members

100% ORWG Review/Approval 0 days Wed 6/3/15 Wed 6/3/15 Members

100% TRM Assessment 32 days Mon 4/20/15 Wed 6/3/15

100% Staff calculate existing and new FG TRMs 17 days Mon 4/20/15 Tue 5/12/15 SPP

2


100% T.O.s review of TRM values 6 days Tue 5/12/15 Tue 5/19/15 Members

100% TWG Review/Approval 1 day Tue 5/19/15 Tue 5/19/15 Members

100% ORWG Review/Approval 0 days Wed 6/3/15 Wed 6/3/15 Members

100% FERC 715 Filing 5 days Tue 3/24/15 Mon 3/30/15

100% Staff to report the SPP filing is complete 5 days Tue 3/24/15 Mon 3/30/15 SPP

100% NERC RAS Summer Report 6 days Mon 3/23/15 Mon 3/30/15

100% TWG Comments on Report 6 days Mon 3/23/15 Mon 3/30/15 Members

100% Annual Review of ATC Process 15 days Thu 2/12/15 Wed 3/4/15

100% ATC Review 15 days Thu 2/12/15 Wed 3/4/15 SPP

26% 2015 NERC TPL-001-4 205 days Thu 2/26/15 Wed 12/9/15

50% NERC TPL Steady State Assessment, TPL 001-4 205 days Thu 2/26/15 Wed 12/9/15

100% TWG Scope Approval 1 day Wed 3/18/15 Wed 3/18/15 Members

56% NERC TPL Steady State Assessment, TPL 001-4 184 days Thu 2/26/15 Fri 11/13/15 SPP

0% TWG approval of 2015 Comprehensive TPL Assessment 1 day Wed 12/9/15 Wed 12/9/15 Members

38% NERC TPL Stability Study, TPL 001-4 147 days Tue 5/19/15 Wed 12/9/15

100% TWG Scope Approval 1 day Tue 5/19/15 Tue 5/19/15 Members

28% NERC TPL Stability Study, TPL 001-4 74 days Wed 8/19/15 Mon 11/30/15 SPP


34% NERC TPL Short Circuit Study, TPL 001-4 202 days Tue 3/3/15 Wed 12/9/15

100% TWG Scope Approval 1 day Wed 3/18/15 Wed 3/18/15 Members

21% NERC TPL Short Circuit Study, TPL 001-4 170 days Tue 3/3/15 Mon 10/26/15 SPP


23% ERAG MRSS 2015 Winter Transmission Assessment 98 days Tue 7/21/15 Thu 12/3/15

23% ERAG MRSS 2015 Summer Transmission Assessment Study 98 days Tue 7/21/15 Thu 12/3/15 Members,SPP

0% NERC RAS Winter Report 5 days Tue 9/15/15 Mon 9/21/15

0% TWG Comments on Report 5 days Tue 9/15/15 Mon 9/21/15 Members

27% SPP 2016 ITP Near-Term (12-month cycle) 583 days Tue 4/1/14 Thu 6/23/16

100% ITPNT Scope 96 days Tue 12/16/14 Tue 4/28/15

100% Finalize 2016 ITPNT Scope 96 days Tue 12/16/14 Tue 4/28/15 Members,SPP

100% ITPNT Models 97 days Tue 2/17/15 Wed 7/1/15

100% Develop Firm Service Scenario Models 69 days Tue 2/17/15 Fri 5/22/15 SPP

100% TWG Review Models 6 days Wed 6/24/15 Wed 7/1/15 Members

100% Develop CBA Scenario Models 53 days Mon 4/20/15 Wed 7/1/15 SPP[102%]

100% TWG Review CBA Scenario 6 days Wed 6/24/15 Wed 7/1/15 Members

0% ITPNT Study Work 257 days Wed 7/1/15 Thu 6/23/16

49% Needs Assessment 44 days Wed 7/1/15 Mon 8/31/15 SPP

0% DPP Window (includes cure period) 30 days Tue 9/1/15 Mon 10/12/15 Stakeholders,SPP

0% Solution Development 30 days Wed 10/28/15 Tue 12/8/15 SPP,Members,Stakeholders (DPP)

0% Conceptual Cost Estimates 30 days Thu 10/1/15 Wed 11/11/15 SPP

0% Develop 2016 ITPNT Draft Portfolio 33 days Thu 11/12/15 Mon 12/28/15 128 SPP,Members

0% Upgrade Determination (New 2A Process) 5 days Tue 12/29/15 Mon 1/4/16 SPP

0% TWG Review of initial Draft Portfolio 1 day Mon 1/18/16 Mon 1/18/16 Members

0% Study Cost Estimates (Non-competitive-TO's and Competitive - SPP) (New 2A Process) 39 days Tue 1/5/16 Fri 2/26/16 SPP,Members

0% TWG Review of Draft Final Portfolio 3 days Fri 3/25/16 Wed 3/30/16 Members

0% Final Portfolio Development 67 days Tue 12/29/15 Wed 3/30/16 SPP,Members

3


0% NERC TPL-001-4 Table 1 Planning Events 108 days Mon 11/2/15 Wed 3/30/16 SPP

0% ATRR / Rate Impacts on Final Portfolio 23 days Mon 2/29/16 Wed 3/30/16 132 SPP

0% 2016 ITPNT Report for MOPC/BOD 20 days Fri 4/1/16 Thu 4/28/16 SPP,Members

0% Short-Term Reliability Project Process 40 days Fri 4/29/16 Thu 6/23/16 SPP,Members

11% SPP 2017 ITP10 (18-month cycle) 268 days Wed 1/21/15 Fri 1/29/16

58% Scoping 192 days Wed 1/21/15 Thu 10/15/15

58% Create Draft Scope 192 days Wed 1/21/15 Thu 10/15/15 SPP,Members

0% TWG Review (Constraint Assessment) 183 days Tue 2/3/15 Thu 10/15/15 Members,SPP

0% TWG Approval 1 day Thu 10/15/15 Thu 10/15/15 Members

0% Post Final Scope 1 day Thu 10/15/15 Thu 10/15/15 SPP

84% Load Review 51 days Fri 5/1/15 Fri 7/10/15

100% Review ESWG/Tier 1 Feedback (Load Data) 14 days Fri 5/1/15 Wed 5/20/15 SPP,Members

100% ESWG Materials Development (Load Data) 3 days Mon 6/8/15 Wed 6/10/15 SPP,Members

0% TWG 1 day Wed 6/17/15 Wed 6/17/15 SPP,Members

75% Finalize Load Review (QAP) 16 days Fri 6/19/15 Fri 7/10/15 SPP

91% Generation Review 66 days Thu 5/7/15 Thu 8/6/15

100% Review ESWG/Tier 1 Feedback (Generation Data) 36 days Thu 5/7/15 Thu 6/25/15 SPP,Members

100% ESWG/TWG Materials Development (Generation Data) 12 days Wed 6/3/15 Thu 6/18/15 SPP,Members


87% Finalize Generation Review (QAP) 35 days Fri 6/19/15 Thu 8/6/15 SPP

3% Siting Plan 23 days Tue 12/1/15 Thu 12/31/15

0% ESWG/TWG Materials Development (Siting Plan) 3 days Tue 12/1/15 Thu 12/3/15 SPP,Members


0% Finalize Siting plan (QAP) 13 days Tue 12/15/15 Thu 12/31/15 SPP

11% Powerflow Model Development 23 days Mon 12/28/15 Wed 1/27/16

0% MDWG/TWG Materials Development (Powerflow Model) 4 days Mon 12/28/15 Thu 12/31/15 SPP,Members


0% Finalize Powerflow Model (QAP) 6 days Wed 1/20/16 Wed 1/27/16 SPP

12% Economic Model Development 11 days Fri 1/15/16 Fri 1/29/16

0% ESWG/TWG Materials Development (Economic Model) 2 days Mon 1/18/16 Tue 1/19/16 SPP,Members

0% Finalize Economic Model (QAP) 11 days Fri 1/15/16 Fri 1/29/16 SPP

0% Constraint Assessment 28 days Mon 12/21/15 Wed 1/27/16

0% TWG Materials development (Constraint Assessment) 9 days Mon 12/21/15 Thu 12/31/15 SPP,Members

