Market Working Group Meeting No. 2 February 6

Market Working Group Meeting No. 2 February 6 - 7, 2018

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Southwest Power Pool MARKET WORKING GROUP MEETING

February 6th – 7th, 2018 Renaissance Tower, 41st Floor, AEP – Dallas, TX

• SUMMARY OF MOTIONS AND NEW ACTION ITEMS •

Motions Agenda Item 2a – Consent Agenda Motion: Michael Massery (AECC) motioned to approve the consent agenda. Jack Madden (ETEC/NTEC) provided the second. Motion carried unanimously. Agenda Item 4a – RR266 JOU Combined Single Resource Modeling post Settlement Share Allocation IA – With Settlement System Motion: Jim Flucke (KCPL) motioned to approve RR266 (JOU Combined Single Resource Modeling post Settlement Share) Option 1 (implementation with Settlement System) Impact Analysis with a High rank. Cliff Franklin (WR) provided the second. Motioned carried with five oppositions from Kevin Galke (CUS), Valerie Weigel (Basin), Rick Yanovich (OPPD), Shawn McBroom (OGE) and Richard Ross (AEP) and one abstention from Carrie Dixon (Xcel). Agenda Item 5 – RR273 Market Settlements RNU Rounding Motion: Kevin Galke (CUS) motioned to approve RR273 (Market Settlements RNU Rounding). Valerie Weigel (Basin) provided the second. Motion carried unanimously. Agenda Item 8 – NDVER to DVER Conversion Motion: Matt Moore (GSEC) motioned to approve RR272 (NDVER to DVER Conversion), Lee Anderson (LES) provided the second. The motion was tabled. Motion: John Varnell (Tenaska) motioned to table the motion to approve RR272 (NDVER to DVER Conversion), Cliff Franklin (WR) provided the second. Motion carried with three oppositions from Lee Anderson (LES), Richard Ross (AEP), and Matt Moore (GSEC) and three abstentions from Shawn McBroom (OGE), Shawn Geil (KEPCO), and Aaron Rome (Midwest). Motion: Matt More (GSEC) motioned to approve RR272 (NDVER to DVER Conversion) as amended via a Friendly Amendment by Carrie Dixon (Xcel). The Friendly Amendment did not receive any opposition from the group. Lee Anderson (LES) provided the second. Motion carried with seven oppositions from Shawn Geil (KEPCO), Cliff Franklin (WR), Ron Thompson (NPPD), John Varnell (Tenaska), Rick Yanovich (OPPD), Michael Massery (AECC) and Jim Flucke (KCPL) and one abstention from Kevin Galke (CUS). Agenda Item 10 – RR270 OCRTF Revisions to Operating Criteria Appendices Motion: Shawn McBroom (OGE) motioned to approve RR270 (OCRTF Revisions to Operating Criteria Appendices). Ron Thompson (NPPD) provided the second. Motion carried unanimously.


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Agenda Item 12 – RR252 OOME Enhancement IA Motion: Kevin Galke (CUS) motioned to approve the Impact Assessment for RR252 (OOME Enhancement IA) with a Medium rank. John Varnell (Tenaska) provided the second. Motioned carried unanimously.

Action Items Action Item: Staff will determine if a manual solution can be put in place to allow MPs the ability to utilize the Combined JOU logic proposed in RR266 while the systematic logic is developed, tested and implemented. Staff will target the April MWG meeting for further discussion.


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February 6th – 7th, 2018 Renaissance Tower, 41st Floor, AEP – Dallas, TX

• MINUTES •

Agenda Item 1 – Call to Order, Attendance, Agenda Review Richard Ross (AEP) called the meeting to order at 8:20 a.m., CPT. Richard reviewed the agenda with the group. See Attachment 1 – February MWG Agenda The following members were in attendance or represented by proxy. See Attachment 2 – MWG Attendance February 6 7 2018 • Richard Ross (Chair), AEP • Jim Flucke (Vice Chair), KCPL • Aaron Rome, MIDW • Carrie Dixon, Xcel • Cliff Franklin, WR • Jack Madden, ETEC/NTEC • John Varnell, Tenaska • Kevin Galke, CUS • Lee Anderson, LES • Matt Moore, GSEC • Michael Massery, AECC • Neal Daney, KMEA – Attachment 3 – February 6 7 MWG_Daney Proxy • Rick Yanovich, OPPD • Ron Thompson, NPPD • Shawn Geil, KEPCO • Shawn McBroom, OGE • Valerie Weigel, BEPC Agenda Item 2 – Consent Agenda Richard Ross introduced consent agenda items for approval. See Attachment 4 – MWG January 8 9 2018 Minutes Motion: Michael Massery (AECC) motioned to approve the consent agenda. Jack Madden (ETEC/NTEC) provided the second. Motion carried unanimously. Agenda Item 3 – Safety Touchpoint Michael Massery (AECC) presented precautions to implement to avoid contracting the influenza virus and to ease symptoms following onset. See Attachment 5 – Safety Touchpoint_Influenza


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Agenda Items 4, 4a, 4b, and 4c – RR266 JOU Combined Single Resource Modeling post Settlement Share Allocation IA John Luallen (SPP) presented three Impact Analyses for implementation timing and cost associated with RR266 (JOU Combined Single Resource Modeling post Settlement Share Allocation): Option 1 – Development, testing and implementation concurrent with the Settlement System Replacement Project, Option 2 – Development concurrent with the Settlement System Replacement Project, but testing and implementation after implementation of the new Settlement System, and Option 3 – Development, testing and implementation all occur after the new Settlement System Replacement Project. John proposed an alternative approach to address the settlements portion of the proposed design outlined in RR266, which would involve creating a new JOU adjustment charge type instead of altering the 40+ charges and credits that currently apply to JOU Resources. John explained this approach could be implemented with any of the three Impact Analyses timing options, but noted the cost could change. The group expressed interest and requested SPP provide an additional impact analysis to assess the cost if developed, tested and implemented with the Settlement System Replacement Project (Impact Analysis Option 1). Erin Cathey (SPP) stated SPP will target the April MWG meeting to provide a new Impact Analysis for the alternative settlements approach. Although a number of MWG stakeholders voiced concern with the cost associated with the design overall, the Option 1 Impact Analysis was approved with a High rank. Due to MWG direction to further assess the cost associated with alternative settlements approach, SPP will not begin work to further develop the market design for RR266 until the Impact Analysis for the alternative settlements approach is complete and has been reviewed by the MWG. Motion: Jim Flucke (KCPL) motioned to approve RR266 (JOU Combined Single Resource Modeling post Settlement Share) Option 1 Impact Analysis with a High rank. Cliff Franklin (WR) provided the second. Motioned carried with five oppositions from Kevin Galke (CUS), Valerie Weigel (Basin), Rick Yanovich (OPPD), Shawn McBroom (OGE) and Richard Ross (AEP) and one abstention from Carrie Dixon (Xcel). See Attachment 6 – RR266 Impact Analysis with Settlement System, Attachment 7 – RR266 Impact Analysis Hybrid, Attachment 8 – RR266 Impact Analysis after Settlement System, and Attachment 9 – RR266 Recommendation Report Action Item: Staff will determine if a manual solution can be put in place to allow MPs the ability to utilize the Combined JOU logic proposed in RR266 while the systematic logic is developed, tested and implemented. Staff will target the April MWG meeting for further discussion. Agenda Item 5 – RR273 Market Settlements RNU Rounding John Luallen (SPP) presented RR273 (Market Settlements RNU Rounding). Per SPP’s tariff, SPP must remain revenue neutral and as such must calculate charge/credit amounts at each Settlement Location for each Asset Owner for each hour on a daily basis. This can result in residual amounts remaining due to rounding, which puts SPP in a position of not being revenue neutral for a given Operating Day. The


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residual is summed on a yearly basis and uplifted to Asset Owners and Settlement Locations. This is performed manually through SPP’s Miscellaneous Adjustment. John explained the objective of the RR is to eliminate the manual processing of residual amounts through the Miscellaneous adjustment and instead automate the distribution of the residual amounts through the RNU process. John detailed six charge types to be incorporated into the RNU process. The group inquired of the magnitude of dollars involved, to which John stated it is minimal. Although some MWG stakeholders expressed interest in considering an alternative approach, such as allocating the residual amounts to the SPP Administration Charge, the RR was approved. SPP staff plans to research this suggested approach, and if determined feasible, will provide an alternative revision request to the MWG for consideration during the March MWG meeting. See Attachment 10 – RR273 Market Settlements RNU Rounding Motion: Kevin Galke (CUS) motioned to approve RR273 (Market Settlements RNU Rounding). Valerie Weigel (Basin) provided the second. Motion carried unanimously. Agenda Item 6 – 2016-2017 ARR Holders % Hedged Debbie James (SPP) explained incorrect 2016/2017 Congestion Hedging % by Asset Owner data was presented during the August 2017 MWG meeting (related to closed MWG action item 317). Staff discovered the error during later analysis noting that several ARR holders that received Day-Ahead Market congestion payments instead of charges should have been shown as having no exposure instead of a hedged %. Debbie noted that the SPP GFA Carve out ARR holders are included in the corrected data, showing 52 ARR holders rather than 51, and that GFA ARR holders over 100% are also included. In the correct data SPP shows 20 AOs with no exposure which is a large contrast the 6 AOs previously shown with no exposure. Graphs and charts exhibiting the incorrect and correct versions of the data presented are included in MWG materials. See Attachment 11 – 2016 ARR Holders Percent Hedged Correction Agenda Items 7, 7a, 7b, 7c, and 7d – ARR/TCR Process Discussion Richard Ross recommended next steps to move towards completion of MOPC action item 276 - ARR/TCR inability to hedge as expected. He suggested researching potential options to address the issue of TCRs with small impacts consuming a disproportionate share of the awards and crowding out the larger impacting requests, possibly by adjusting the ARR process to align with the Transmission study process such that requests having less than a 3% impact are not included. Stakeholders voiced the need to develop a solution that would reduce uplift. Richard also facilitated a discussion of ARR/TCR process training. The group provided suggestions for additional training. Several stakeholders expressed an interest in more detailed training overall, and would like to see this provided in a workshop forum, possibly in-person prior to a MOPC meeting. Specific training requested included a deeper dive to look into the ARR allocation model and TCR auction model, including examples of a small system impact and a percent change impact and training to help stakeholders better understand the TSR process starting with the study process. Staff will work to provide a schedule and plan to address the training requested at the March MWG meeting. See Attachment 12 – Recommended Congestion Hedging Related Training and Attachment 13 – MOPC AI 276 Detailed Progress Summary


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Agenda Item 8a – NDVER to DVER Conversion Analysis and 8b – RR272 NDVER to DVER Conversion Erin Cathey (SPP), Gary Cate (SPP), and Casey Cathey (SPP) facilitated a review and discussion of the Non-Dispatchable Variable Energy Resources (NDVER) to Dispatchable Variable Energy Resource (DVER) Conversion Analysis Report provided to the MWG. Erin highlighted details of the NDVER capacity existing in SPP’s market and explained the individual Resource analysis was based on analysis performed at the request of an MP on one of their specific Resources to eliminate confusion where some questioned why SPP chose the specific Resource. The group discussed the analysis in detail and requested additional analysis be performed to show the impact of converting other NDVERs. Gary and Casey discussed SPP’s reasoning in proposing the NDVER conversion and explained why the effort is important and beneficial to the SPP market, speaking specifically to market inefficiencies and Reliability concerns. Keith Collins (SPP MMU) voiced the SPP MMU’s desire to see this effort completed, stating the MMU believes converting NDVERs to DVERs will create an overall more efficient market. SPP staff reiterated that with RR272 (NDVER to DVER Conversion), an MP would be able to request a waiver from FERC exempting them from conversion. See Attachment 14 – NDVER to DVER Conversion Analysis and Attachment 15 – RR272 NDVER to DVER Conversion Motion: Matt Moore (GSEC) motioned to approve RR272 (NDVER to DVER Conversion), Lee Anderson (LES) provided the second. The motion was tabled. Motion: John Varnell (Tenaska) motioned to table the motion to approve RR272 (NDVER to DVER Conversion), Cliff Franklin (WR) provided the second. Motion carried with three oppositions from Lee Anderson (LES), Richard Ross (AEP), and Matt Moore (GSEC) and three abstentions from Shawn McBroom (OGE), Shawn Geil (KEPCO), and Aaron Rome (Midwest). Motion: Matt Moore (GSEC) motioned to approve RR272 (NDVER to DVER Conversion) as amended via a Friendly Amendment by Carrie Dixon (Xcel). The Friendly Amendment did not receive any opposition from the group. Lee Anderson (LES) provided the second. Motion carried with seven oppositions from Shawn Geil (KEPCO), Cliff Franklin (WR), Ron Thompson (NPPD), John Varnell (Tenaska), Rick Yanovich (OPPD), Michael Massery (AECC) and Jim Flucke (KCPL) and one abstention from Kevin Galke (CUS). Agenda Item 8c – RR272 NPPD Comments 020118 Ron Thompson (NPPD) summarized NPPD’s comments and answered questions from the group. Ron noted concern with the following: cost impacts to conversion not considered and compensated by the market, converting type I and II turbines may result in additional maintenance costs and increased risk with no chance of cost recovery from SPP, impact of non-firm Resources on congestion, and SPP proposing changes to market rules in general which potentially places added cost burden on the SPP member utilities. More detail is provided in the submitted comments posted with materials. See Attachment 16 – RR272 NPPD Comments 020118 Agenda Item 8d – RR272 Westar Comments 020218