0% TWG Review (Constraint Assessment) 10 days Tue 1/5/16 Mon 1/18/16 SPP,Members

0% Finalize Constraint Assessment (QAP) 6 days Wed 1/20/16 Wed 1/27/16 SPP

0% Generator Outlet Facilities 16 days Wed 11/25/15 Wed 12/16/15

0% ESWG/TWG Materials Development 4 days Wed 11/25/15 Mon 11/30/15 SPP,Members

0% ESWG/TWG Review 1 day Tue 12/15/15 Tue 12/15/15 SPP,Members

0% ESWG/TWG Approval 1 day Wed 12/16/15 Wed 12/16/15 SPP,Members

0% Engineering Planning Summit 1 day Tue 8/25/15 Tue 8/25/15

0% Engineering Planning Summit 1 day Tue 8/25/15 Tue 8/25/15 SPP,Members

4

Draft TWG Response for MOPC Action Item 206

Transmission Working Group

5/20/2015

MOPC Action Item #206

• From the MOPC Action Item List –

• This originated from discussion at the MOPC over the new Generator Interconnection Process

• BPWG asked MOPC to transfer action item to another Working Group – MOPC transferred to TWG

2

206 Investigate and report on Business Practices to reflect Limited Operations of GIs and how Integrated Marketplace may affect

April 16‐17, 2013

MOPC

In Progress

BPWG

TWG

Look at after work is complete on process changes

Perceived Problem

• Generators necessary to “keep the lights on” are sometimes hampered in their ability to interconnect quickly in the current process for Generator Interconnection.

• New process for Generator Interconnection will help facilitate generators necessary for reliability but may not contain a “silver bullet” for this issue

3

Potential Enhancement

• Type of Interconnection Service currently available – ERIS

– NRIS

– Interim ERIS/NRIS

• What if there was a new service?– Limited Generator Interconnection Service (LGIS?)

4

What would LGIS actually be?

• LGIS would be conditional Energy Resource Interconnection Service

• LGIS would allow generator to interconnect and operate on an “as called on” basis.

• When the Transmission Provider needs energy to meet reliability needs, it may call on the unit to operate within the framework of the existing conditions of the transmission system (i.e. no wind conditions).

• Installed only for reliability / does not compete with ERIS/NRIS units

• Abbreviated Study process for quick results5

Is this “Net‐Zero” Interconnection Service?

• No, Net‐Zero Interconnection Service (NZIS) offered by MISO allows for generators of differing fuel types to share Interconnection Service at the same Point of Interconnection.

• LGIS would not limit the location of the generation. For LGIS, the generation may be placed closer to load and be more effective for reliability needs.

6

TWG concerns with LGIS

• Queuing Issues – how do you study subsequent generators? Does this create free‐riders?

• Capacity Eligibility – would customers who request this think the generation would be eligible for capacity margin? Staff indicated they would not since that generation could not be counted upon.

• Transmission Service Eligibility ‐ would customers be able to receive transmission service?

• How do you enforce curtailments? No current enforcement procedures or policies.

7

TWG concerns with LGIS• Facilitates Grid Switchers – may cause grid switchers to

come on and off the SPP system with little to no notice.

• Lack of Need for LGIS – with the new GI process and the availability of Interim service, this product is not needed.

• Overall Reliability Concerns – exacerbates flowgates, possibility of new flowgates with no remedies.

8

TWG Recommendation

• TWG recommendation to MOPC regarding Action Item #206 is to not implement a service similar to Limited Generator Interconnection Service for these reasons.

9

TWG Response to MOPC Action Item #206

This action item was assigned to the TWG at the April 2015 MOPC meeting.

206 Investigate and report on Business Practices to reflect Limited Operations of GIs and how Integrated Marketplace may affect

April 16-17, 2013

MOPC

In Progress

TWG

Look at after work is complete on process changes

Further discussions with Staff and TWG stakeholders are detailed below.

Perceived Problem

It is perceived that some generators that are necessary to “keep the lights on” are sometimes hampered in their ability to interconnect in a timely manner. The ability to move through the Generator Interconnection Procedures (GIP) in a timely manner can be delayed while SPP deals with volumes of Interconnection Requests of the variable variety (wind/solar).

It was discussed that a new process in the GIP could help facilitate generators necessary for reliability purposes.

Limited Generator Interconnection Service (LGIS)

Staff brought a proposal to the TWG for discussion at their May 2015 meeting. The proposal called for a new service, Limited Generator Interconnection Service (LGIS) to be available for generators that wished to interconnect and operate on an “as called on” basis.

Basic principles of LGIS are

Generators with LGIS would be allowed to interconnect and operate on an “as called on” basis only.

When Transmission Provider needs energy to meet reliability needs, it may call on the unit to operate within the framework of the existing transmission system (i.e. no variable energy resources available)

Units would be compete with ERIS/NRIS units for market pricing Abbreviated Study for quick results Study would assume low variable energy resources on line Not Net‐Zero Interconnection Service, LGIS is not limited to a specific location and no

bi‐lateral agreements would be required.

Concerns with Limited Generator Interconnection Service

The TWG voiced concerns with LGIS. The concerns are listed below.

Queueing ‐ Many concerns were in regards to the GI queue process. The TWG felt that while the process might work for the first generator, it then thoroughly complicates and frustrates the study of subsequent generators in the queue. It was not agreed upon how the LGIS generator should be treated in those studies. There is a possibility of creating “free‐riders” on the system that benefit from upgrades that other entities pay to build. Staff mentioned that if the LGIS generator was truly not being granted any kind of permanent service other than “as called on” that the LGIS generator could be ignored in the subsequent studies. The TWG was not convinced of the validity of that methodology from a reliability perspective.

Capacity Eligibility – Some concerns were what exactly that Interconnection Customers who requested LGIS thought they would be receiving. Some members thought that customers thought they would be able to count the generation towards capacity margin or firm transmission service. Staff indicated that the proposal brought to the TWG did not have this in mind. However, it was mentioned by other participants that the Capacity Margin Task Force (CMTF) was looking at new ways to evaluate capacity margin. This caused concern from the TWG in that a member could count a generator for capacity margin requirements when that generator could not be guaranteed to be available at all times. This is true of LGIS units since there are times (of high wind/solar conditions) when those units would not be available.

Transmission Service Availability – the same concerns for transmission service as for capacity margin were voiced by the TWG participants.

Enforcement – There is no current methodology for enforcing that a generator that is not needed for reliability is not generating.

Grid Switching Facilitation – one participant asked the question about how LGIS would play into allowing grid switchers to come on and off of the SPP system, possibly with little notice. Staff indicated that LGIS would probably facilitate that to a great extent. That was not viewed upon as a good thing by the group.

Lack of Need for a New Product – One participant did not see the need for the LGIS product. He indicated that between the new Generator Interconnection process has cut down on speculative requests progressing through the queue, and the Interim GIA process that allows generators to receive GIAs quicker if needed, that this new service is not a necessity. The questions was asked, what reliability problems has SPP experienced due to generators not being allowed to interconnect as quickly as they wished. This product seems to create more problems than it fixes.

Overall Reliability Concerns – TWG was also concerned that LGIS would exacerbate existing flowgates and cause new flowgates to be created. The concern is that no one would be responsible to fix new flowgates and further degrade reliability on the system. While some participants mentioned that the current processes could be causing overbuilding of transmission facilities in the footprint, that view was

not shared amongst a majority of the group. Staff mentioned that the only study scenario that Staff studies all VERs and dispatchable generation together is in the stability analyses. This also helps prevent overbuilding. There were also concerns that the ORWG has not yet been asked their view of the potential service.

TWG Recommendation to MOPC for Action Item #206

The TWG Recommendation to MOPC regarding Action Item #206 is to not implement a service similar to Limited Generator Interconnection Service for the reasons listed above.

NRIS Update


8/19/2015

Network Resource Interconnection Service

• In 2009, FERC issued order to SPP to re‐insert Order 2003 language concerning Network Resource Interconnection Service (ER09‐1255).

• “Transmission Provider must conduct the necessary studies and the Transmission Owner construct the Network Upgrades needed to integrate the Generating Facility in a manner comparable to that in which Transmission Owner integrates its generating facilities to serve Native Load Customers as Network Resources. Network Resource Interconnection Service allows Interconnection Customer's Generating Facility to be designated as a Network Resource, up to the Generating Facility's full output, on the same basis as existing Network Resources interconnected to Transmission Provider's Transmission System, and to be studied as a Network Resource on the assumption that such a designation will occur.”

2

Network Resource Interconnection Service• NRIS currently addressed in Business Practice 7250

• SPP currently studies NRIS – Within the Generator Interconnection process

– At 100% nameplate of the unit

– to the host transmission zone

– 3% TDF mitigation for constraints

• With the beginning of the Integrated Market, NRIS needs to be modified.