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Cliff Franklin (Westar) summarized Westar’s comments to RR272 (NDVER to DVER Conversion) and answered questions from the group. Cliff noted Westar agrees with NPPD comments and added additional concerns. Cliff asked staff why an RR had not been pursued to address the price following concerns and asked several questions related to the NDVER Conversion Analysis report provided by SPP. Erin explained SPP did introduce the idea of establishing thresholds which would indicate price following and require reregistration as a DVER but the idea was not accepted by the MWG (late 2014). Erin and Gary answered Westar’s questions related to the NDVER to DVER Conversion Analysis report noting that the report was updated to address the questions and add clarity. Cliff highlighted Westar’s concerns with existing PPA contracts, stating RR272 forces NDVER conversion and abrogates NDVER contracts making RR272 unjust and unreasonable. Finally, Cliff notes the RR puts SPP’s market reputation at risk due to SPP providing the conditions for NDVERs at the beginning of the SPP Integrated Marketplace. See Attachment 17 – RR272 Westar Comments 020218 Agenda Items 8e – RR263 NDVER to DVER Conversion through Incentives and 8f – RR263 Westar Comments 020318 Cliff Franklin (Westar) summarized Westar’s comments to their RR263 (NDVER to DVER Conversion through Incentives) and answered questions from the group. Cliff explained Westar’s comments are intended to address MWG member and SPP staff comments that were discussed during the January MWG meeting. Cliff summarized the comments and grouped responses in four areas; curtailment payment obligation allocation, responsibility for upgrades to convert NDVERs, favorable treatment resulting from providing incentives, and value of incentives if PTC and rate exposure are not considered in formulating negative resource offers. Cliff highlighted language changes to correctly calculate payments to proposed NDVER-DCPL facilities for DA and RT asset energy. See Attachment 18 – RR263 NDVER to DVER Conversion through Incentives and Attachment 19 – RR263 Westar Comments 020318 Agenda Item 8g – RR274 NDVER to DVER Conversion through URD Chandler Brown (SEPC) summarized Sunflower’s RR274 (NDVER to DVER Conversion through URD) and answered questions from the group. Chandler explained the intent and benefits of the proposed design, stating NDVERs would be discouraged from chasing price by means of a penalty which mimics SPP existing URD logic. He explained the proposed design is just a starting point and additional work to fine-tune would be needed. See Attachment 20 – RR274 NDVER to DVER Conversion through URD Agenda Item 8h – RR274 NPPD Comments 013118 Ron Thompson (NPPD) summarized NPPD’s comments to RR274 (NDVER to DVER Conversion through Incentives) and answered questions from the group. See Attachment 21 – RR274 NPPD Comments 020118 Agenda Item 8i – RR274 Olympus Power Comments 013018 John Varnell (Tenaska) summarized Olympus Power’s comments to RR274 (NDVER to DVER Conversion through Incentives) and answered questions from the group. See Attachment 22 – RR274 Olympus Power Comments 013018


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Agenda Item 9 – Multi-Day Minimum Run Time Solution Debbie James provided an update on the status of the multi-day minimum run time solution. She refreshed the group on the options provided during the February MWG meeting: Option 1 – No MWP after 24 Hours, Option 2 – Binding Offer at Minimum Energy for the Minimum Run Time, and the OGE Option – MWP to be lesser of the Mitigated Offer or Energy Offer for the balance of the minimum run time after the first 24 hours. Keith Collins (SPP) noted the SPP MMU’s concern that the proposed option from OGE may, although closing one, create a new loophole. The new loophole may present an incentive for MPs to offer in order to be committed and receive MWPs associated with the mitigated offer in subsequent days. Keith proposed a modification to OGE’s option. He recommended that if the “as-committed” energy offer and/or “as-committed” no-load offer is less than the mitigated energy and/or no-load offers, the MP will not be eligible to receive a MWP after the first 24 hours of its resource’s minimum run time. OGE voiced support for this option and offered to work with SPP staff to develop a revision request. See Attachment 23 – Multi-Day Min. Run Time Gaming Issue_Options Agenda Item 10 – RR270 OCRTF Revisions to Operating Criteria Appendices Neil Robertson (SPP) presented RR270 (OCRTF Revisions to Operating Criteria Appendices). Neil explained this RR was initiated by the Operating Criteria Review Task Force (OCRTF) and creates a stand-alone document for outage coordination methodology. Neil walked through the language in the RR and answered questions. The group unanimously approved the Revision Request. See Attachment 24 – RR270 OCRTF Revisions to Operating Criteria Appendices Motion: Shawn McBroom (OGE) motioned to approve RR270 (OCRTF Revisions to Operating Criteria Appendices). Ron Thompson (NPPD) provided the second. Motion carried unanimously. Agenda Items 11 – Modeling Practice Update Drew McGilvray (SPP) provided an education session on future effective load ownership. See Attachment 25 – Modeling Update_Future Effective Load Ownership Agenda Item 12 –RR252 OOME Enhancement Impact Analysis Erin Cathey presented the Impact Analysis for RR252 (OOME Enhancement). She explained the cost estimate was determined based on development and implementation following completion of the Settlement System Replacement project. The RR252 Impact Analysis was unanimously approved with a ranking of Medium priority. See Attachment 26 – RR252 Impact Analysis and Attachment 27 – RR252 Recommendation Report Motion: Kevin Galke (CUS) motioned to approve the Impact Assessment for RR252 (OOME Enhancement IA) with a Medium rank. John Varnell (Tenaska) provided the second. Motioned carried unanimously.


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Agenda Items 13 and 13a – MDRA Historical Data Follow-Up Erin Cathey suggested the MWG defer the discussion to the April MWG meeting to allow stakeholders additional time to analyze the data provided. See Attachment 28 – RR196 Providing MDRA Forecasted Commitments Agenda Item 15 – Regulatory Report Patti Kelly (SPP) presented the regulatory report. She made note of the FERC open meeting on Thursday, February 15th, 2018. Erin Cathey provided an update on SPP’s filing for the 206 Order on Quick-Start Resources from FERC, stating SPP is getting close to a final draft. See Attachment 29 – Regulatory Report February 2018 Agenda Item 16 – Stakeholder Prioritization Terry Rhoades (SPP) provided a refresher on the SPP Stakeholder Prioritization Process. He walked through the different aspects of the process and answered questions. Terry requested stakeholders utilize the SPP RMS to submit additional questions or comments. See Attachment 30 – Stakeholder Prioritization 2018 Agenda Item 17a – MWTG Update Erin Cathey provided an update on the Mountain West Transmission Group (MWTG) revision request review schedule. She explained there are multiple RRs related to the MWTG effort that will be brought to the MWG in March. Debbie James stated the tentative goal is for all MWTG RRs to be complete and provided to the MOPC for review at the July 2018 MOPC meeting. Agenda Item 17b – Reference Bus/LMP Calculation Yasser Bahbaz (SPP) facilitated an education session on the Reference Bus/LMP Calculation design for Mountain West. Taking a step back, Yasser provided some foundational level education to explain the basics of what a reference bus is before explaining why SPP is proposing to use two reference buses for the regions and how SPP envisions the approach operating. Yasser provided examples to illustrate the two reference bus approach. More education on this topic and how SPP will manage the DC Ties will be provided in March prior to the group reviewing MWTG revision requests. See Attachment 31 – MWTG Reference Bus Agenda Item 18 – January MMU Marketplace Update Kevin Bates (SPP MMU) presented the MMU Marketplace Update and answered questions from the group. A stakeholder requested the MMU provide additional detail on Virtual participation. See Attachment 32 – 201801 MWG MMU Market Update Agenda Item 19 – Open Discussion/General Questions Richard Ross provided an opportunity for questions and discussion. Valerie Weigel (Basin) proposed the group plan a future MWG meeting in Denver, CO. Valerie noted Tri-State has offered to host the meeting in their facility at no charge for the meeting space. MWG stakeholders recommended the June/July/August timeframe to meet in Denver. Valerie will work with Erin to finalize logistics and provide an update during the March MWG meeting.


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Agenda Item 20 – Written Reports Richard Ross provided an opportunity for the group to discuss topics submitted as written reports. No discussion. See Attachment 33 – January MWG Meeting Effectiveness Survey and Attachment 34 – February 2018 RTO Update Agenda Item 21 – RRs Prev. Reviewed by MWG, Awaiting Further Staff/Stakeholder Development *See SPP.org Revision Requests page for Materials related to these RRs.

a. RR114 Add Energy Storage Rules to Marketplace b. RR260 Repair of RR127 c. RR264 Remove Combined JOU

Agenda Item 22 – Review of Motions, Action Items, and Future Meetings Motions and new actions taken during the meeting are summarized above. Future meetings are listed below. See Attachment 35 – February MWG Closure Pending AIs, Attachment 36 – MWG Action Items, and Attachment 37 – February MWG Summary of Motions Future Meetings and Actions MWG Meeting Monday, March 12th, 2018 (1:00 p.m. – 6:00 p.m., CPT) Tuesday, March 13th, 2018 (8:15 a.m. – 6:00 p.m., CPT) Wednesday, March 14th, 2018 (8:15 a.m. – 12:00 p.m., CPT) Location: AEP Office – Dallas, TX Room: 41st Floor MWG Meeting Monday, April 16th, 2018 (1:00 p.m. – 6:00 p.m., CPT) Tuesday, April 17th, 2018 (8:15 a.m. – 6:00 p.m., CPT) Wednesday, April 18th, 2018 (8:15 a.m. – 12:00 p.m., CPT) Location: AEP Office – Dallas, TX Room: 41st Floor Agenda Item 23 – Adjournment Richard Ross adjourned the meeting at 11:45 a.m., CPT. Respectfully Submitted, Thank you – Erin Cathey, MWG Staff Secretary

Market Working Group Meeting No. 2 February 6th -7th, 2018

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

MARKET WORKING GROUP MEETING February 6th – 7th, 2018 AEP Office – Dallas, TX

2/6/2018: 8:15 a.m. – 6:00 p.m. 2/7/2018: 8:15 a.m. – 12:00 p.m.

• A G E N D A •

February 6 Agenda

1. Call to Order, Attendance, Agenda Review (8:15 – 8:20) Richard Ross

2. Consent Agenda (Approval Items) (8:20 – 8:25) Richard Ross

a. MWG January 8th – 9th Minutes

3. Safety Touchpoint (8:25 – 9:00) Michael Massery

4. RR266 JOU Combined Single Resource Modeling post Settlement Share Allocation IA (Approval) (9:00 – 10:00) John Luallen

a. Option 1: With Settlement System

b. Option 2: Hybrid

c. Option 3: After Settlement System

5. RR273 Market Settlements RNU Rounding (Approval) (10:00 – 10:30) John Luallen

6. 2016-2017 ARR Holders % Hedged (Correction) (10:45 – 11:00) Debbie James

7. ARR/TCR Process Discussion (11:00 – 12:00) Richard Ross

a. Eliminating Impact of <3% Impacts from ARR Clearing

b. Changing Clearing Methodology to Match TSR Assessment

c. Requiring Counterflow Nominations

d. TCR Process Training Next Steps

8. NDVER to DVER Conversion (12:45 – 3:45)

a. SPP NDVER Conversion Analysis Erin Cathey/Gary Cate

b. RR272 NDVER to DVER Conversion (Approval) Erin Cathey

c. RR272 NPPD Comments 020118 Ron Thompson

d. RR272 Westar Comments 020218 Cliff Franklin




e. RR263 NDVER to DVER Conversion through Incentives (Approval) Cliff Franklin

f. RR263 Westar Comments 020318 (Approval) Cliff Franklin

g. RR274 NDVER to DVER Conversion through URD (Approval) Chandler Brown

h. RR274 NPPD Comments 013118 Ron Thompson

i. RR274 Olympus Power Comments 013018 John Varnell

9. Multi-Day Minimum Run Time Solution (4:00 – 4:30) Debbie James

10. RR270 OCRTF Revisions to Operating Criteria Appendices (Approval) (4:30 – 5:00) Neil Robertson

11. Modeling Practice Update (5:00 – 5:30) Drew McGilvray

12. RR252 OOME Enhancement IA (Approval) (5:30 – 5:40) Gary Cate

13. MDRA Historical Data Follow-Up (5:40 – 6:00) Erin Cathey/Shawn McBroom

a. RR196 Communicating MDRA Forecasted Commitments (Approval) Erin Cathey

February 7 Agenda

14. Call to Order, Attendance, Agenda Review (8:15 – 8:20) Richard Ross

15. Regulatory Report (8:20 – 8:30) Patti Kelly

16. Stakeholder Prioritization (8:30 – 9:00) Terry Rhoades

17. MWTG Education/Discussion (9:00 – 10:30)

a. MWTG Update David Kelley

b. Reference Bus/LMP Calculation Gary Cate

18. January MMU Marketplace Update (10:30 – 11:00) Jason Bulloch

19. Open Discussion/General Questions All

20. Written Reports

a. Monthly MWG Effectiveness Survey Erin Cathey

b. January RTO Marketplace Update Gary Cate

21. RRs Awaiting Further Staff/Stakeholder Development (Possible Action) *See SPP.org Revision Requests page for Materials related to these RRs




a. RR114 Add Energy Storage Rules to Marketplace

b. RR260 Repair of RR127

c. RR264 Remove Combined JOU

22. Review of Motions, Action Items, and Future Meetings Kristen Darden

23. Adjournment Richard Ross

X = In PersonP = By Phone* = By Proxy

Day 1 Day 2 Full Name Company E-mailX X Richard Ross (Chair) AEP [email protected] X Jim Flucke (V-Chair) KCPL [email protected] X Erin Cathey (Sec) SPP [email protected] P Aaron Rome Midwest Energy [email protected]

Aundrea Williams NextEra Energy Resources [email protected] X Carrie Dixon Xcel Energy [email protected] X Cliff Franklin Westar [email protected] X Jack Madden GDS Associates [email protected] X John Varnell Tenaska Power Services [email protected] X Kevin Galke City Utilities, Springfield [email protected] X Lee Anderson LES [email protected] P Matt Moore Golden Spread Electric Coop [email protected] X Michael Massery AECC [email protected]* * Neal Daney KMEA [email protected] P Rick Yanovich OPPD [email protected] X Ron Thompson NPPD [email protected] X Shawn Geil Kansas Electric Power Co-op [email protected] X Shawn McBroom OGE [email protected] X Valerie Weigel Basin Electric Power Co. [email protected] X Aaron Doll Empire District [email protected] Abram Harder Southwest Power Pool [email protected] P Adam Schieffer MEAN [email protected] Alex Baird Colorado Springs Utilities [email protected] P Bob Wittmeyer Longhorn Power [email protected] Brenda Fricano Southwest Power Pool [email protected] P Brian Rounds AESL [email protected] P Brooke McMillan Southwest Power Pool [email protected] P Calvin Daniels WFEC [email protected] Carrie Simpson Xcel Energy [email protected] Casey Cathey Southwest Power Pool [email protected] X Chandler Brown Sunflower Electric [email protected] X Charles Costello Adapt2 Solutions [email protected] X Chris Lyons Customized Energy Solutions [email protected] Chris Nolen Southwest Power Pool [email protected] X Chris Winburn Independence Power and Light [email protected] X Cindy Ireland AR PSC [email protected] X Clay Carr WFEC [email protected] Craig Rutledge AEP [email protected] Dan Walter Tri State [email protected]

Market Working Group2/6/18 - 2/7/18Attendance

P Dana Boyer Southwest Power Pool [email protected] X David Beard Municipal Energy Agency of Nebraska [email protected] David Bloom Exelon Corp [email protected] P David Daniels Southwest Power Pool [email protected] X Debbie James Southwest Power Pool [email protected] P Delphine Alm BEPC [email protected] Dendy Collier Southwest Power Pool [email protected] P Dory Batka BHE [email protected] P Doug Clark Southwest Power Pool [email protected] Drew McGilvray Southwest Power Pool [email protected]

P Ella Caillouette Northwestern [email protected] P Eric Alexander GRDA [email protected] Farrokh Rahimi OATI [email protected] X Gary Cate Southwest Power Pool [email protected] X Geoffrey Rush OCC [email protected] P Gunnar Shaffer Southwest Power Pool [email protected] P Hagen Boehmer Southwest Power Pool [email protected]

P Harvey Scribner Southwest Power Pool [email protected] Heather Starnes MJMEUC [email protected] X Jack Clark NextEra Energy Resources [email protected] James Fife Physical Systems Integration [email protected]

X James Fife Jr. Physical Systems Integration [email protected] James Lewis Noble Power [email protected] Jared Greenwalt Southwest Power Pool [email protected]

Jason Bulloch SPP MMU [email protected] P Jason Mazigian BEPC [email protected] Jeff Knottek City Utilities [email protected] P Jeremi Wofford City Utilities [email protected]

P Jerry Stone Southwest Power Pool [email protected] Jerry Tielke MRES [email protected] Jessica Kasparek LES [email protected]

X Jim Jacoby AEP [email protected] P Jill Jones MEAN [email protected] X Jim Gonzalez Southwest Power Pool [email protected] Jim Krajecki Customized Energy Solutions [email protected] Jodi Woods Southwest Power Pool [email protected] X Joe Holmes Colorado Springs Utilities [email protected] John Boshears City Utilities [email protected] X John Fernandes Invenergy [email protected] X John Krajewski Nebraska Power Review Board [email protected] X John Luallen Southwest Power Pool [email protected] P John Seck KMEA [email protected] John Stephens CUS [email protected] X John Tennyson SPRM [email protected]

P P Jordan Boehmer Southwest Power Pool [email protected] X Keith Collins SPP MMU [email protected]

P Kevin Bates SPP MMU [email protected] X Kristen Darden Southwest Power Pool [email protected]

P L.D. Larson Balch [email protected] P Lane Hume Southwest Power Pool [email protected] P Lane Sisung [email protected] P Leann Poteet Southwest Power Pool [email protected] Lisa Szot Enel Green Power North America [email protected] Lisa Frisk-Thompson WAPA [email protected] X Mandi Howell WFEC [email protected] X Marguerite Wagner ITC [email protected] P McCord Stowater HCPD [email protected] P Micha Bailey Southwest Power Pool [email protected]

P Michael Billinger MWE [email protected] Michael Daly Southwest Power Pool [email protected] P Michael Hodges Southwest Power Pool [email protected] P Michael McCann Southwest Power Pool [email protected] X Michelle Almazan BP Energy [email protected] X Natasha Brown OMPA [email protected] Natasha Henderson GSEC [email protected]

P Neil Robertson Southwest Power Pool [email protected] P Nick Parker SPP MMU [email protected] P Patti Kelly Southwest Power Pool [email protected] P Raj Padmanabhan TEA [email protected] P Raleigh Mohr Southwest Power Pool [email protected] P Rebecca Atkins MJMEUC [email protected] P Rich Owen OGE [email protected] P Ricky Finkbeiner Southwest Power Pool [email protected] P Robert Pick NPPD [email protected] Robert Safuto Customized Energy Solutions [email protected] P Robert Tallman OGE [email protected] X Roy True ACES [email protected]

P Russell Quattlebaum Southwest Power Pool [email protected] P P Ryan Kirk AEP [email protected] P Ryan Schoppe Southwest Power Pool [email protected] Sandy Wirkus WAPA [email protected] P Scott Hartz MEAN [email protected] Seth Cochran DC Energy [email protected] P Shawnee Claiborn-Pinto Public Utility Commission of Texas [email protected] P Sonya Hall Southwest Power Pool [email protected] Steve Davis Southwest Power Pool [email protected] Steve Drew NextEra [email protected] X Steve Gaw Wind Coalition [email protected]

X X Steve Hickey Enel Green Power North America [email protected] Terry Rhoades Southwest Power Pool [email protected] P Thomas Sandoz NextEra Energy Resources [email protected] P Thresa Allen Avangrid [email protected] P Tom Burns Southwest Power Pool [email protected] Tom SaittaP Tony Alexander Southwest Power Pool [email protected] X Ty Mitchell SPP [email protected] P Tyson Boatler GSEC [email protected] P Vince Vandaveer SPRM [email protected] X Walt Shumate Shumate and Associates [email protected] P Wayne Camp Utilicast [email protected]

X Wayne Penrod Sunflower Electric Power Corp [email protected] P Will Vestal SPP MMU [email protected]

X Yasser Bahbaz Southwest Power Pool [email protected] P Yohan Sutjandra TEA [email protected]

Market Working Group Meeting No. 1 January 8 – 9, 2018

Page 1 of 8


January 8th – 9th, 2018 Renaissance Tower, 41st Floor, AEP – Dallas, TX

• SUMMARY OF MOTIONS AND NEW ACTION ITEMS •

Motions Agenda Item 10a – RR252 OOME Enhancement SPP Comments Motion: Ron Thompson (NPPD) motioned to approve RR252 (OOME Enhancement) SPP Comments as modified by the MWG. Rick Yanovich (OPPD) provided the second. Motion passed unanimously. Agenda Item 11 – RR266 JOU Combined Single Resource Modeling post Settlement Share Allocation Impact Analysis Motion: Cliff Franklin (WR) motioned to approve RR266 (JOU Combined Single Resource Modeling post Settlement Share Allocation) Impact Analysis with a High rank. Jack Madden (ETEC and NTEC) provided the second. Motion withdrawn.

Action Items Action Item: SPP staff to develop an Impact Assessment for implementation of RR266 (JOU Combined Single Resource Modeling post Settlement Share Allocation) with the new Settlements system for MWG review during the February MWG meeting. Action Item: SPP staff will provide a more detailed scope for each MWG Market Initiative which will include; 1) time commitment to design, 2) cost and complexity to implement, and 3) benefits to the SPP Market for MWG review during the February MWG meeting.


Page 2 of 8

Southwest Power Pool

MARKET WORKING GROUP MEETING January 8th - 9th, 2018

Renaissance Tower, 41st Floor, AEP – Dallas, TX

• MINUTES •

Agenda Item 1 – Call to Order, Attendance, Agenda Review Jim Flucke (KCPL) called the meeting to order at 1:00 p.m. CPT. Jim reviewed the agenda with the group. See Attachment 1 – January MWG Agenda The following members were in attendance or represented by proxy. See Attachment 2 – MWG Attendance January 8th – 9th 2018 • Richard Ross (Chair), AEP – Attachment 3 – January 8 9 MWG_Ross Proxy • Jim Flucke (Vice Chair), KCPL • Aaron Rome, MIDW • Aundrea Williams, NextEra – Attachment 4 – January 8 9 MWG_Williams Proxy • Carrie Dixon, Xcel • Cliff Franklin, WR • Jack Madden, ETEC/NTEC • John Varnell, Tenaska • Kevin Galke, CUS • Lee Anderson, LES • Matt Moore, GSEC • Michael Massery, AECC • Neal Daney, KMEA • Rick Yanovich, OPPD • Ron Thompson, NPPD • Shawn Geil, KEPCO • Shawn McBroom, OGE • Valerie Weigel, BEPC – Attachment 5 – January 8 9 MWG_Weigel Proxy Agenda Item 2 – Consent Agenda Jim Flucke introduced consent agenda items. See Attachment 6 – MWG December 11 12 2017 Minutes Agenda Item 3 – Safety Touchpoint Matt Moore (GSEC) provided a presentation on distracted walking and the associated dangers. See Attachment 7 – Safety Touchpoint_Distracted Walking Agenda Item 4 – MDRA Historical Data Posting Update Erin Cathey (SPP) provided an update on SPP’s progress to post two years of historical Multi-Day Reliability Assessment (MDRA) data. She provided information on where to locate the newly posted data on the Marketplace Portal and explained the data will be updated daily. Shawn McBroom (OGE)


Page 3 of 8

will review the data and provide feedback during the February MWG meeting on the next steps for RR196 (Communicating MDRA Forecasted Commitments). See Attachment 8 – MDRA Update Agenda Item 5 – SPP Culture of Compliance Ben Bright (SPP) provided a brief education session focused on SPP’s Culture of Compliance, specifically highlighting the, “What Does the Tariff Say” (WDTTS) and the “Good Catch” programs. Ben explained SPP staff is encouraged to bring forward any potential issues identified in SPP’s governing documents and that stakeholders can expect to see Revision Requests brought forward from these efforts. See Attachment 9 – Culture of Compliance January 2018 Agenda Item 6a – MWTG Schedule Update David Kelley (SPP) provided an update on the MWTG schedule. David explained that the policies are being discussed and finalized at the Strategic Planning Committee (SPC) and stakeholders will not see draft governing document language for review until the policy direction is set by the SPC. David stated it could be as early as January BOD meeting, but it could also be later. David stated SPP staff is focusing on creating a foundation by providing education to the stakeholders at this time. Erin reminded the group that they will have input as policies progress, through the stakeholder process. Agenda Items 6b and 6c – Day-Ahead Market TCR Funding and ARR/LTCR/ILTCR Obligation John Luallen (SPP) provided high-level training on potential MWTG market design. John covered three cost allocation options; 1) Market-Wide, Regional, and Cross-Regional. Other topics included in John’s training were impacts to charge types, a comparison of the TCR hedge value and TCR hedge funding today versus tomorrow with MWTG. In the second portion of John’s training, he covered the ARR/LTCR/ILTCR obligation proposal. John Luallen (SPP), David Kelley and Gary Cate (SPP) facilitated discussion and answered questions. SPP staff will consider the discussion in future MWTG design development. Jim Flucke recommended this training be provided to the Settlements User Group as well. Details on each topic can be reviewed in the MWTG Settlement Training MWG presentation provided in MWG meeting materials. See Attachment 10 – MWTG Settlement Training MWG Agenda Item 6d – LTCR Counterflow Kevin Galke (CUS) discussed an option to change newly awarded LTCRs to a potential hold requirement, similar to MISO’s construct. Kevin presented the pros and cons of SPP’s existing one year LTCR product with rollover rights and posed several questions to the group before moving into a straw proposal. Kevin facilitated a quick discussion and answered questions. Details on this topic can be reviewed in the LTCR Counterflows presentation provided in the MWG meeting materials. See Attachment 11 – LTCR Counterflows MWG Agenda Item 8 – MOPC Update Jim Flucke provided an overview of the MWG MOPC agenda items. He encouraged the group to discuss agenda items with their MOPC representation prior to the MOPC meeting. See Attachment 12 – MWG MOPC Update