3

Network Resource Interconnection Service• Proposal

– NRIS to be studied to the entire SPP footprint by displacing generation in all areas for the ratio of the load of the area (similar to ERIS) Impacts may be diluted

– NRIS to be studied using scenario 5 models

– ERIS generators not included in study unless they have firm service or are under study for firm service

– To be studied for 5% TDF mitigation of constraints

4

Network Resource Interconnection Service• Staff brought this initial proposal to TWG at the May

meeting. Staff was directed to move forward and bring proposed changes to applicable business practice(s).

• TWG is asked to provide comments on the draft revision of BP7250 to address these changes.

5

Business Practice Revision

Page 1 of 6

BPR Number

BPR065 BPR Title

BP 7250 Modification

Business Practice Section(s) Requiring Revision (include Section No., Title, and Protocol Version)

BP 7250

Impact Analysis Required (Yes or No)

No

MMU Report Required (Yes or No) No

Requested Resolution (Normal or Urgent) Normal

Revision Description Changes the process for studying Network Resource Interconnection Service

Reason for Revision Allow for better process to mesh with the Integrated Marketplace

Tariff Implications or Changes (Yes or No; If yes include a summary of impact and/or specific changes)

N

Criteria Implications or Changes (Yes or No; If yes include a summary of impact and/or specific changes)

N

Credit Implications (Yes or No, and summary of impact)

N

Working Group/Committee Review and Results

BPWG – RTWG – TWG – MOPC –

Sponsor


Page 2 of 6

Name Charles Hendrix E-mail Address [email protected] Company Southwest Power Pool Company Address 201 Worthen Drive Phone Number 501-614-3546 Fax Number

Proposed Business Practice Language Revision

7250 GENERATOR INTERCONNECTION SERVICE (return to TOC)

Generator Interconnection Service is provided by SPP pursuant the Generator

Interconnection Procedures (Attachment V). Process and procedure guidelines have been established in order to attain a common understanding regarding the study process and the integration of Network Resource Interconnection Service (NRIS) facilities and Energy Resource Interconnection Service (ERIS) facilities into the SPP Transmission System.

Business Practice Current Day Rules and Procedures:

1.1) Energy Resource Interconnection Service (ERIS) will be studied based on Attachment V of the SPP OATT, using various percentages of Generation Interconnection request values spread to the entire SPP footprint based on the load ratio share of the Transmission Owner zones. Upgrades required to interconnect the ERIS generating facility will be cost allocated based on a 20% TDF threshold for outage based constraints and 3% TDF threshold for system intact constraints. Stability impacts attributed to the generators must be mitigated regardless of the TDF impact.

2) Network Resource Interconnection Service (NRIS) facilities will be studied based on an analysis through Attachment V of the SPP Open Access Transmission Tariff (OATT), using the nameplate amount of the resource to the entire SPP footprint based on the load ratio share of the Transmission Owner zones. interconnection host zone. Upgrades required to interconnect will be identified and cost assigned based on a 53% TDF threshold for both system intact and outage based conditions. NRIS studies also include an ERIS component as described abovewhich uses various percentages of nameplate values spread to the entire footprint based on the load ratio share of the Transmission Owner zones. Upgrades required to interconnect will be identified and cost allocated based on

Formatted


Page 3 of 6

the appropriate threshold criteria. The models for NRIS will be developed in accordance with the following methodologies

1. Generators from the Interconnection Queue will be added to the ITPNT models based on the following method.

1. NRIS generators and ERIS generators under study in the TSR process to be added to models

2. All Seasons (SPP footprint not divided into regional groups)

1. Variable energy generation – 100% nameplate

2. Fully dispatchable generation – 100% nameplate

2)

3) Once interconnection is complete, there is no difference between SPP Operations’ treatment of generating facilities regardless of generation interconnection type (NRIS or ERIS).

4) Neither NRIS nor ERIS guarantees transmission service or deliverability pursuant

to Part II or Part III of the SPP OATT. Transmission service must be requested and studied through the same process as any other Designated Resource wanting to deliver energy to a specified point (Point-To-Point Transmission Service) or to a specified Network Load (Network Integrated Transmission Service).

5) NRIS does not guarantee but may allow for the generator to be designated for capacity requirements.

5)6) Base Plan funding determinations for Base Plan Upgrades are subject to limits stated in Attachments Z2 and J of the SPP OATT. Upgrades required to attain either NRIS or ERIS are not eligible for Base Plan funding.

Future Procedure consideration: 1) Current business rules will change once the new SPP Integrated Marketplace is

implemented.

Definitions

Formatted: Indent: Left: 0.5", No bullets or numbering


Page 4 of 6

Designated Resource: Any designated generation resource owned, purchased or leased by a Transmission Customer to serve load in the SPP Region. Designated Resources do not include any resource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be called upon to meet the Transmission Customer's load on a non-interruptible basis. Energy Resource Interconnection Service: An Interconnection Service that allows the Interconnection Customer to connect its Generating facility to the Transmission System to be eligible to deliver the Generation Facility’s electric output using the existing firm or nonfirm capacity of the Transmission System on an as available basis. Energy resource Interconnection Service in and of itself does not convey transmission service. Firm Transmission Service: The highest quality (priority) service offered to customers under a filed rate schedule that anticipates no planned interruption. Grandfathered Agreements or Transactions: Grandfathered Agreements or Transactions include (1) agreements providing long term firm transmission service executed prior to April 1, 1999 and Network Integration Transmission Service executed prior to February 1, 2000; (2) bundled wholesale contracts (that reserve transmission as part of the contract); (3) short-term firm and non-firm point-to-point transmission transactions which were accepted and confirmed prior to the Effective Date; (4) existing or new contracts entered into by the Southwestern Power Administration on behalf of the United States for the use of transmission facilities of the Southwestern Power Administration that are constructed or acquired by purchase or other agreement, as authorized under Section 5 of the Flood Control Act of 1944, for the transmission of Federal Power; and (5) contracts executed before the Effective Date, regardless of term, entered into by the Southwestern Power Administration on behalf of the United States for the transmission of power or energy across transmission facilities owned and operated by the Southwestern Power Administration; (6)contracts entered into by a Nebraska public-power entity prior to the transfer of functional control of its transmission facilities to the Transmission Provider; (7) existing contracts entered into by a Member which is a Nebraska public-power entity with any retail or wholesale electric utility customer that has a right under state law to obtain electric transmission service or energy service from such Member; and (8) new contracts entered into by a Member which is a Nebraska public-power entity with any retail or wholesale electric utility customer that has a right under state law to obtain electric transmission service or energy service from such Member to the extent that provision of service under the Tariff would not satisfy such Member’s obligation under state law. These agreements are set forth on the list which is Attachment W to this Tariff. Umbrella service agreements are specifically not Grandfathered.


Page 5 of 6

Long-Term Service: Long-Term Firm Point-To-Point Transmission Service or Network Integration Transmission Service of one year or longer in duration. Network Integration Transmission Service: Service that allows an electric transmission customer to integrate, plan, economically dispatch and regulate its network reserves in a manner comparable to that in which the Transmission Owner serves Native Load customers. This transmission service is provided under Part III of the SPP Tariff. Network Resource Interconnection Service: An Interconnection Service that allows the Interconnection Customer to integrate its Generating Facility with the Transmission System in a manner comparable to that in which the Transmission Owner integrates its generating facilities to serve Native Load Customers as a Network Resource. Network Resource Interconnection Service in and of itself does not convey transmission service. Non-Firm Transmission Service: Transmission service that is reserved on an as-available basis and is subject to curtailment or interruption. OATT: Open Access Transmission Tariff

Part II: Tariff Sections 13 through 27 pertaining to Point-To-Point Transmission Service in conjunction with the applicable Common Service Provisions of Part I and appropriate Schedules and Attachments.

Part III: Tariff Sections 28 through 36 pertaining to Network Integration Transmission Service in conjunction with the applicable Common Service Provisions of Part I and appropriate Schedules and Attachments. Point-To-Point Transmission Service: The reservation and transmission of capacity and energy on either a firm or non-firm basis from the Point(s) of Receipt to the Point(s) of Delivery under Part II of the SPP Tariff. Short-Term Service: Short-Term Firm Point-To-Point Transmission Service or Network Integration Transmission Service of less than one year in duration. SPP: The Southwest Power Pool, Inc. Transfer Distribution Factor (TDF): A general term, which may refer to either PTDF or OTDF – The TDF represents the relationship between the participation adjustment of two areas and the Flowgates within the system.