Page 4 of 8

Agenda Items 9, 9a, 9b, 9c, and 9d – NDVER to DVER Conversion Erin Cathey introduced SPP’s draft Revision Request to convert Non-Dispatchable Variable Energy Resources to Dispatchable Variable Energy Resources over a two year transition timeframe. Erin noted the RR would be posted to SPP.org on January 16, 2018 and comments may be officially submitted at that time. Erin, Gary Cate, and Jodi Woods (SPP) facilitated discussion with some individual MWG stakeholders regarding the following:

• Concern of impact to MWTG NDVERs • Desire to have an escalated timeframe for type 3 and 4 wind powered VERs of one year rather

than two years • Desire to include an exception for run-of-the-river hydro not to convert • Desire to include an exception for Type 1 and Type 2 wind powered VERs to have a three year

timeframe rather than the proposed two year timeframe • Desire to require VERs without 100% Firm PTP or NITS service to convert before those with

Firm PTP or NITS service Cliff Franklin (WR) presented details to support RR263 NDVER to DVER Conversion through Incentives. Cliff explained that WR’s approach is a voluntary approach that does not abrogate NDVER PPA contracts and provided examples to illustrate how his proposal would work in production. Cliff facilitated discussion regarding WR proposal and answered questions. Kevin Galke provided an overview of TEA’s comments to RR263 stating that although they appreciate the potential efficiency gains of having more assets dispatchable associated with RR263, they have serious equitability and technical implementation concerns that lead them to oppose the design. Kevin noted the proposal may put NDVER-DCPL at a significant and discriminatory advantage to other resource types in the footprint. Chandler Brown (SEPC) provided an overview of Sunflower’s comments to RR263 stating that Sunflower is supportive of the NDVER to DVER conversion, agrees with the need to respect existing contracts, and agrees that MPs should not be unduly harmed as a result of the conversion. However, Sunflower also stated RR263 may create discriminatory market practices and as such Sunflower does not support the proposal. The MWG will take action on the NDVER to DVER conversion during the February MWG meeting. See Attachment 13 – 2018 Jan 8_Incentive for NDVER Conversion_WR Presentation MWG, Attachment 14 – RR263 NDVER to DVER Conversion Through Incentives, Attachment 15 – RR263 SEPC Comments 010318, Attachment 16 – RR263 CUS Comments 010518, and Attachment 17 – DRAFT RR NDVER DVER Conversion Agenda Items 10, 10a, and 10b – RR252 OOME Enhancement Erin Cathey introduced RR252 (OOME Enhancement) and provided background on past and current status to set the focus for discussion. Erin reminded the group that the Revision Request (RR) had been pulled from Secondary Working Group review when AEP, the RR submitter, and SPP determined there were missing settlement components that were necessary to add. Erin explained the intent of the RR is to


Page 5 of 8

allow Resources operating under an OOME cap and/or floor to be economically dispatched up to and including the newly defined OOME limits. Raleigh Mohr (SPP) expanded on the need for the limits in RR252 SPP Comments. He also specifically noted the need for the distinction between the two types of Out-of-Merit Energy (OOME) presented in RR252. Raleigh walked through other minor clarifying modifications submitted in SPP’s comments. John Luallen (SPP) discussed the two new charge types necessary to implement RR252. After some discussion and modification to RR252 SPP Comments, the group approved unanimously. See Attachment 18 – RR252 SPP Comments 010418, Attachment 19 – RR252 NPPD Comments 112717, Attachment 20 – RR252 MWG Comments 111417, Attachment 21 – RR252 Recommendation Report, and Attachment 22 – RR252 MWG Comments 010818 Motion: Ron Thompson (NPPD) motioned to approve RR252 (OOME Enhancement) SPP Comments as modified by the MWG. Rick Yanovich (OPPD) provided the second. Motion passed unanimously. Agenda Item 11 –RR266 JOU Combined Single Resource Modeling post Settlement Share Allocation Impact Analysis Erin Cathey presented the Impact Analysis for RR266 (JOU Combined Single Resource Modeling post Settlement Share Allocation). Erin explained the cost and duration are estimated based on implementation following the completion of the new settlement system replacement project, which is currently set to be in production during the second quarter of 2019. After discussion, the group requested an additional Impact Analysis for RR266 be performed with the cost and duration estimates based on an implementation that would occur with the new settlement system, rather than after. The group will review both options to determine their desired path. SPP staff will provide the requested information during the February MWG Meeting. See Attachment 23 – RR266 Impact Analysis, Attachment 24 – Severities Levels, Attachment 25 – RR266 Recommendation Report, Attachment 26 – RR260 Repair of RR127, Attachment 27 – RR264 Remove Combined JOU, and Attachment 28 – RR264 AEP Comments 120817 Motion: Cliff Franklin (WR) motioned to approve RR266 (JOU Combined Single Resource Modeling post Settlement Share Allocation) Impact Analysis with a High rank. Jack Madden (ETEC and NTEC) provided the second. Motion withdrawn. Action Item: SPP staff to develop an Impact Assessment for implementation of RR266 (JOU Combined Single Resource Modeling post Settlement Share Allocation) with the new Settlements system for MWG review during the February MWG meeting. Agenda Items 12, 12a, 12b, and 12c – ARR/TCR Process Discussion Deferred to the February 6th-7th MWG meeting. Agenda Item 13 – SPP Market Design Initiative Ranking Erin Cathey summarized the results of the MWG Members’ SPP Market Design Initiative priority ranking. Erin noted that overall the members’ top three priorities are: 1) Multi-Day Unit Commitment, 2) De-Commitment, and 3) Ramp Product. Gary Cate spoke to SPP’s priority ranking and why certain initiatives would be prioritized over, or in conjunction with, others. Gary stated Ramp Product is at the


Page 6 of 8

top of SPP’s list. Nick Parker (SPP MMU) and Keith Collins (SPP MMU) noted support of prioritizing the development of a Ramp Product design. The group requested SPP staff provide, for each initiative, the time commitment to design, the cost and complexity to implement, and the benefits to the market. Erin stated this additional data would be provided during the February MWG meeting. See Attachment 29 – Market Design Initiative Ranking 10-4 Action Item: SPP staff will provide a more detailed scope for each MWG Market Design Initiative which will include; 1) time commitment to design, 2) cost and complexity to implement, and 3) benefits to the SPP Market for MWG review during the February MWG meeting. Agenda Item 14 – FERC Fast-Start Direction & Next Steps Erin Cathey introduced the FERC Fast-Start 206 Investigation, Docket No. EL18-35-000, issued December 21st, 2017. Chris Nolen (SPP) explained the process of a 206 investigation and how it differs from a FERC 205 filing. Chris explained that based on the 206 investigation, FERC has made a preliminary finding that SPP’s Quick Start Resource (QSR) practices may be unjust and unreasonable. Chris informed the group that SPP staff will provide an initial brief to FERC by February 12th, 2018. Gary Cate walked through each of the areas identified by FERC as possibly being unjust and unreasonable, highlighting where the inflight QSR Revision Requests are applicable and where gaps exist. Erin explained how SPP may handle the approved QSR Revision Requests, stating each would be placed on hold until a FERC Order is received. Erin also informed the group that the scheduled stakeholder QSR training and member QSR testing has been cancelled. David Kelley informed members that they have an opportunity to intervene by January 11th. The group held significant discussion regarding the investigation and next steps. SPP’s next steps are to respond to FERC by February 12, 2018. Erin noted that SPP will share the draft response as soon as it is complete. See Attachment 30 – QSR Proposed Market Design, Attachment 31 – EL18-35-000 Fast-Start Order, and Attachment 32 – RR256 Recommendation Report Agenda Item 15 – Multi-Day Minimum Run Time Solution Debbie James (SPP) provided background and explained the purpose of her presentation. Debbie explained the presentation will focus on the two options of which MWG stakeholders requested more information during the November MWG meeting; Option 1 – No MWP after 24 Hours and Option 2 – Binding Offer at Minimum Energy for the Minimum Run Time. Debbie walked through each option in detail and facilitated discussion. Shawn McBroom (OGE) proposed an alternate option where the MWP after 24 hours would become the lesser of the Mitigated Offer or Energy Offer for the balance of the minimum run time. The group discussed and voiced support for OGE’s option. SPP staff will work with Shawn and provide an update during the February MWG. See Attachment 33 – Multi-Day Min. Run Time Gaming Issue_Options Agenda Item 17 – December MMU Marketplace Update Jason Bulloch (SPP) presented the MMU Marketplace Update and answered questions from the group. See Attachment 34 – 201712 MWG MMU Market Update Agenda Item 18 – Regulatory Report


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Patti Kelly (SPP) presented the Regulatory Report. Patti brought awareness to FERC’s withdrawal of their proceeding in the Department of Energy’s NOPR on Grid Resiliency Pricing. FERC issued a new order requesting information from RTOs/ISOs in relation to the resiliency of the bulk power system. David Kelley informed the group that the new order will be discussed at the upcoming Strategic Planning Committee (SPC) on January 18th, 2018. See Attachment 35 – Regulatory Report January 2018 Agenda Item 19 – Quarterly Review of all Existing Open Action Items Kristen Darden (SPP) reviewed all existing open action items with the group. See Attachment 36 – MWG Action Items Agenda Item 20 – Monthly MWG Effectiveness Survey Erin Cathey discussed the results from the December MWG meeting effectiveness survey. See Attachment 37 – December MWG Meeting Effectiveness Survey Agenda item 21 – MWG Cookbook Erin Cathey provided a preview of the MWG Cookbook. See Attachment 38 – 2017 MWG Cookbook Agenda Item 22 – Stakeholder Prioritization Deferred to the February 6th-7th MWG meeting. Agenda Item 23 – Open Discussion/General Questions Jim Flucke provided an opportunity for open discussion and general Q&A. Agenda Item 24 – Written Reports Jim Flucke provided an opportunity for the group to discuss topics submitted as written reports. See Attachment 39 – January 2018 RTO Update, Attachment 40 – Instantaneous Load Capacity Jan 2018, Attachment 41 – GFA Quarterly Report_20180108 MWG, Attachment 42 – Congestion Hedging 2016_2017_Q2_MWG, and Attachment 43 – RR System Impacting Est. Cost Qtrly Report Agenda Item 25 – RRs Prev. Reviewed by MWG, Awaiting Further Staff/Stakeholder Development *See SPP.org Revision Requests page for Materials related to these RRs.

a. RR114 Add Energy Storage Rules to Marketplace b. RR196 Communicating MDRA Forecasted Commitments c. RR260 Repair of RR127 d. RR264 Remove Combined JOU

Agenda Item 26 – Review of Motions, Action Items, and Future Meetings Motions and new actions taken during the meeting are summarized above. Future meetings are listed below. See Attachment 44 – January MWG Summary of Motions Future Meetings and Actions MWG Meeting CANCELLED Monday, February 5th, 2018 (1:00 p.m. – 6:00 p.m., CPT) Tuesday, February 6th, 2018 (8:15 a.m. – 6:00 p.m., CPT)


Page 8 of 8

Wednesday, February 7th, 2018 (8:15 a.m. – 12:00 p.m., CPT) Location: AEP Office – Dallas, TX Room: 41st Floor Topics:

• Multi-Day Unit Commitment Market Design • MDRA Historical Data Follow-up • NDVER/DVER Conversion • RR266 (JOU Combined Single Resource Modeling post Settlement Share Allocation) Impact

Assessment • TCR/ARR Discussion • RR RNU Rounding • Mountain West Market Design

MWG Meeting Monday, March 12th, 2018 (1:00 p.m. – 6:00 p.m., CPT) Tuesday, March 13th, 2018 (8:15 a.m. – 6:00 p.m., CPT) Wednesday, March 14th, 2018 (8:15 a.m. – 12:00 p.m., CPT) Location: AEP Office – Dallas, TX Room: 41st Floor MWG Meeting Monday, April 16th, 2018 (1:00 p.m. – 6:00 p.m., CPT) Tuesday, April 17th, 2018 (8:15 a.m. – 6:00 p.m., CPT) Wednesday, April 18th, 2018 (8:15 a.m. – 12:00 p.m., CPT) Location: AEP Office – Dallas, TX Room: 41st Floor Agenda Item 27 – Adjournment Jim Flucke adjourned the meeting at 5:10 p.m. CPT. Respectfully Submitted, Thank you – Erin Cathey, MWG Staff Secretary

Market Working Group Safety Touch Point

Influenza

Key Facts About Flu

• Flu season peaks between December and February• Flu season in the U.S. often follows flu season in Asia• Each year in the U.S. 25 – 50 million infections are reported• More than 200,000 are hospitalized• Approximately 23,600 die due to seasonal flu

People at High Risk from Flu

• 65 years and older• People diagnosed with asthma, diabetes or heart disease• Pregnant women• Young children

•Content source: Centers for Disease Control and Prevention, National Center for Immunization and Respiratory Diseases (NCIRD)

http://www.cdc.gov/

http://www.cdc.gov/ncird/index.html

Signs and Symptoms of Flu• Fever or feeling feverish/chills• Cough• Sore Throat• Runny or stuffy nose• Muscle or body aches• Headaches• Fatigue• Vomiting and diarrhea (more common in children)


http://www.cdc.gov/


How the Flu Spreads• Droplets from others up to 6 feet away

– Coughing– Sneezing– Talking

• Periods of Contagiousness– Adults

• 1 day before symptoms develop and up to 5 or 7 days after

– Children• Longer than 7 days


http://www.cdc.gov/


Prevention

• Get Flu Vaccine• Avoid close contact with sick people• Covering coughs• Frequent handwashing• Avoid sharing utensils• Drink water• Disinfect common surfaces


http://www.cdc.gov/


1

Revision Request Impact Analysis Report

RR #: 266 Date: 1/26/2018

RR Title: JOU Combined Single Resource Modeling post Settlement Share Allocation

Estimated Cost: $389,290 ROM based on information available at the time of the estimate

Estimated Duration: 6 – 8 Months ROM based on information available at the time of the estimate

Primary Working Group Score/Priority: High

SUMMARY OF SYSTEM IMPACTS This RR will impact the following systems: POPS, Markets, and Market Settlements. The changes needed will be reflected in changes to database schemas and system logic. Approximately 50% of the Market Settlements Charge Types may be affected depending upon the design for the changes. There may also be additional charge types required for this RR. Training materials will need to be created once the system design changes are complete. NOTE: This analysis assumes the development will occur with the Settlement Replacement project and that implementation will occur with the new settlement system. See risks noted below in the “SPP Comments” section.

IMPACTED SYSTEMS

Member Impacting

(Y/N)

List all impacted systems.

Provide a brief explanation of the expected impact to each.

1. Y

2. N

3. Y

4. Y

1. Training

2. POPS

3. Markets

4. Market Settlements

1. Course material edits and Job Aid creation

2. Database changes (New Charge Types and changes to existing Charge Types)

3. System changes

4. System (Calculations) and Database changes (New Charge Types and changes to existing Charge Types)

SPP STAFFING IMPACTS

N/A

EVALUATION OF INTERIM SOLUTIONS(i.e., manual workarounds)

N/A

ALTERNATIVE SOLUTION(S) FOR IMPLEMENTATION (i.e., other system implementation options)

N/A

OBJECTIVE OF REVISION REQUEST (as stated in Revision Request Form)

2

The goal of this RR is to address the gaming opportunity and market inefficiencies that currently exist with the JOU market design. The overall intent of this option is to treat the combined JOU as one Resource in the Market clearing decisions by modeling as a single Resource in EMS, AGC and reliability models while performing a percent ownership share allocation split of revenues after the fact. A Designated Asset Owner will submit all JOU data as a single Resource. However, other JOU shares will remain and will be used for settlement purposes; each JOU share will exist only in the context of settlements where final results of clearing are split based on the submitted ownership share percentages to the JOU shares.

Benefits that will be realized from this revision: • Eliminates gaming issues stemming from JOU modeling/logic • Streamlines SPP EMS, ICCP and Market Models • Reduces complexity in both the clearing engine and CR deployment • Removes voltage/VAR issues Maintains ability for the participant to have revenues/charges split out to each share

SPP COMMENTS

SPP recommends a ranking of high. The following are the risks to the Settlement Replacement project if the JOU revision is implemented at the same time: The Settlement Replacement project schedule is very aggressive: Scope –

• Replace and consolidate Market and Transmission billing systems into a single consolidated system • Implementation of non-Protocol impacting enhancements requested by the SUG • Migrate all historic data into new format for replacement system

Testing – • Ensure all results are complete and accurate to current effective Protocol and Tariff • Scenario test with members to validate connectivity and accuracy for pre-defined as well as member specific

scenarios • Parallel test with members in new production environment to validate accuracy and completeness

Risks of introducing member-impacting changes to replacement project:

• Increases scope of replacement project o Even with vendor developed code SPP resource will be diverted from the replacement project to work

with and validate vendor code • Increases magnitude of testing effort for SPP and members

o Scenario testing with JOU logic in effect in a member-facing environment will require members to test their updated shadow settlement systems

o Scenario testing with JOU logic in effect in a member-facing environment will require a coordinated effort across Markets and Settlements

o Parallel testing without JOU logic in effect in the new production environment will require members to test with their current shadow settlement systems

o Even with vendor supported member-facing testing of JOU logic, resource will be diverted from the replacement project to work with the vendor and sign-off on testing

• Implementation of settlement replacement project will require a coordinated effort across Markets and Settlements to implement the JOU logic

1


RR #: 266 Date: 1/26/2018



Estimated Duration: 6 – 8 Months ROM based on information available at the time of the estimate


SUMMARY OF SYSTEM IMPACTS This RR will impact the following systems: POPS, Markets, and Market Settlements. The changes needed will be reflected in changes to database schemas and system logic. Approximately 50% of the Market Settlements Charge Types may be affected depending upon the design for the changes. There may also be additional charge types required for this RR. Training materials will need to be created once the system design changes are complete. NOTE: This analysis assumes the development will occur concurrently with the development of the Settlement Replacement project, but will not be implemented with the new Settlement System, it would be implemented immediately following. All testing would occur after the new Settlement System replacement.

IMPACTED SYSTEMS

Member Impacting

(Y/N)



1. Y

2. N

3. Y

4. Y

1. Training

2. POPS

3. Markets

4. Market Settlements



3. System changes



N/A


N/A


N/A


2



The following are the risks to the Settlement Replacement project if the JOU revision is developed with the Settlement system:

• Staff would have to oversee and manage development work with the vendor and could jeopardize the Settlement Replacement project timeline.

SPP COMMENTS

SPP recommends a ranking of high.

of 2


RR #: 266 Date: 1/5/18



Estimated Duration: 6 - 8 Months ROM based on information available at the time of the estimate


SUMMARY OF SYSTEM IMPACTS This RR will impact the following systems: POPS, Markets, and Market Settlements. The changes needed will be reflected in changes to database schemas and system logic. Approximately 50% of the Market Settlements Charge Types may be affected depending upon the design for the changes. There may also be additional charge types required for this RR. Training materials will need to be created once the system design changes are complete. NOTE: This analysis assumes development and implementation will not occur until after the implementation of the Settlement Replacement project.

IMPACTED SYSTEMS

Member Impacting

(Y/N)



1. Y

2. N

3. Y

4. Y

1. Training

2. POPS

3. Markets

4. Markets Settlements



3. System changes



N/A


N/A


N/A


of 2



SPP COMMENTS

SPP recommends a ranking of high.

1

Revision Request Recommendation Report

RR #: 266 Date: 12/12/2017


SUBMITTER INFORMATION

Submitter Name: Gary Cate Company: Southwest Power Pool

Email: [email protected] Phone: 501.614.3200

EXECUTIVE SUMMARY AND RECOMMENDATION FOR MOPC AND BOD ACTION

OBJECTIVE OF REVISION

Background:

SPP introduced Joint Operating Unit (JOU) Resource market design in its Integrated Marketplace Filing (ER12-1179), stating MPs with JOUs may register each ownership share as a separate Resource and then allow the Resource to be offered in the markets and committed and dispatched as separate, individual Resources or committed as a combined Resource and dispatched as individual Resources.

On March 30, 2015, the MMU noted to Market Design an unintended consequence of the JOU Resource design – the “free rider” issue. Two unintended consequences were noted regarding the “combined option” of the JOU design: 1) Free Riders – a Resource that would not have been committed “but for” being part of a JOU. The unit may have an economic minimum output that results in an energy make-whole payment, and 2) Economic inefficiency in the make-whole payment for the start-up and no-load costs when not all parts of the JOU are receiving a make-whole payment. The Market Working Group and SPP staff reviewed nine total potential solutions before moving forward with RR127 (JOU Combined Option - Aggregate Energy Offer Curve) and RR205 Correction to RR127 for Regulation Limit Requirements).

RR127 and RR205 resulted in additional market inefficiencies and more complex gaming opportunities than existed with the original combined JOU Resource market design, so the MWG again began work to determine how best to address the issues with the combined JOU Resource market design.

During the October 2017 MWG meeting, the group reviewed eight total potential solutions. Of the eight solutions, SPP recommended the Market Working Group further pursue discussion and analysis of three viable options; Fully remove the JOU Resource market design (RR248 OGE Submission), Remove only the combined JOU Resource market design (RR248 AEP Comments), and a Single Resource Modeling with Post Market Revenue Allocations to Each Share option (SPP). The MWG rejected the option to remove all JOU Resources design from the SPP market, which rejected all associated comments. A motion was made to direct staff to revert back to pre-RR127 JOU market design, but this motion was postponed to December.

Objectives of Revision Request:


Benefits that will be realized from this revision: • Eliminates gaming issues stemming from JOU modeling/logic • Streamlines SPP EMS, ICCP and Market Models • Reduces complexity in both the clearing engine and CR deployment • Removes voltage/VAR issues • Maintains ability for the participant to have revenues/charges split out to each share

2

SPP STAFF ASSESSMENT

IMPACT

Will the revision result in system changes No Yes

Summarize changes:

Will the revision result in process changes? No Yes

Summarize changes:

Is an Impact Assessment required? No Yes

Estimated Cost: $ Estimated Duration: months

Primary Working Group Score/Priority:

SPP DOCUMENTS IMPACTED

Market Protocols Protocol Section(s): Glossary, 4.2.2.1, 4.2.2.5.4, 6.1.6, 6.1.6.2 Protocol Version: 52a

Operating Criteria Criteria Section(s): Criteria Date: Planning Criteria Criteria Section(s): Criteria Date: Tariff Tariff Section(s): Attachment AE – Definitions J, 2.2, 4.1, 4.1.2.3 Business Practice Business Practice Number: Integrated Planning Model (ITP Manual) Section(s): Revision Request Process Section(s): Minimum Transmission Design

Standards for Competitive Upgrades (MTDS) Section(s):

Reliability Coordinator and Balancing Authority Data Specifications (RDS) Section(s):

SPP Communications Protocols Section(s): WORKING GROUP REVIEWS AND RECOMMENDATIONS

List Primary and any Secondary/Impacted WG Recommendations as appropriate

Primary Working Group: MWG

Date: 12/11/2017

Action Taken: Approved

Abstained: Tenaska, BEPC, OPPD, OGE, AEP, LES, AECC, Xcel

Date: 1/8/2018

Action Taken:

Abstained:

Opposed:

3

Reason for Abstention:

BEPC (Valerie Weigel) - I want to see the impact assessment on RR266 cost prior to approving. I want to be able to compare that amount to completely removing the combined JOU (RR 264). Tenaska (John Varnell) - I abstained because RR266 did not fix anything for those wanting to self commit.

AEP (Richard Ross) - My abstention on the JOU RR was due to concern over the cost of implementation, but the desire to see a full impact analysis of the approach. However, it is unclear why, if such an approach could be used by selected JOU owners, those owners can not utilize a combined registration option. The legal concerns over coordination that have been expressed would appear to be present in either scenario.

Secondary Working Group: ORWG

Date: TBD

Action Taken:

Abstained:

Opposed:

Reasons for Opposition:

Secondary Working Group: RTWG

Date: TBD

Action Taken:

Abstained:

Opposed:


Secondary Working Group: CWG

Date: TBD

Action Taken:

Abstained:

Opposed:


MOPC

Date: TBD

Action Taken:

Abstained:

Opposed:


4

BOD/Member Committee

Date: TBD

Action Taken:

Abstained:

Opposed:


COMMENTS

Comment Author: Kristen Darden on behalf of the MWG

Date Comments Submitted: 12/11/2017

Description of Comments: The MWG adjusted language in AE referring to the Meter Agent’s responsibilities for a JOU registered under the Combined Resource Option. This adjustment aligns the Tariff with the Protocols.

Status: MWG approved and language incorporated.

Comment Author:

Date Comments Submitted:

Description of Comments:

Status:

PROPOSED REVISION(S) TO SPP DOCUMENTS

Market Protocols Glossary

Jointly Owned ResourceUnit

A Resource that is owned by more than one Asset As defined in Attachment AE of the Tariff.

4.2.2.1 Resource Offer Parameters The following Resource Offer parameters must be submitted to constitute a valid offer for use in

either the DA Market or RTBM:

(1) Resource Name (as specified during Market Registration and cannot be changed as part of

Resource Offer submittal);

5

(2) Start-Up Offer ($/Start, Hot, Intermediate and Cold – Hourly Unit Commitment

Parameter)1;

(3) Mitigated Start-Up Offer ($/Start, Hot, Intermediate and Cold – Hourly Unit Commitment

Parameter) 1;

(4) No-Load Offer ($/Hour)1;

(5) Mitigated No-Load Offer ($/Hour) 1;

(6) Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, monotonically non-

decreasing $/MWh, increasing MW and slope or block option) 1;

(a) Block and slope pairs may not coexist. The Resource Offer in effect for any given

period of time must be comprised by all block or all slope price/quantity pairs.