Page 6 of 6

Transmission System: The facilities used by the Transmission Provider to provide transmission service under Part II, Part III and Part IV of the SPP Tariff. SPP OATT References: Part II Part III Attachment C Attachment J Attachment V Attachment AC Attachment Z1 & Z2

CSP Regional Review Process – Reliability Results

TWGAugust 18 – 19, 2015

Regional Review Presentation Overview

• Reliability Power Flow Model

• No‐Harm Evaluation

• Avoided Reliability Metric

2

Proposed Interregional Projects

• Projects identified and recommended for approval in the SPP‐MISO Coordinated System Plan Study

– Elm Creek to NSUB5 345 kV

– Series Reactor on Alto to Swartz 115 kV

– Rebuild South Shreveport to Wallace Lake 138 kV

3

Model

• Final Regional Review reliability model

– Started with the SPP‐MISO CSP 2024 summer peak model

– Included 2015 ITPNT and ITP10 NTC projects

– Updated model based on stakeholder feedback provided in the development of the Regional Review economic model

– Stakeholders provided additional model updates by July 28th

4

No‐Harm Evaluation Results

• Performed ACCC analysis to determine if any new reliability needs were created by the inclusion of any of the Interregional Projects

– Compared needs list from an initial ACCC run with needs from an ACCC run including the potential interregional projects

– No additional needs were identified

5

Avoided Reliability Metric

• Leveraged the ACCC Analysis performed for the No‐Harm Evaluation to determine if any thermal needs were mitigated by the proposed interregional project(s)

– South Shreveport to Wallace Lake 138kV – Interregional Project mitigates the need for the South Shreveport to Wallace Lake 138kV – ITP10 Project

– No other avoided reliability benefit was determined

6

RELIABILITY PROJECT VALUATION

7

How to Calculate Reliability Replacement Benefit

• As applies to Regional Review of proposed Interregional Projects

– Magnitude of SPP benefit not allocation of benefits

– No impact on zonal allocation of benefits

• If the proposed interregional project replaces an SPP regional project the benefit value is the cost of the regional project being replaced

– If Interregional Project AB eliminates the need for SPP Regional Project CD, the reliability benefit of Interregional Project AB is the cost of Regional Project CD

8

Conceptual Example 1

9

A

B

C DSPP ITPNT Project

SPP-MISO Interregional Project completely eliminates the need for the SPP Regional Project

SPP Benefit: $25 MillionSPP Cost: $20 Million

Conceptual Example 2

10

A

B

A

B

SPP-MISO Interregional Project completely addresses reliability issues as identified in SPP’s approval of the project in the ITPNT

SPP Benefit: $40 MillionSPP Cost: $20 Million

Rebuild S Shreveport – Wallace Lake 138 kV

11

A

B

A

B

SPP-MISO Interregional Project Rebuild S. Shreveport – Wallace Lake 138 kV completely addresses reliability issues as identified in SPP’s approval of the project in the 2015 ITP10

SPP Benefit: $18.5 MillionSPP Cost: $3.7 Million

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RR #: 56 Date: 8/10/2015

RR Title: Upgrade Determination and Short-Term Reliability Project Process


Submitter Name: Tony Green Company: Southwest Power Pool

Email: [email protected] Phone: (501)688-1789

EXECUTIVE SUMMARY OF ACTION AND RECOMMENDATION


Describe the problem/issue this revision request will resolve:

Attachment Y of the Tariff describes the categories that determine if a transmission project may be issued to an incumbent Transmission Owner or through the Transmission Owner Selection Process. In order to comply with FERC Order 1000 and Attachment Y of the Tariff, procedures need to be developed to insure that the proper section of the Tariff is used to issue Notifications to Construct.


Compliance with FERC Order 1000 and the SPP Tariff, as well as providing clear communication to stakeholders participating in the process.








Tariff Tariff Section(s):

Business Practice Business Practice Number: NEW WORKING GROUP REVIEWS AND RECOMMENDATIONS


Primary Working Group: BPWG

Date: 5/27/2015, 7/29/2015, 8/21/2015

Action Taken: 5/27/15: Initial review only. 7/29/15: 2nd Review. Minor grammatical change. 8/21/15: Seeking approval.

Abstained:

Opposed:

Reason for Opposition:

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Secondary Working Group: CTPTF (Primary Secondary)

Date: 5/7/2015, 7/30/2015

Action Taken: 5/7/2015: Initial review only. 7/30/15: Review and changes made; motion to approve with changes contingent on no significant changes by other working groups/task forces. Vote: Unanimously approved.

Abstained: 0

Opposed: 0


Secondary Working Group: PCWG

Date: 6/3/2015, 8/5/2015

Action Taken: 6/3/15: Initial review only; requested changes applied. 8/5/15: Review and changes made; motion to approve with changes. Vote: Unanimously approved.

Abstained: 0

Opposed: 0


Secondary Working Group: ORWG

Date: 8/6/2015

Action Taken: Reviewed; no changes. Vote: Unanimously approved.

Abstained: 0

Opposed: 0


Secondary Working Group: ESWG

Date: 7/9/2015, 8/19/2015

Action Taken: 7/9/15: Initial review only; change made to specify that economic and public policy changes not in STR Project Process. 8/19/15: Seeking approval.

Abstained:

Opposed:


Secondary Working Group: TWG

Date: 7/22/2015, 8/19/2015

Action Taken: 7/22/15: Initial review only. 8/19/15: Seeking approval.

Abstained:

Opposed:


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RTWG

Date: 7/23/2015, 8/27/2015

Action Taken: 7/23/15: Initial review only. Minor changes suggested and applied for posting for BPWG on 7/29 and CTPTF on 7/30. 8/27/15: Seeking approval.

Abstained:

Opposed:


MOPC

Date: October 2015

Action Taken:

Abstained:

Opposed:


BOD/Member Committee

Date: October 2015

Action Taken:

Abstained:

Opposed:


COMMENTS

Comment Author: David Kayes, OG&E


This revision request does not describe "what the problem is or what needs fixing". In the "Objective" section the author immediately describes what the new solution and makes no mention of what the problem is. This request should either be revised to describe the problem (as directed) or rejected as incomplete.

Status: Objective corrected in separate comment form.

Comment Author: Sherri Maxey, SPP staff

Description of Comments: Minor grammatical changes for RR56.

Changes to the “Objectives of Revision Request:” section, as follows:

Describe the problem/issue this revision request will resolve:

Attachment Y of the Tariff describes the categories that determine if a transmission project may be issued to an incumbent Transmission Owner or through the Transmission Owner Selection Process. In order to comply with FERC Order 1000 and Attachment Y of the Tariff, procedures need to be developed to insure that the proper section of the Tariff is used to issue Notifications to Construct.


Compliance with FERC Order 1000 and the SPP Tariff, as well as providing clear communication to stakeholders participating in the process.

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Status: Changes applied.

Comment Author: Sherri Maxey, SPP staff

Description of Comments

(1) Updates to process flowcharts per PCWG feedback and added process flow for Short-Term Reliability Project Process; and

(2) Internal SPP staff changes after legal review.

Status: Changes applied.

Comment Author: Dennis Reed and SPP staff

Description of Comments

The RR as written does not accurately reflect the Tariff. A project is assigned to a DTO either through the ITO or the TOSP process. The qualification of a project as an STR only switches the process of determining the DTO from TOSP to ITO. In addition there is no reason to take an upgrade through the STR process if it already qualifies to have the DTO determined through the ITO process. I will also note the STR process was intermixing the approval and posting of the STR report with the approval of an upgrade to be designated as a STR. If the STR report has more than one upgrade described in it, then the process required the Board to approve all the upgrades as STRs or none of them. My edits are to make the process clearer and conform to the approved Tariff language.

SPP Comment

Internal SPP staff made minor changes and would like to clarify comments in (3) above: A project is either assigned to the ITO or selected through the Transmission Owner Selection Process (TOSP). The qualification of a project as a STR Project only switches the process of assigning the project to the ITO, rather than through the TOSP. In addition, only a project that would qualify for the TOSP could be subject to the STR Project process.

Changes per ESWG to STR Project Process to specify that economic and public policy projects are not considered in the STR Project process.

Status: Changes applied with modifications.

Comment Author: CTPTF 7/30/15 Teleconference

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Description of Changes:

In first paragraph, added ("ITO") in the second sentence, prior to "; or (2)" Under "Upgrade Determination" section, replace verbiage in bullet 6 with Tariff language from Attachment Y, Section I(2) of

the SPP Tariff, modified as follows:

“For transmission projects involving both a Rebuild of existing facilities and the construction of new transmission facilities, SPP shall determine which Tariff process is used to select TO(s), as follows:

If 80% or more of the total cost of a project consists of the Rebuild of existing facilities, the upgrade will be designated to the ITO in accordance with Section IV of this Attachment Y;

Otherwise, the project will be divided into two or more segments or upgrades, based upon whether that portion of the project is a Rebuild of existing facilities or new facilities. For those segments that are Rebuilds of existing facilities, the upgrade will be designated to the ITO in accordance with Section IV of this Attachment Y. For those segments that are new facilities and determined to be a Competitive Upgrade, those upgrades will be designated pursuant to the TOSP in accordance with Section III of this Attachment Y.

Figure 2 below illustrates upgrade determination for projects with new and Rebuild portions.

In the paragraph following the last bullet under the "Upgrade Determination" section, changed first sentence to: "For transmission facilities that meet the above requirements to be a Competitive Upgrade, but are required to be in service within three (3) years or less to address an identified reliability violation, may be exempted from the TOSP if approved by the Board."

Modify title of Figure 2 graphic to "Upgrade Determination for Projects with New and Rebuild portions" and keep "Figure 2" graphic.

In the first bullet under the STR Project Process section, delete "through the Integrated Transmission Planning (“ITP”) or high priority study processes by the Board." In that same bullet, add "or less based on the RTO Determined Need Date" prior to the last sentence.

Modify Figure 3 graphic to show last decision diamond have the text of "Did the SPP Board approve the STR Project?" Also, have "No" going to TOSP process and "Yes" continuing on to the actions in the light blue box.

Status: Changes applied and unanimously approved.

Comment Author: PCWG 8/5/15 Teleconference

Description of Changes:

4th bullet under Upgrade Determination section: note added “Approved by FERC 8/3/15” In the paragraph following the last bullet under the "Upgrade Determination" section, changed to delete the first word of first

sentence, “For” and replace last word in paragraph “below” with the word “section.” The paragraph now reads: "Transmission facilities that meet the requirements to be a Competitive Upgrade, but are required to be in service within three (3) years or less to address an identified reliability violation, may be exempted from the TOSP if approved by the Board. Details of this process are described in the STR Project Process section."

Figures 1, 2 and 3: The blue color was lightened in the decision diamonds for readability. RTO Determined Need Date is not a Tariff‐defined term, so capitalization removed. In the 4th bullet under STR Project Process section, added an “s” to the word “Market.”

Status: Changes applied and unanimously approved.

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Upgrade Determination and Short‐Term Reliability Project Process Business Practice

This business practice outlines the procedures SPP utilizes to determine which Tariff process is used to select a Transmission Owner (“TO”) for upgrades approved by the SPP Board of Directors (“Board”) for construction. The two (2) processes utilized include whether an upgrade is: (1) assigned to the incumbent TO, as described in Attachment Y, Section IV (“ITO”); or (2) assigned to a Designated Transmission Owner as a Competitive Upgrade using the Transmission Owner Selection Process (“TOSP”), as described in Attachment Y, Section III of the SPP Tariff. In addition, if a Competitive Upgrade meets the qualification as a Short‐Term Reliability (“STR”) Project, the project may be assigned to an incumbent TO by the Board. The criteria for determining if a transmission upgrade is assigned to an incumbent TO or through the TOSP process is described in Attachment Y, Section I.3 of the SPP Tariff.

Upgrade Determination

SPP will use the following checklist to determine what process is used in selection of a TO for upgrades, as outlined in Attachment Y, Section I of the SPP Tariff. A transmission upgrade must satisfy all of the following requirements in order to be a Competitive Upgrade:

Transmission facilities that are an Integrated Transmission Plan (“ITP”) upgrade, high priority upgrade, or Interregional Project.

Transmission facilities that have a nominal operating voltage greater than 100 kV.

Transmission facilities that are not a Rebuild of an existing facility. Rebuild is defined in Attachment Y, Section I.2 of the SPP Tariff.

Transmission facilities that do not alter a TO’s use and control of its existing rights‐of‐way under relevant law or regulations.

Transmission facilities located where selecting the TO using the TOSP does not violate relevant law.

For transmission projects involving both a Rebuild of existing facilities and the construction of new transmission facilities, SPP shall determine which Tariff process is used to select TO(s), as follows:

o If 80% or more of the total cost of a project consists of the Rebuild of existing facilities, the upgrade will be designated to the ITO in accordance with Section IV of this Attachment Y;

o Otherwise, the project will be divided into two or more segments or upgrades, based upon whether that portion of the project is a Rebuild of existing facilities or new facilities. For those segments that are Rebuilds of existing facilities, the upgrade will be designated to the ITO in accordance with Section IV of this Attachment Y. For those segments that are new facilities and determined to be a Competitive Upgrade, those upgrades will be designated pursuant to the TOSP in accordance with Section III of this Attachment Y.

o Figure 2 below illustrates upgrade determination for projects with new and Rebuild portions.

Transmission facilities that are not a Local Transmission Facility.

Commented [SM1]: Updated per CTPTF 7/30/15.

Commented [SM2]: Pending FERC language; Docket No. ER13-1939

Commented [TCK3]: FERC language in Docket No. ER13-366

Commented [SM4]: Approved by FERC 8/3/15

Commented [SM5]: New language per CTPTF 7/30/15; slight rewording of Tariff language to fit BP.

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Transmission facilities that meet the above requirements to be a Competitive Upgrade, but are required to be in service within three (3) years or less to address an identified reliability violation, may be exempted from the TOSP if approved by the Board. Details of this process are described in the STR Project Process sectionbelow.

Figures 1 and 2 below illustrate the decision points used in determining which of the two (2) processes itemized above will be utilized in determining whether an upgrade is a Competitive Upgrade subject to the TOSP or designated to the incumbent TO.

Figure 1:

Commented [SM6]: Updated per PCWG 8/5/15

Commented [SM7]: Updated per CTPTF 7/30/15

Commented [SM8]: Change per PCWG 8/5/15

Commented [SM9]: Figures 1, 2 and 3 lightened the colors used with the graphics for readability.

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Figure 2:

Designation to Incumbent TO

If an upgrade does not satisfy the requirements to be a Competitive Upgrade, the upgrade will be designated to the incumbent TO as described in Attachment Y, Section IV of the SPP Tariff, and SPP Business Practice 7060.

Designation Pursuant to TOSP

If an upgrade is determined to be a Competitive Upgrade, the Competitive Upgrade will be designated pursuant to the TOSP as described in Attachment Y, Section III of the SPP Tariff, and SPP Business Practice 7700.

STR Project Process

For any reliability upgrade that would otherwise have the TO assigned through the TOSP be considered a STR Project, as defined in Attachment Y, Section I of the SPP Tariff, SPP staff will:

Identify the time‐sensitive needs and post an explanation (the “STR Project Report”) on the SPP website pursuant to Attachment Y, Section I of the SPP Tariff, once an upgrade is approved for construction through the Integrated Transmission Planning (“ITP”) or high priority study processes by the Board. To qualify as a STR Project, the upgrade must have (1) qualified to have the TO assigned through the TOSP process, (2) be required to be constructed to solve a reliability issue, and (3) be required to be in service within three (3) years or less based on the RTO determined need date. Economic and public policy projects are not considered in the STR Project Process.

Commented [SM10]: Updated Figure title per CTPTF 7/30/15

Commented [SM11]: Do both Boards have to approve for interregional projects? Yes. Pending FERC language; Docket No. ER13-1939.

Commented [SM12]: Updated per CTPTF 7/30/15 Also, PCWG 8/5/15 – RTO determined need date not a Tariff term so capitalization removed.

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The STR Project Report will contain at least the following information for each upgrade contained in the report: (1) a description of each upgrade, (2) demonstrate why each upgrade is needed within the three (3) year reliability window and (3) why the upgrade was not identified earlier. Notification of when the report is posted will be sent via email exploder.

Once the STR Project Report is posted and notification sent out, stakeholders will have a 30 day period in which to provide comments regarding whether or not the project(s) described in the report should be classified as a STR Project. Those comments will be received via the SPP Request Management System (“RMS”), with the instructions provided in the notice posting.