. For a JOU under the Combined Resource Option, the block or slope option

must be selected by, or on behalf of, the designated Asset Owner. All other

JOU Share Resource owners of that JOU must use the option selected by

the designated Asset Owner. All other JOU Share Resource owners of that

JOU will be converted to the option selected by the designated Asset Owner

if submitted differently.

(c)(b) The price of all MWhs below the first pricing point MWh is equal to the

first pricing point price. The price by all MWhs above the last pricing point MWh

is equal to the last pricing point price.

(d)(c) Under the slope option, the set of price points that are submitted are used as

the beginning and ending values for calculating a linear slope for each set of

beginning and ending values. Therefore, each MW between the two price points

has a different price due to the interpolation of the submitted price points. Under

the block option, each MW between the two MW points is offered at the price of

1 For Market Participants that have registered a JOU under the Combined Resource Option (see Section 6.1.6.2), this value must be submitted by or on behalf of the designated Asset Owner and represents the value for the entire Physical JOU Resource. See Section 4.2.2.5.4).

6

the larger MW point. Exhibit 4-5 illustrates Energy Offer Curves developed from

submitted price/MWh pairs for both the slope and block options.

Exhibit 4-1: Energy Offer Curve Development

(7) Mitigated Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, monotonically

non-decreasing $/MWh, increasing MW and slope or block option);

(a) Block and slope pairs may not coexist. The Resource Offer in effect for any given

period of time must be comprised of all block or all slope price/quantity pairs.

( ) For a JOU under the Combined Resource Option, the block or slope option

must be selected by or on behalf of the designated Asset Owner. All other

JOU Share Resource owners of that JOU must use this selected option. All

other JOU Share Resource owners of that JOU will be converted to the

option selected by the designated Asset Owner if submitted differently.

(9)(8) Regulation-Up Offer ($/MW);

(10)(9) Mitigated Regulation-Up offer ($/MW);

(11)(10) Regulation-Up Mileage Offer ($/MW) – Note that if Regulation-Up Offer is less

than zero then Regulation-Up Mileage Offer must be equal to zero;

(12)(11) Mitigated Regulation-Up Mileage Offer ($/MW);

(13)(12) Regulation-Down Offer ($/MW);

MW $/MWh100 20.00200 40.00400 60.00500 80.00

Submitted Data

Slope Option

Block Option

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

0 100 200 300 400 500 600

$/M

Wh

MW

Energy Offer Curve

Slope Option

Block Option

7

(14)(13) Mitigated Regulation-Down Offer ($/MW);

(15)(14) Regulation-Down Mileage Offer ($/MW) - Note that if Regulation-Down Offer is

less than zero then Regulation-Down Mileage Offer must be equal to zero;

(16)(15) Mitigated Regulation-Down Mileage Offer ($/MW);

(17)(16) Spinning Reserve Offer ($/MW);

(18)(17) Mitigated Spinning Reserve Offer ($/MW);

(19)(18) Supplemental Reserve Offer ($/MW);

(20)(19) Mitigated Supplemental Reserve Offer ($/MW)

(21)(20) Sync-To-Min Time (hours:minutes – Daily Unit Commitment Parameter)1;

(22)(21) Min-To-Off Time (hours:minutes – Daily Unit Commitment Parameter)1;

(23)(22) Start-Up Time (hours:minutes, Hot, Intermediate, Cold – Hourly Unit Commitment

Parameter)1;

(24)(23) Hot to Intermediate Time (hours:minutes– Daily Unit Commitment Parameter)1;

(25)(24) Hot to Cold Time (hours:minutes– Daily Unit Commitment Parameter)1;

(26)(25) Maximum Daily Starts (Daily Unit Commitment Parameter)1;

(27)(26) Maximum Weekly Starts – rolling 7-day (Daily Unit Commitment Parameter)1;

(28)(27) Maximum Daily Energy (MWh – Daily Unit Commitment Parameter)1;

(a) For enforcement of the Maximum Daily Energy constraint, cleared Regulation-Up

and cleared Contingency Reserve will decrement the Resource’s total Maximum

Daily Energy by 50% of the cleared product.

(b) For enforcement of the Maximum Daily Energy constraint, cleared Regulation-

Down will increment the Resource’s total Maximum Daily Energy allowed by 0%

of the cleared product.

(29)(28) Minimum Run Time (hours:minutes– Daily Unit Commitment Parameter)1;

(30)(29) Group Minimum Run Time (hours:minutes– Daily Unit Commitment Parameter) -

Only applicable to MCRs that have registered under the option described under Section

6.1.7.1;

(31)(30) Plant Minimum Run Time (hours:minutes– Daily Unit Commitment Parameter) -

Only applicable to MCRs that have registered under the option described under Section

6.1.7.1;

8

(32)(31) Maximum Run Time (hours:minutes– Daily Unit Commitment Parameter)1;

(33)(32) Minimum Down Time (hours:minutes– Daily Unit Commitment Parameter)1;

(34)(33) Minimum Emergency Capacity Operating Limit (MW);

(35)(34) Minimum Emergency Capacity Run Time (hours:minutes – Operations

Information);

(36)(35) Minimum Normal Capacity Operating Limit (MW);

(37)(36) Minimum Economic Capacity Operating Limit (MW);

(38)(37) Minimum Regulation Capacity Operating Limit (MW);

(39)(38) Maximum Regulation Capacity Operating Limit (MW);

(40)(39) Maximum Economic Capacity Operating Limit (MW);

(41)(40) Maximum Normal Capacity Operating Limit (MW);

(42)(41) Maximum Emergency Capacity Operating Limit (MW);

(43)(42) Maximum Emergency Capacity Run Time (hours:minutes – Operations

Information);

(44)(43) Maximum Quick-StartOff-line Supplemental Reserve Resource Response Limit

(MW, this represents the maximum amount of Supplemental Reserve that may be supplied

by an Ooff-line Quick-StartSupplemental Reserve Resource)1;

(45)(44) Ramp-Rate-Up (curve, MW/Minute - for use when the Resource is not selected for

Regulation-Up and/or Regulation-Down clearing and dispatched in the up direction).

Ramp-Rate-Up submittal is through a segmented profile as follows. Each profile will

require at least one (1) segment and may have up to n segments where n will be defined by

SPP, initially set to ten (10);

(a) Breakpoint Limit 1 – Resource MW output at which segment 1 Ramp-Rate-Up will

apply. In the RTBM, if the actual measured MW during deployment is less than

the Breakpoint Limit 1, the Ramp-Rate-Up in Block 1 will apply back to the actual

measured MW.

(b) Block 1 Ramp Rate Up – Rate at which Resource can change output upward in

MW/min at output levels greater than or equal to Breakpoint Limit 1.

Commented [RR1161]: RR116 Awaiting FERC and System Implementation


9

(c) Block 1 Ramp Rate Emergency – Rate at which Resource can change output

upward in MW/min at output levels greater than or equal to Breakpoint Limit 1

during an Emergency.

(d) Breakpoint Limit n – Resource MW output at which Ramp-Rate-Up changes from

previous segment values to segment n values.

(e) Block n Ramp-Rate-Up – Rate at which Resource can change output upward in

MW/min at output levels greater than or equal to the Breakpoint Limit n

(f) Block n Ramp-Rate-Up Emergency – Rate at which Resource can change output

upward in MW/min at output levels greater than the Breakpoint Limit n and less

than Breakpoint Limit n+1 during an Emergency.

(46)(45) Ramp-Rate-Down (curve, MW/Minute - for use when the Resource is not selected

for Regulation-Up Service and/or Regulation-Down Service clearing and dispatched in the

Down direction). Ramp-Rate-Down submittal is through a segmented profile as follows.

Each profile will require at least one (1) segment and may have up to n segments where n

will be defined by SPP, initially set to ten (10);

(a) Breakpoint Limit 1 – Resource MW output at which segment 1 Ramp-Rate-Down

will apply. In the RTBM, if the actual measured MW during deployment is less

than the Breakpoint Limit 1, the Ramp-Rate-Down in Block 1 will apply back to

the actual measured MW.

(b) Block 1 Ramp Rate Down – Rate at which Resource can change output downward

in MW/min at output levels greater than or equal to Breakpoint Limit 1.

(c) Block 1 Ramp-Rate-Down Emergency – Rate at which Resource can change output

downward in MW/min at output levels greater than or equal to Breakpoint Limit 1

during an Emergency.

(d) Breakpoint Limit n – Resource MW output at which Ramp-Rate-Down changes

from previous segment values to segment n values.

(e) Block n Ramp-Rate-Down – Rate at which Resource can change output downward

in MW/min at output levels greater than or equal to the Breakpoint Limit n.

10

(f) Block n Ramp-Rate-Down Emergency – Rate at which Resource can change output

downward in MW/min at output levels greater than the Breakpoint Limit n and less

than Breakpoint Limit n+1 during an Emergency

(47)(46) Turn-Around Ramp Rate Factor (a value between 0.01 and 1.00). A Resource’s

ramping direction in the next Dispatch Interval is compared against its ramping direction

in the current Dispatch Interval. If these two ramping directions are different, then the

Turn-Around Ramp Rate Factor is applied to the Dispatch Instruction in the next Dispatch

Interval, except in circumstances where the Resource is selected as available to be cleared

for Regulation or the Resource is being sent an OOME instruction.

The ramping direction in the current Dispatch Interval is based on the actual output at the

beginning of the current Dispatch Interval compared to the Dispatch Instruction at the end

of the current Dispatch Interval. The direction of the next Dispatch Interval is determined

by considering the actual output and ramp capability of the Resource at the time of the

solution and comparing it to the next Dispatch Instruction;

(48)(47) Regulation Ramp Rate (curve, MW/Minute - for use when the Resource is selected

for Regulation-Up Service and/or Regulation Down Service clearing). Regulation Ramp

Rate submittal is through a segmented profile as follows. Each profile will require at least

one (1) segment and may have up to n segments where n will be defined by SPP, initially

set to ten (10);

(a) Breakpoint Limit 1 – Resource MW output at which segment 1 Regulation Ramp

Rate will apply. In the RTBM, if the actual measured MW during deployment is

less than the Breakpoint Limit 1, the Regulation Ramp Rate in Block 1 will apply

back to the actual measured MW.

(b) Block 1 Regulation Ramp Rate – Rate at which a Resource on Automatic

Generation Control can change output in the up and down direction in MW/min at

output levels greater than or equal to Breakpoint Limit 1.

(c) Breakpoint Limit n – Resource MW output at which Regulation Ramp Rate

changes from previous segment values to segment n values.

11

(d) Block n Regulation Ramp Rate – Rate at which Resource on Automatic Generation

Control can change output in the up and down direction in MW/min at output levels

greater than or equal to the Breakpoint Limit n.

(49)(48) Contingency Reserve Ramp Rate (curve, MW/Minute). Contingency Reserve

Ramp Rate submittal is through a segmented profile as follows. Each profile will require

at least one (1) segment and may have up to n segments where n will be defined by SPP,

initially set to ten (10);

(a) Breakpoint Limit 1 – Resource MW output at which segment 1 Contingency

Reserve Ramp Rate will apply. In the RTBM, if the actual measured MW during

deployment is less than the Breakpoint Limit 1, the Contingency Reserve Ramp

Rate in Block 1 will apply back to the actual measured MW.

(b) Block 1 Contingency Reserve Ramp Rate – Rate at which a Resource not on

Automatic Generation Control can change output in the up direction in MW/min

when deploying Contingency Reserve at output levels greater than or equal to

Breakpoint Limit 1.

(c) Breakpoint Limit n – Resource MW output at which Contingency Reserve Ramp

Rate changes from previous segment values to segment n values.

(d) Block n Contingency Reserve Ramp Rate – Rate at which Resource not on

Automatic Generation Control can change output in the up direction in MW/min

when deploying Contingency Reserve at output levels greater than or equal to the

Breakpoint Limit n.

(50)(49) Resource Status (see Section 4.2.2.2);

(51)(50) Maximum Transition State Supplemental Reserve Resource Response Limit (MW,

this represents the maximum amount of Supplemental Reserve that may be supplied by

MCRs as a result of transitioning to a higher configuration) – Only applicable to MCRs

that have registered under the option described under Section 6.1.7.1;

(52)(51) Transition State Offer (Only applicable to MCRs that have registered under the

option described under Section 6.1.7.1);

12

(53)(52) Mitigated Transition State Offer (Only applicable to MCRs that have registered

under the option described under Section 6.1.7.1);

(54)(53) Transition State Time (Only applicable to MCRs that have registered under the

option described under Section 6.1.7.1); and

(55)(54) JOU Ownership Percent Share (Daily Unit Commitment Parameter)2;.

(56) JOU Minimum Physical Capacity Operating Limit3; and

(57) JOU Minimum Physical Regulation Capacity Operating Limit3.

4.2.2.5.4 Jointly Owned Unit Jointly Owned Unit (JOU) owners may elect to model their individual ownership shares as separate

Resources using either the Individual Resource Option or the Combined Resource Option as

specified during market registration as described under Section 6.1.6. Otherwise, the Resource is

modeled like any other single Resource with an associated single Asset Owner. Resource offers

may be submitted for each Asset Owner’s JOU ownership (“JOU Share Resource”) the same as

any other Resource subject to the following Resource Offer validation rules and exceptions.