After the 30‐day period, the STR Project Report and comments will be sent to the Markets and Operations Policy Committee (“MOPC”) and Board for their review and approval at the next quarterly meeting. The Board may approve one or more upgrades from the report as a STR Project.

The approved STR Project Report and comments will be stored on the SPP website including those upgrades that were approved as a STR Project.

The approved STR Project Report, and list of upgrades designated as a STR Project will be filed with FERC as an informational filing in the following January.

If the Board approves an upgrade as a STR Project, a Notification to Construct (“NTC”) will be issued in accordance with Attachment Y, Section IV of the SPP Tariff, and SPP Business Practice 7060.

If the Board does not approve an upgrade as a STR Project, then SPP shall initiate the TOSP process in accordance with Attachment Y, Section III of the SPP Tariff and SPP Business Practice 7700.

Figure 3 below illustrates the STR Project Process.

Commented [SM13]: Added “s” per PCWG 8/5/15.

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Figure 3:

Competitive Upgrade Transmission Report

The Competitive Upgrade Transmission Report is a report issued by SPP no later than seven (7) calendar days following the approval of one (1) or more Competitive Upgrade by the Board, which shall provide general information regarding the approved Competitive Upgrades.

This report will include the following items (See Figure 4 – Draft Competitive Upgrade Transmission Report):

Competitive Upgrade description;

State(s) in which project is to be built;

Study Name from which Competitive Upgrade was issued;

Need date(s) from Board‐approved study;

Anticipated financial expenditure date;

Expected Request for Proposal (“RFP”) issue date;

Expected RFP Response Window; and

Indication if Competitive Upgrade(s) have an associated Detailed Project Proposal (“DPP”).

Commented [SM14]: Updated per CTPTF on 7/30/15

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Figure 4:

This report will be posted on the SPP website.

Market Protocols

Tariff (OATT)

SPP Criteria

Steady State Reliability Metrics in the ITP

Michael [email protected]

• Previous ITPNT focused on least cost factor to determine which project was selected for the final portfolio

• Other factors can be used when selecting the most beneficial project

• Steady State Planning developed two new metrics to help in project selection for individual needs

2

Background

• A metric to coincide with voltage and thermal needs was selected by SSPL

• Cost per Loading Relief (CLR) provides the amount of thermal loading relief for the cost of a project for a need

• Cost per Voltage Relief (CVR) provides the amount of voltage support for the cost of a project for a need

• Both metrics consider project cost and the amount of relief the project provides

3

Metrics Concepts

• Cost per Loading Relief (CLR) provides the amount of thermal loading relief for the cost of a project for each need• Cost / (100% Loading – Post % Loading)• The lower the CLR value the better

4

Cost per Loading Relief Metric

NEED PROJECT COST POST % LOADING

RELIEF (100% ‐ POST LOADING%)

CLR ($/RELIEF) RANK

N1 P1 $ 500,000.00 50.9 49.1 10183.30 2N1 P2 $ 200,000.00 46.3 53.7 3724.39 1N1 P3 $ 1,500,000.00 51.3 48.7 30800.82 3

• Cost per Voltage Relief (CVR) provides the amount of voltage support for the cost of a project for a need• Weight increases as the post p.u. voltage moves to 1• The lower the CVR value the better

5

Cost per Voltage Relief Metric

RANGE HIGH

RANGE LOW WEIGHT NEED PROJECT COST POST

p.u. V RELIEF COST/RELIEF RANK

1.05 1.04 1 N1 P1 $ 156,086,984.50 0.979 16 9755436.53 1<1.04 1.03 5 N1 P2 $ 156,086,984.50 0.930 8 19510873.06 2<1.03 1.02 10 N1 P3 $ 213,987,859.40 0.920 6 35664643.23 3<1.02 1.01 15<1.01 1 20<1 0.99 20

<0.99 0.98 18<0.98 0.97 16<0.97 0.96 14<0.96 0.95 12<0.95 0.94 10<0.94 0.93 8<0.93 0.92 6<0.92 0.91 4<0.91 0.9 2

• For each thermal and voltage need, the best project will be selected based on selection criteria

• Selection criteria used in ranking projects include:• Cost / Loading Relief• Cost / Voltage Relief (support)

• Each project has the criteria calculated for each need

• Each need has one or more projects developed to fix the need

• Best project identified for each need

6

Best Project Identification

• Metrics are calculated for each project’s performance for each need

• Best project (lowest cost for amount of relief) is identified for each need

• Project displacement algorithm is ran to identify projects that can displace “best projects” for each need

• Check relief comparison of best projects and displacing projects to ensure valid displacement

• Selected projects move to the project portfolio

7

Project Selection Methodology

• Approve the use of Cost per Loading Relief (CLR) and Cost per Voltage Relief (CVR) Steady State Reliability Metrics in the reliability analysis portion of the ITP study processes

8

Recommendation

Non‐Competitive Cost EstimatesDiscussion

August 19, 2015

Current 2016 ITPNT Timeline

2

**AllProjectSchedulesSubjecttoChange**

2016 ITPNT Timeline with Solution 2A

3


2016 ITPNT Schedule Impacts

4

Current 2016 ITPNT Timeline

1


2016 ITPNT Solution 2A Staff Recommendation

2


2016 ITPNT 2 0 1 6 I n t e g r a t e d T r a n s m i s s i o n P l a n n i n g

N e a r - T e r m S c o p e

AprilAugust194,2015Final

Engineering

1

RevisionHistory

Date or Version Number

Author Change Description Comments

11/18/2014 Staff Initial Draft

01/30/2015 Staff Model Series Change

03/10/2015 Staff Incorporate Stakeholder Feedback

03/18/2015 Staff Incorporate Stakeholder Feedback

03/25/2015 Staff TWG Approved

04/14/2015 Staff MOPC Approved

8/11/2015 Staff Incorporate Non-Competitive Cost Estimates Schedule Change

2

TableofContents

Revision History ...........................................................................................................................................1

Overview .......................................................................................................................................................3

Objective .......................................................................................................................................................4

Data inputs ....................................................................................................................................................5

A. Load .......................................................................................................................................5

B. Generation Resources ............................................................................................................5

C. Model Topology.....................................................................................................................5

D. Transmission Service .............................................................................................................6

E. Consolidated Balancing Authority .........................................................................................6

F. Demand Response ..................................................................................................................7

Analysis .........................................................................................................................................................8

A. Steady State Assessment ........................................................................................................8

B. Solution Development ...........................................................................................................8

C. NERC Reliability Standard TPL-001-4 .................................................................................8

D. Shunt Reactive Requirements Assessment ............................................................................8

E. Stability Analysis ...................................................................................................................8

F. Final Reliability Assessment..................................................................................................8

Seams .............................................................................................................................................................9

Study Process ................................................................................................................................................10

Schedule ........................................................................................................................................................11

Deliverables ..................................................................................................................................................12

Changes in Process and Assumptions ........................................................................................................13

3

Overview

This document presents the scope and schedule of work for the 2016 Integrated Transmission Planning (ITP) Near-Term Assessment. This document will be reviewed by the Transmission Working Group (TWG) beginning February 2015, with the expectation of approvals from the Market Operations and Policy Committee (MOPC) and the Board of Directors (BOD) in April 2016. The assessment begins in April 2015 and is a 12-month study scheduled to be finalized in April 2016.