(1) As part of market registration, the following offer parameters representing the ownership

and physical characteristics of the entire JOU (“Physical JOU Resource”) must be

submitted either by or on behalf of the Asset Owner identified at registration (“designated

Asset Owner”):

(a) JOU maximum physical capacity operating limit;

2 Only applicable for the designated Asset Owner identified by the Market Participant that has registered a JOU under the Combined Resource Option (see Section 4.2.2.5.4). A value for each Asset Owner must be submitted by or on behalf of the designated Asset Owner and represents each Asset Owners percentage share of the Physical JOU Resource and must add up to 100%. 3 For Market Participants that have registered a JOU under the Combined Resource Option (see Section 6.1.6.2), this value must be submitted by or on behalf of the designated Asset Owner and represents the value for the entire Physical JOU Resource. See Section 4.2.2.5.4).

13

(b) JOU Minimum Physical Capacity Operating Limit (Default value. May be updated

as part of the DA Market and RTBM offer. Only required if registered under

Combined Resource Option);

(c) JOU Minimum Physical Regulation Capacity Operating Limit (Default value. May

be updated as part of the DA Market and RTBM offer. Only required if registered

under Combined Resource Option);

(d)(b) JOU maximum physical 10-minute response from an off-line state (if a

Quick-Start Resource); and

(e)(c) JOU Ownership Percent Share by Asset Owner (Default value. May be updated as

part of DA Market and RTBM Offer. Only required if registered under Combined

Resource Option).

(2) The following Offer parameters as submitted by or on behalf of each Asset Owner for its

JOU Share Resource that have registered under the Individual Resource Option must meet

the following criteria in order to be accepted as valid offers, otherwise, all Offers related

to the Physical JOU Resource will revert to the last valid offer;

(a) The sum of the Maximum Emergency Capacity Operating Limits of each JOU

Share Resource associated with the Physical JOU Resource must be less than or

equal to the Physical JOU Resource maximum physical capacity operating limit.

(3) Commitment of individual JOU Share Resources that have registered under the Individual

Resource Option will be evaluated by SCUC based on the individually submitted Offers

for each JOU Share Resource;

(4) Commitment of a JOU Share Resources that have registered under the Combined Resource

option will be evaluated by SCUC based on a combination of the individually submitted

Resource Offers for each JOU Share Resource and the Offer parameters submitted by or

on behalf of the designated Asset Owner that apply to the entire Physical JOU Resource.

(see Section4.2.2.1 for footnoted parameters to be submitted by or on behalf of the

designated Asset Owner and Section 4.2.2.2 regarding Commitment Status) given the

additional constraint that if one of the JOU Resources is committed, all JOU Share

Resources associated with the Physical JOU Resource must be committed. This rule also

14

applies to clearing of Supplemental Reserve from an Off-line Quick-Start Supplemental

Reserve Resources. Each Asset Owner of a JOU Share Resource under the Combined

Resource Option must submit a zero for Minimum Emergency Capacity Operating Limit,

Minimum Normal Capacity Operating Limit, Minimum Regulation Capacity Operating

Limit, and Minimum Economic Capacity Operating Limit. The JOU Minimum Physical

Capacity Operating Limit, or Minimum Physical Regulation Capacity Operating Limit

while selected for Regulation, can be achieved by any combination of JOU Share

Resources(s) during the commitment period. The designated Asset Owner of that JOU

under the Combined Resource Option will designate for all shares either the slope or block

option when submitting the Energy Offer Curve. A JOU under the Combined Resource

Option will be dispatched using an aggregated Energy Offer Curve. This aggregated

Energy Offer Curve is made up of all price points from each JOU Share Resource’s Energy

Offer Curve associated with that JOU. When committed, each JOU Share Resource is

eligible for recovery of Start-Up Offer and No-Load Offer costs proportional to that Asset

Owner’s JOU Ownership Percent Share whether or not that JOU Share Resource was

dispatched greater than zero MWs as described under Section 4.5.8.12 and 4.5.9.8. Prior

to evaluation by SCUCFor Make Whole Payment calculation purposes, the Resource Offer

for each JOU Share Resource associated with the Physical JOU Resource is set equal to

the JOU’s Resource Offerassigned the following unit commitment parameters as submitted

by or on behalf of the designated Asset Owner.:

( ) The Start-Up Offer of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is calculated by multiplying the Start-Up Offer

submitted for the Physical JOU Resource by that Asset Owner’s JOU Ownership

Percent Share and this value will be used for Make Whole Payment calculation

purposes;

( ) The Mitigated Start-Up Offer of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is calculated by multiplying the

Mitigated Start-Up Offer submitted for the Physical JOU Resource by that Asset

Owner’s JOU Ownership Percent Share and this value will be used for Make

Whole Payment calculation purposes;

Commented [RR116.3]: Awaiting FERC

Commented [RR116.4]: Awaiting FERC

15

( ) The No-Load Offer of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is calculated by multiplying the No-Load Offer

submitted for the Physical JOU Resource by that Asset Owner’s JOU Ownership

Percent Share and this value will be used for Make Whole Payment calculation

purposes;

( ) The Mitigated No-Load Offer of each Asset Owner’s JOU Share Resource


Mitigated No-Load Offer submitted for the Physical JOU Resource by that Asset

Owner’s JOU Ownership Percent Share and this value will be used for Make

Whole Payment calculation purposes;

( ) The Sync-To-Min Time of each Asset Owner’s JOU Share Resource associated

with the Physical JOU Resource is set equal to the Sync-To-Min Time submitted

for the Physical JOU Resource;

( ) The Min-To-Off Time of each Asset Owner’s JOU Share Resource associated

with the Physical JOU Resource is set equal to the Min-To-Off Time submitted


( ) The Start-Up Time of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is set equal to the Start-Up Time submitted for the

Physical JOU Resource;

( ) The Hot to Intermediate Time of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is set equal to the Hot to Intermediate

Time submitted for the Physical JOU Resource;

( ) The Hot to Cold Time of each Asset Owner’s JOU Share Resource associated

with the Physical JOU Resource is set equal to the Hot to Cold Time submitted


( ) The Maximum Daily Starts of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is set equal to the Maximum Daily

Starts submitted for the Physical JOU Resource;

16

(o) The Maximum Weekly Starts of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is set equal to the Maximum Weekly

Starts submitted for the Physical JOU Resource;

(p) The Maximum Daily Energy of each Asset Owner’s JOU Share Resource


Maximum Daily Energy submitted for the Physical JOU Resource by that Asset

Owner’s JOU Ownership Percent Share;

(q) The Minimum Run Time of each Asset Owner’s JOU Share Resource associated

with the Physical JOU Resource is set equal to the Minimum Run Time submitted


(r) The Minimum Down Time of each Asset Owner’s JOU Share Resource associated

with the Physical JOU Resource is set equal to the Minimum Down Time

submitted for the Physical JOU Resource;

(s) The Maximum Run Time of each Asset Owner’s JOU Share Resource associated

with the Physical JOU Resource is set equal to the Maximum Run Time submitted


(t) The Maximum Quick-Start Off-line Supplemental Reserve Resource Response

Limit of each Asset Owner’s JOU Share Resource associated with the Physical

JOU Resource is calculated by multiplying the Maximum Quick-StartOff-line

Supplemental Reserve Resource Response Limit submitted for the Physical JOU

Resource by that Asset Owner’s JOU Ownership Percent Share; and

( ) The Commitment Status of each Asset Owner’s JOU Share Resource associated

with the Physical JOU Resource is set equal to the Commitment Status submitted

for the Physical JOU Resource.

(22)(5) If committed, each JOU Share Resource under the Individual Resource Option will

be considered separately for the purposes of dispatch, Operating Reserve clearing and

settlement and the Physical JOU Resource will receive an aggregate Setpoint Instruction

for the purposes of Energy and Operating Reserve deployment;



17

(a) If a JOU Share Resource is committed by SPP in the DA Market, that JOU Share

Resource is cleared for Energy based on the submitted Energy Offer Curve and

Ramp Rate and is cleared for Operating Reserve based on the submitted Operating

Reserve Offers and Ramp Rate;

(b) Each JOU Share Resource committed by SPP in the DA Market is eligible to

receive a DA Market Make Whole Payment under the same eligibility rules as any

other Resource as described under Section 4.5.8.12;

(c) In the RTBM, each JOU Share Resource is dispatched for Energy based on the

submitted Energy Offer Curve, Ramp-Rate-Up and Ramp-Rate-Down and is

cleared for Operating Reserve based on the submitted Operating Reserve Offers,

Ramp-Rate-Up and Ramp-Rate-Down. SPP sends to each Asset Owner it’s

independent Dispatch Instruction, Setpoint Instruction, and cleared amount(s) of

Operating Reserve for its individual JOU Share Resource.

SPP will also, for information purposes, send to the JOU Operating Owner each

Asset Owner’s independent Dispatch Instructions and the sum of these

independent Dispatch Instructions, and each Asset Owner’s independent Setpoint

Instructions and the sum of the Asset Owner’s independent Setpoint Instructions

The SPP provided Setpoint Instruction(s) for each JOU Share and the actual output

submitted for each JOU Asset Owner(s) as submitted by respective Meter Agent(s)

shall be used for monitoring according to (ii) below and for settlements.

(i) If a JOU Share Resource is committed by SPP in any RUC process, that

individual JOU Share Resource is eligible to receive a RUC Make Whole

Payment under the same eligibility rules as any other Resource as described

under Section 4.5.9.8.

(ii) Each JOU Share Resource will be subject to charges associated with

Uninstructed Resource Deviation that exceeds the JOU Share Resource

Operating Tolerance as described under Sections 4.5.9.8 and 4.5.9.10,

Regulation deployment failure charges as described under Section 4.5.9.15

18

and Contingency Reserve deployment failure charges as described under

Section 4.5.9.17, under the same eligibility rules as any other Resource.

(23)(6) If committed, each the Physical JOU Share Resource registered under the

Combined Resource Option will beis considered separatelytreated as a single Resource for

the purposes of dispatch, and Operating Reserve clearing and settlement. Resource Offer

and the Offer parameters under the Combined Resource Option are submitted by or on

behalf of the designated Asset Owner and apply to the entire Physical JOU Resource. The

total settlement is distributed to each JOU Asset Owner based on the Asset Owner’s JOU

Ownership Percent Share. andthe Physical JOU Resource will receive an aggregateTthe

total Setpoint Instruction of the Physical JOU Resource for the purposes of Energy and

Operating Reserve deployment will be communicated to each JOU Asset Owner;

(a) The Physical JOU Resource If a JOU Share Resource is committed by SPP in the

DA Market, that JOU Share Resource is cleared for Energy based on the

aggregated Energy Offer Curve as described in (4) above and the submitted Ramp

Rate, and is cleared for Operating Reserve based on the Operating Reserve Offers

and the submitted Ramp Rate;Each JOU Share Resource committed by SPP for a

MW amount greater than zero in the DA Market is eligible to receive a DA Market

make whole payment and be subject to charges under the same eligibility rules as

any other Resource as described under Sections 4.5.8 and 4.5.9, and each JOU

Share Resource will recover costs and will be responsible for charges proportional

to that Asset Owner’s JOU Ownership Percent Share;

(b) Each JOU Share Resource committed by SPP for a MW amount of zero in the DA

Market is eligible to recover Start-Up and No-Load costs proportional to that Asset

Owner’s JOU Ownership Percent Share as described under Section 4.5.8.12.

(c) In the RTBM, each JOU Share Resource is dispatched for Energy based on the

aggregated Energy Offer Curve as described in (4) above, the submitted Ramp-

Rate-Up and Ramp-Rate-Down and is cleared for Operating Reserve based on the

Operating Reserve Offers, the submitted Ramp-Rate-Up and Ramp-Rate-Down.

SPP sends to each Asset Owner it’s independent Dispatch Instruction, Setpoint

19

Instruction, and cleared amount(s) of Operating Reserve for its individual JOU

Share Resource.

SPP will also, for information purposes, send to the JOU Operating Owner each Asset

Owner’s independent Dispatch Instructions and the sum of these independent

Dispatch Instructions, and each Asset Owner’s independent Setpoint Instructions

and the sum of the Asset Owner’s independent Setpoint Instructions.

(e)(b) The SPP provided Setpoint Instruction(s) for each JOU Sharethe Physical JOU

Resource and the actual output as submitted by the Meter Agent for eachfor the

JOU designated Asset Owner(s) as submitted by respective Meter Agent(s) shall

be used for monitoring according to (iii) below and for settlements under the same

rules as any other Resource as described in section 4.5.9.

( ) If a JOU Share Resource is committed by SPP for a MW amount greater

than zero in any RUC process, that individual JOU Share Resource is

eligible to receive a RUC make whole payment under the same eligibility

rules as any other Resource as described under Section 4.5.9.8.

( ) Each JOU Share Resource is committed by SPP for a MW amount of zero

in any RUC process that individual JOU Share Resource is eligible to

recover Start-Up and No-Load costs proportional to that Asset Owner’s

JOU Ownership Percent Share as described under Section 4.5.9.8.