4

Objective

The ITP process is an iterative three-year planning process performed in accordance with Attachment O of the SPP Open Access Transmission Tariff (SPP OATT) that includes 20-Year, 10-Year and Near Term Assessments (ITP20, ITP10 and ITPNT, respectively) designed to identify transmission solutions that address both near-term and long-term transmission needs. The ITP20 is conducted over the first half of the three-year cycle and the ITP10 is conducted over the second half of the three-year cycle. The ITPNT is an assessment that is performed annually in order to evaluate the reliability of the SPP transmission system in the near-term planning horizon, collaborate on the development of improvements with stakeholders, and assess system upgrades at all applicable voltage levels required in the near-term planning horizon to meet reliability criteria. The 2016 ITPNT’s primary focus is identifying solutions required to meet the reliability criteria defined in OATT Attachment O, Section III.6. The process includes coordination of transmission plans with the ITP20, ITP10, Aggregate Study, and Generator Interconnection processes. The 2016 ITPNT study will generate an effective near-term plan for the SPP Regional Transmission Organization (RTO) planning region by identifying solutions to potential violations for system intact (Basecase) and (N-1 contingency) conditions using the following principles:

Identifying potential reliability-based problems (NERC Reliability Standard TPL-001-4 P1 events respecting SPP and local criteria)

Utilizing Transmission Operating Guides (TOGs) Developing additional mitigation plans including transmission upgrades to meet the region’s

needs and maintain SPP and local reliability/planning standards The 2016 ITPNT study horizon will include modeling of the transmission system for five years (i.e., 2020). This five year look allows enough lead time requirements such that the Notification to Construct (NTC) issuance can be provided in time for project owners to complete their projects by the identified need date. In order to comply with FERC’s Order 1000, SPP developed the Transmission Owner Selection Process, as outlined in Attachment Y of the SPP Tariff. In accordance with Attachment O, Section III.8.b, SPP shall notify stakeholders of identified transmission needs and provide a transmission planning response window of thirty (30) days during which any stakeholder may propose a Detailed Project Proposal (DPP). SPP shall track each DPP and retain the information submitted pursuant to Attachment O, Section III.8.b(i). The SPP ITP process is open and transparent and allows for stakeholder input through the FERC Order 1000 and Order 890 processes. The Transmission Working Group (TWG) will have opportunities to review and vet components of the 2016 ITPNT process, which includes but is not limited to the following items: model development, reliability analysis, transmission plan development, seams impacts, and the 2016 ITPNT Report. In addition, SPP will present the ITPNT Project Plan at the SPP transmission planning summits as an opportunity for SPP stakeholders to provide feedback. SPP will also coordinate the study results with first-tier neighbors.

5

Datainputs

For the 2016 ITPNT, SPP will consider power flow models with individual load balancing areas, as well as models with a Consolidated Balancing Authority (CBA Scenario). SPP will analyze 2017 and 2020 models in the 2016 ITPNT for the following seasons: 2017 summer peak, 2017 winter peak, 2020 light load, 2020 summer peak, and 2020 winter peak. A total of 15 model scenarios will be analyzed as part of the 2016 ITPNT Assessment. The CBA model will include a wind dispatch with a bid cap based upon wind generation past performance max output. The modeling set is summarized in the table below.

Description Scenario 0 Scenario 5 CBA

Year 2 peak ITPNT 2017SP ITPNT 2017WP

ITPNT 2017SP ITPNT 2017WP


Year 5 peak ITPNT 2020SP ITPNT 2020WP



Year 5 off-peak ITPNT 2020L ITPNT 2020L ITPNT 2020L

A. Load

The load density and distribution for the steady state analysis will be provided through the Model Development Working Group (MDWG) model building process1. The load will represent each individual load balancing area’s peak conditions per season (i.e., non-coincident conditions for the SPP region). Resource obligations will be determined for the footprint taking into consideration what load is industrial (non-scalable) and residential, commercial and agricultural (scalable) type loads.

B. GenerationResources

Existing generating resources will be represented in the power flow models taking into account planned retirements. New generating resources included in the power flow models will be limited to resources with a FERC-filed Interconnection Agreement not on suspension or resources with an executed Service Agreement. Exceptions to these qualifications are addressed in the ITP Manual.

C. ModelTopology

The topology used to account for the transmission system, excluding generation, will be the current transmission system and the following transmission upgrades: SPP upgrades that have been approved for construction, SPP Transmission Owner's planned (zonal sponsored) upgrades, and first-tier entities' planned upgrades (first-tier entities listed below). The model development processes for SPP MDWG and SERC account for long-term transmission line outages of 6 months or longer as forecasted by each member transmission owner. 1 SPP MDWG Model Development Procedure Manual

6

First-tier entities include the following:

Associated Electric Cooperative, Inc. (AECI) Alliant Energy West (ALTW) Ameren Missouri (AMMO) CLECO Corporation (CLEC) Dairyland Power Cooperative (DPC) Entergy Arkansas (EAI) Entergy Electric System (EES) Great River Energy (GRE) Lafayette Utilities (LAFA) Louisiana Energy and Power Authority (LEPA) MidAmerican Energy (MEC) Montana-Dakota Utilities Co. (MDU) Otter Tail Power Company (OTP) Saskatchewan Power Co. (SPC) Xcel Energy North (XEL)

D. TransmissionService

To account for confirmed long-term transmission service SPP will develop scenario models representing individual load balancing areas. The first scenario (S0) is built similar to the MDWG models but removes any non-firm transmission service, removes generation without signed interconnection agreements, removes topology that is projected or unbudgeted and incorporates transactions provided by members. Wind generation is accredited according to SPP Criteria. The second scenario (S5) sets all wind generation to maximum firm service, then all reservations between companies are set to maximum firm service as much as load will allow on a pro rata basis.

E. ConsolidatedBalancingAuthority

In order to account for the impacts of the Integrated Marketplace on the SPP footprint, a Consolidated Balancing Authority (CBA) scenario model will be developed as part of the 2016 ITPNT Assessment. For each CBA scenario SPP will be modeled as a single Balancing Authority with interchange modeled across the SPP seams. The CBA scenario will utilize the SPP portion of the NERC Book of Flowgates updated with information from the 2016 Flowgate Assessment, 2016 ITPNT transmission topology and latest ITP10 economic generator data. The goal will be to attain a security-constrained unit commitment and economic dispatch (SCUC/SCED) for each year and season identified as part of the 2016 ITPNT Assessment. In an effort to capture future constraints that are not currently in the NERC Book of Flowgates due to seasonal topology changes and load growth, a constraint assessment will be completed to determine if any constraints should be added, removed, or modified before the SCUC/SCED are developed. The updated constraint list will be reviewed and approved by the TWG before being applied to the CBA scenario models.

Making use of the economic data from the latest ITP10, an economic DC tool will perform a security constrained economic dispatch on the SPP footprint to deliver the most economical power around the given constraints. An N-1 contingency analysis described in subsection A (Load) of the Analysis

7

section above will then be performed on each CBA power flow model. The Eastern Interconnect generation outside of SPP will remain unchanged.

F. DemandResponse

Demand response will be incorporated into the models through lower load and capacity forecasts, which is developed as described in subsection A (Load) above.

8

Analysis

A. SteadyStateAssessment

The steady state assessment will use the following models: 2017 summer peak and winter peak, 2020 light load, summer peak and winter peak using individual load balancing area's dispatch. SPP will also use Consolidated Balancing Authority models of these same seasons. An N-1 contingency analysis will be performed for the peak and off-peak cases for facilities 60 kV and above in SPP and facilities 100 kV and above in first-tier. The Integrated System (IS) will be included in the analysis as part of the SPP planning region. All facilities 60 kV and above in SPP and 100 kV and above in first-tier will be monitored for this analysis in consideration of 60 kV and above solutions to the potential violations identified. SPP will use engineering judgment to resolve “blown up” and non-converged cases. If these cases cannot be solved, the potential violations will be posted in the needs list specifying the result of the analysis (e.g., voltage collapse).

B. SolutionDevelopmentSPP will analyze a pool of possible solutions to perform needs assessment to develop the 2016 ITPNT plan. This pool of solutions will be comprised of DPPs submitted for the 2016 ITPNT, SPP upgrades approved for construction, local reliability planning studies by Transmission Owners (TOs), SPP-identified solutions, and any other solutions proposed by SPP stakeholders.

C. NERCReliabilityStandardTPL‐001‐4

SPP will identify potential violations using the NERC TPL-001-4 standard Table 1 planning events that do not allow for non-consequential load loss or curtailment of firm transmission service. These potential violations will be posted on a secure website for informational purposes only.

D. ShuntReactiveRequirementsAssessment

If any 300 kV and above upgrades are identified as solutions and presented in the 2016 ITPNT Project Plan, a line-end reactive requirements analysis will be performed for those solutions. This analysis will be performed on the 2020 light load models by opening each end of the new line to identify preliminary shunt reactive needs. The analysis will provide the amount of MVars needed to maintain both 1.05 p.u. and 1.1 p.u. voltage at both ends of the new line. After performing the light load analysis, the reactor will be studied under steady state summer peak conditions to determine if switched capability is needed. This analysis will provide an indicative amount of reactive needs before design level studies are completed. This analysis will be completed with the entire 2016 ITPNT Project Plan.

E. StabilityAnalysis

SPP will not perform stability analysis as part of the 2016 ITPNT Assessment.

F. FinalReliabilityAssessment

After all upgrades have been identified and incorporated into the power flow models, a steady state N-1 contingency analysis will be conducted to identify any new potential violations.

9

Seams

In the development of the 2016 ITPNT Project Plan, SPP will review expansion plans of neighboring utilities and RTOs and include first-tier parties’ planned projects in the 2016 ITPNT models. Based upon that review, Staff may take into account other external plans. The IS will be included as a member and the new first-tier areas are ALTW, DPC, GRE, MEC, MDU, OTP, SPC and XEL, as previously identified. The models used in the 2016 ITPNT incorporate the latest data from the neighboring utilities and RTOs through the Multiregional Modeling Working Group (MMWG) model development process. In addition to the MMWG model development process, SPP will coordinate with first-tier neighbors to receive any additional model updates to ensure SPP’s models are aligned with how first-tier neighbors plan their own systems. SPP will also coordinate the results of the steady state assessment with first-tier neighbors highlighting needs relevant to the seam with that neighbor. As a part of this coordination, SPP will also solicit first-tier neighbors to participate in the solutions development portion of the study by submitting potential projects to be considered. Cost-effectiveness testing will be performed for all potentially beneficial seams projects. This additional cost-effectiveness testing will identify what level of cost sharing would be needed for each seams project to make the seams project a more cost-effective solution than an SPP regionally-implemented solution. SPP will coordinate the potential impacts of the 2016 ITPNT with neighboring systems. This coordination is conducted in accordance with the relevant Joint Operating or Seams agreements. In the absence of such an agreement, SPP will contact the relevant entities to discuss the potential impacts on their systems.

10

StudyProcess

1. The resource additions and retirements, load profiles, and transmission service inclusion processes will be developed through stakeholder reviews.

2. The TWG/MDWG will oversee the development of the models that incorporate the assumptions developed in step #1 above, including review of data and results. A model review will be conducted by MDWG and TWG to verify the models before analysis starts.

3. An initial steady state analysis will be performed using applicable planning standards on power flow models that represent the applicable load profiles and generation dispatch per year and season. The assessment will be for the horizon years one (1) through five (5). Within SPP, all facilities 60 kV and above in the models will be monitored and within the first-tier for all facilities 100 kV and above will be monitored in this analysis as a means to determine 60 kV and above solutions in the SPP planning region.

a. With input from stakeholders, 60 kV and above solutions will be developed to mitigate potential violations. Solutions will be coordinated with the Aggregate (AG) and Generation Interconnection (GI) Study processes for the SPP planning region. Since TOGs are tools used to mitigate violations in the daily management of the transmission grid, TOGs may be used as alternatives to planned projects and are tested annually to determine effectiveness in mitigating violations. For purposes of this study, the 2016 ITPNT will identify all solutions where the use of TOGs is deemed not effective.

b. A check will be performed to determine if projects identified in the ITP10 assessments will eliminate or defer any projects identified in the 2016 ITPNT.

4. A final reliability assessment will be performed, repeating the steps above on the identified solutions to validate the solutions and check for new potential violations.

5. Short-term reliability projects will be separately identified and posted with an explanation of the reliability violations and system conditions for which there is a time-sensitive need. There will be a thirty day comment period as required in Section I.3.c of Attachment Y of the SPP Tariff.

11

Schedule

The study will begin in February 2015 with final results complete by April 2016. The estimated study timeline is as follows:

Item Approval By Start Date Completion Date

Scoping TWG November 2014 March 2015 Model Development (S0, S5 & CBA)* TWG March 2015 September 2015 Reliability Assessment TWG May 2015 September 2015 DPP Response Window TWG September 2015 October 2015 Solution Development TWG October 2015 November 2015 Draft Portfolio TWG December 2015 December 2015 Final Reliability Assessment TWG March 2016

Review report TWG February March

2016 March April 2016

Final report with recommended Project Plan

TWG February April

2016 March April 2016

MOPC/BOD April 2016 *Note: Model Development for the CBA Scenario includes TWG review of constraints to be used in the models

12

Deliverables

The results from the 2016 ITPNT study, which define a set of transmission upgrades needed to meet the near-term potential violations of the system, will be compiled into a report detailing the findings and recommendations of SPP Staff.

13

ChangesinProcessandAssumptions

In order to protect against changes in process and assumptions that could present a significant risk to the completion of the ITPNT, any such changes must be vetted. If TWG votes on any process steps or assumptions to be used in the study, those assumptions will be used for the 2016 ITPNT. Changes to process or assumptions recommended by stakeholders must be approved by the TWG. This process will allow for changes if they are deemed necessary and critical to the ITP, while also ensuring that changes, and the risks and benefits of those changes, will be fully vetted and discussed.

Non‐Transmission Solution Evaluation Proposal


6/19/2015

What Does The Tariff Say?

Attachment O Section III 8.d

In addition to recommended upgrades, the Transmission Provider will consider, on a comparable basis, any alternative proposals which could include, but would not be limited to, generation options, demand response programs, “smart grid” technologies, and energy efficiency programs. Solutions will be evaluated against each other based on a comparison of their relative effectiveness of performance and economics.

Process Goals

• Evaluate the use of a Non‐Transmission Solution (NTS) fairly/equally against transmission solutions– NTSs may not always be the best solution or vice versa

– Develop common process to evaluate non‐transmission solutions vs. transmission solutions Process may differ slightly between ITPNT and ITP10

evaluation

• Find the best solution for the identified study needs as well as future system needs

• Apply evaluation approach to ITP and TSS processes

Non‐Transmission Solution

• What is a NTS?– Opening a line

– Closing a line

– Generation dispatch (MW or MVAR)

– Operation of other existing equipment such as cap banks, transformers, or other equipment

– Future generation

– Demand‐side management

4

Transmission Operating Guides

• SPP will evaluate TOGs as NTSs if submitted through RMS during the DPP window

• SPP may develop and/or test additional TOGs not submitted through the DPP window

5

Submitting a NTS through Order 1000

• All NTSs submitted as DPPs

• DPP must include as applicable:– NTS Description

– System conditions for application

– Needs solved

– Detailed Operator Actions

– Expected life

– Exceptions

– Idev/Nomogram and PROMOD case

– Risk Assessment6

NERC Reliability Standard Activities Update – August 18, 2015 Ballot Pools: There was no activity in this category since the last report. Drafting Team Vacancies: There was no activity in this category since the last report. Webinars: There was no activity in this category since the last report. Workshops and Conferences: NERC 2015 Standards and Compliance Fall Workshop October 20‐22, 2015 | San Diego, California Notes: There was no activity in this category since the last report. Currently Posted for Comment:

Project Applicability Comment Period Ends SPP Review

Project 2007‐06.2 Phase 2 of System Protection Coordination

This will address the proposed efforts to retire Requirements R2, R5, and R6 in PRC‐001. The drafting team for PRC‐027‐1 will be addressing the implementation of R3

and R4 of PRC‐001 into PRC‐027.

PRC‐027‐TO,GO,DP, PRC‐001 BA,TOP, GOP

9/11/2015 TBD

Project 2007‐06. System Protection Coordination

Requirement R1 of PRC‐001 will be proposed to be moved to TOP‐009.

Coordinators, Transmission Operators, Generator Operators, and Balancing Authorities for use by their System

Operators in support of reliable system operations.

TOP‐009 BA,TOP, GOP

9/11/2015 TBD

Project 2010‐14.2.1 Phase 2 of Balancing Authority Reliability‐based Controls The Periodic Review Team (PRT) conducted an evaluation of BAL‐005 and BAL‐006. As a result, they have recommended the revision of BAL‐005 and BAL‐006 Standards. These revisions will also impact FAC‐001 as well.

BAL‐005 and BAL‐006, BA

FAC‐001, TO, GO, and

LSE

9/14/15 TBD

Project 2007‐17.4 PRC‐005 FERC Order No. 803 Directive

The project will be focusing on the modifications to PRC‐005‐6 as well as

working on the Implementation Plan for this standard.

TO, GO, DP 9/16/15 TBD

Project 2010‐04.1 MOD‐031 FERC Order No. 804 Directives This project will modify the language in Requirement R3 to clarify certain obligations to provide data to the Regional Entity and will also address the directive to consider the compliance obligations of an applicable entity upon receipt of a data request that seeks confidential information.

PA, PC, TP, BA, RP, LSE, and DP

9/18/15 TBD

Recent Activity (Comments already filed):

Project Applicability Comment Period Ends SPP Review

Physical Security (CIP‐014) Requirement R6 (Guidelines)

These guidelines has been developed to help give the industry guidance on what criteria should be used when entities are researching for Third Party Organizations to conduct their Third Party Assessment in reference to Requirement R6 in CIP‐014.

TO, TOP 8/10/2015 8/4/2015

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