( ) Each JOU Share Resource will be subject to charges associated with

Uninstructed Resource Deviation that exceeds the JOU Share Resource

Operating Tolerance as described under Sections 4.5.9.8 and 4.5.9.10,

Regulation deployment failure charges as described under Section 4.5.9.15

and Contingency Reserve deployment failure charges as described under

Section 4.5.9.17, under the same eligibility rules as any other Resource.

(27)(7) The Meter Agent(s) assigned to the Physical JOU Resource registered under the

Individual Resource Option must account for all physical Energy produced and properly

reflect this Energy in each individual JOU Share Resource meter data submittal.

6.1.6 Jointly Owned ResourceUnit

20

In addition to the responsibilities described under Section 6.1.1, Market Participants wishing to model each ownership share as a separate Resource must choose one of the two options described below and provide the specified additional information. A Resource registered as a Combined Cycle Resource may not register as a JOU.

6.1.6.2 Combined Resource Option Under the Combined Resource Option, the JOU is modeled as one market Resourceeach

ownership share is modeled as a separate Resource for the dispatch purposes but commitment

related parameters are submitted representing the entire physical Resource. Under this option, the

commitment decision is made assuming that all Resource shares must be committed or none at

allfor the Physical JOU Resource. Each Asset Owner of a JOU Share Resource under the

Combined Resource Option must submit a zero for Minimum Emergency Capacity Operating

Limit, Minimum Normal Capacity Operating Limit, Minimum Regulation Capacity Operating

Limit, and Minimum Economic Capacity Operating Limit. The JOU Minimum Physical Capacity

Operating Limit, or Minimum Physical Regulation Capacity Operating Limit while selected for

Regulation, can be achieved by any combination of JOU Share Resource(s) during the

commitment period. The designated Asset Owner of that JOU under the Combined Resource

Option will designate for all shares either the slope or block option when submitting the Energy

Offer Curvesubmit the Resource Offer to be used for commitment, dispatch, and Operating

Reserve clearing. A JOU under the Combined Resource Option will be dispatched using an

aggregated Energy Offer Curve. This aggregated Energy Offer Curve is made up of all price points

from each JOU Share Resource’s Energy Offer Curve associated with that JOU. When committed

each JOU Share Resource is eligible for recovery of Start-Up Offer and No-Load Offer costs

proportional to that Asset Owner’s JOU Ownership Percent Share whether or not that JOU Share

Resource was dispatched greater than zero MWs as described under Section 4.5.8.12 and 4.5.9.8.

This option must be selected if the eligibility criteria stated under the Individual Resource Option

cannot be met. The following additional information must also be provided:

(1) Specification of a single Asset Owner (“designated Asset Owner”) that will be responsible

for submittal by or on its behalf of all unit commitment related datathe Resource Offer and

the following operating data representing the physical operating characteristics of entire

JOU Resource for use in data validation as described under Section 4.2.2.5.4;

21

(2) JOU Maximum Physical Capacity Operating Limit;

(3) JOU Minimum Physical Capacity Operating Limit;

(4) JOU Minimum Physical Regulation Capacity Operating Limit; and

(5)(1) Maximum physical 10-minute response from an off-line state.;

(2) Specification of each Asset Owner, JOU Ownership Percent Share and Settlement Location

associated with each individual ownership share JOU Resource.

(a) Submitted JOU Ownership Percent Shares must add up to 100%.

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

that JOU Resource unless each individual JOU Resource owner registers a different Meter Agent

for its share of the Resource.

SPP Tariff (OATT)

Attachment AE 1.1 Definitions J Jointly Owned Unit

A Resource that is owned by more than one Asset Owner or a Resource for which multiple Asset

Owners have contractual rights or financial obligations.that allow the submittal of a Resource

Offer into the Integrated Marketplace.

2.2 Application and Asset Registration (1) Applications for a Market Participant to provide services in the Integrated

Marketplace must be submitted to the Transmission Provider prior to the expected

date of participation consistent with Section 6.4 of the Market Protocols.

Applications must conform to the procedures specified in the Market Protocols and

may be rejected if not complete. New Market Participants will follow the timeframe

as specified in Section 6.4 of the Market Protocols in addition to the detailed model

update timing requirements in Appendix E of the Market Protocols.

22

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

and load, including applicable load associated with Grandfathered Agreements

(“GFAs”), Non-Conforming Load and Demand Response Load with the

Transmission Provider in accordance with the registration process specified in the

Market Protocols. As part of Resource registration, Market Participants must

specify whether settlement meter data will be submitted on a gross basis or net

basis, where gross meter data does not include reductions for auxiliary load and net

meter data is gross meter data reduced by auxiliary load. Both Non-Conforming

Load and Demand Response Load may only be associated with a single Price Node

except that Non-Conforming Load and Demand Response Load may be associated

with an aggregated Price Node that contains multiple electrically equivalent Price

Nodes. Non-participating embedded load and/or generation must either: (i) register

its load and/or generation in the Integrated Marketplace; or (ii) transfer its load

and/or generation to an external Balancing Authority.

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

multiple Meter Data Submittal Locations associated with their load assets. Market

Participants may not aggregate multiple Resource Meter Data Submittal Locations

into a single Resource Settlement Location unless the Resources are at the same

physical and electrically equivalent injection point to the Transmission System.

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

and under the Market Protocols, Market Participants wishing to model each

participant’s share of a Jointly Owned Unit as a separate Resource must choose one

of the two options described below and provide the specified additional

information. A Resource registered as a combined cycle Resource may not register

as a Jointly Owned Unit.

(a) Individual Resource Option

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

modeled as a separate Resource for the purposes of commitment and,

dispatch and Operating Reserve Clearing, and each Resource may be

committed independent of the other Resource shares.

23

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

Jointly Owned Unit unless each individual Jointly Owned Unit participant

registers a Meter Agent for its share of the Resource.

Unless otherwise agreed to by the Jointly Owned Unit participants,

the operating owner will be responsible for submitting the following data:

• Jointly Owned Unit maximum physical capacity operating

limit;

• Jointly Owned Unit minimum physical capacity operating

limit;

• Jointly Owned Unit minimum physical regulation capacity

operating limit; and

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

line state.

(b) Combined Resource Option

Under the combined Resource option, the Jointly Owned Unit is

modeled as one market Resource for the purposes of commitment, dispatch

and Operating Reserve clearing. each participant’s share is modeled and

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

commitment decision is made for the JOU Resource assuming that all

Resource shares must be committed or none at all. Each Asset Owner of a

Jointly Owned Unit under the combined Resource option must submit a

zero for the Minimum Emergency Capacity Operating Limit, Minimum

Normal Capacity Operating Limit, Minimum Regulation Capacity

Operating Limit, and Minimum Economic Capacity Operating Limit. The

Jointly Owned Unit minimum physical capacity operating limit and

minimum physical regulation capacity operating limit when the Jointly

Owned Unit is selected to Regulate, can be achieved by any combination of

Jointly Owned Unit shares during the commitment period. A Jointly Owned

Unit under the combined Resource option will be dispatched using an

aggregated Energy Offer Curve. Once committed, each Jointly Owned Unit

share is dispatched independently and is eligible for recovery of Start-Up

24

Offer and No-Load offer costs as described under Sections 8.5.9 and 8.6.5

of this Attachment AE. This option must be selected if the eligibility criteria

stated under the individual Resource option cannot be met.

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

Jointly Owned Unit unless each individual Jointly Owned Unit participant

registers a Meter Agent for its share of the Resource.

Unless otherwise agreed to by the Jointly Owned Unit participants,

the operating owner will be responsible for submitting the following data:

• Jointly Owned Unit maximum physical capacity operating

limit;

• Jointly Owned Unit minimum physical capacity operating

limit;

• Jointly Owned Unit minimum physical regulation capacity

operating limit;

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

line state; and

• Participant share percentage by Market Participant.

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

registration procedures specified in the Market Protocols.

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

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

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

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

the name of the load Asset Owner. Failure or refusal to register a Resource will

result in the Transmission Provider filing an unexecuted version of the service

agreement as specified in Attachment AH of this Tariff for that Resource with the

Commission under the name of the generation interconnection customer under an

interconnection agreement with the Transmission Provider or the applicable

Transmission Owner. In the case of a Qualifying Facility exercising its rights under

PURPA to deliver all of its net output to its host utility, such registration will not

require the Qualifying Facility to participate in the Energy and Operating Reserve

25

Markets or subject the Qualifying Facility to any charges or payments related to the

Energy and Operating Reserve Markets. Any Energy and Operating Reserve

Market charges or payments associated with the output of the Qualifying Facility

will be allocated to the Market Participant representing the host utility purchasing

the output of the Qualifying Facility under PURPA, and the Market Participant will

be provided the settlement data required to verify the settlement charges and

payments.

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

Operating Reserve Markets will utilize an External Resource Pseudo-Tie in

accordance with Attachment AO. In addition to the responsibilities outlined in

Attachment AO, the Market Participant registering the External Resource will be

responsible for registering and performing all responsibilities that are required of

Resources in the Energy and Operating Reserve Markets.

(8) A Market Participant wishing to offer Demand Response Load as a Demand

Response Resource in the Energy and Operating Reserve Markets must include in

its application and registration a certification that participation in the Energy and

Operating Reserve Markets by its Demand Response Resource is not precluded

under the laws or regulations of the relevant electric retail regulatory authority.

Consistent with Section 2.8.1 of this Attachment, an aggregator of retail customers

wishing to offer Demand Response Load in the form of a Demand Response

Resource on behalf of one or more retail customers must also include in its

application and registration a certification that participation of each retail customer

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

regulatory authority if the customer is served by a utility that distributed more than

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

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

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

year. Demand Response Resources must meet all application, registration and

technical requirements applicable to the Energy and Operating Reserve Markets.

The Transmission Provider is not responsible for interpreting the laws or

regulations of a relevant electric retail regulatory authority and shall be required

26

only to verify that the Market Participant has included such a certification in its

application materials. The Transmission Provider is not liable or responsible for

Market Participants participating in the Energy and Operating Reserve Markets in

violation of any law or regulation of a relevant electric retail regulatory authority

including state-approved retail tariff(s).

(9) An aggregator of retail or wholesale customers offering Demand Response Load of

one or more end-use retail customers or wholesale customers as a Demand

Response Resource in the Energy and Operating Reserve Markets must be a Market

Participant, satisfying all registration and certification requirements applicable to

Market Participants as well as certification consistent with Section 2.8 of this

Attachment, as required.

(10) All Variable Energy Resources must register as a Dispatchable Variable Energy

Resource except for (1) a wind-powered Variable Energy Resource with an

interconnection agreement executed on or prior to May 21, 2011 and that

commenced Commercial Operation before October 15, 2012 or (2) a Qualifying

Facility exercising its rights under PURPA to deliver its net output to its host utility

or (3) a non-wind powered Variable Energy Resource registered on or prior to

January 1, 2017 and with an interconnection agreement executed on or prior to

January 1, 2017. Variable Energy Resources included in (1) and (3) above may

register as Dispatchable Variable Energy Resources if they are capable of being

incrementally dispatched by the Transmission Provider. A Qualifying Facility

exercising its rights under PURPA to deliver its net output to its host utility may

register as a Dispatchable Variable Energy Resource if it is capable of being

incrementally dispatched by the Transmission Provider and will be subject to the

Dispatchable Variable Energy Resource market rules including Uninstructed

Resource Deviation charges. Any Resource that has previously registered as a

Dispatchable Variable Energy Resource shall not subsequently register as a Non-

Dispatchable Variable Energy Resource.

(11) A Market Participant that is selling firm power to the load asset under a bilateral

contract may, with the agreement of the buyer, register all or a portion of the buyer’s

load as its load asset. For purposes of this Section 2.2(11) of this Attachment AE,

27

the sale of firm power shall refer to power sales deliverable with firm transmission

service, with the supplier assuming the obligation to serve the buyer’s load with

both capacity and energy. For the purposes of Section 2.11.1 of this Attachment

AE, such registration of the buyer’s load by the seller shall be accounted for by

including such load in the seller’s Reported Load and not including such load in the

buyer’s Reported Load, as described under Section 2.11.1(A)(1) of this Attachment

AE, and such associated bilateral contracts shall not be included in either the

buyer’s or seller’s net resource capacity described under Section 2.11.1(A)(4) of

this Attachment AE.

(12) A Transmission Owner providing firm transmission service under a GFA eligible

for GFA Carve Out must request removal of congestion and marginal loss charges

and designate the GFA Responsible Entity within the timeframe set forth in Section

2.2 (1) of Attachment AE.

(13) A GFA Responsible Entity shall provide to the Transmission Provider the

information necessary to administer the GFA Carve Out. The required information

shall include the following:

(a) Resource Settlement Location;

(b) Load Settlement Location;

(c) The maximum MW capacity contracted under the GFA Carve Out;

(d) The identification of the GFA in Attachment W; and

(e) Any other information reasonably required by the Transmission Provider.

(14) Market Participants with assets interconnected to the Transmission System that are

not participating in the Energy and Operating Reserve Markets must pseudo-tie the

Resource or load out of the SPP Balancing Authority Area in accordance with

Attachment AO. Such assets shall continue to be registered in the Integrated

Marketplace for the purposes of accounting for congestion and loss charges

between the Resource Price Node and the applicable External Interface Settlement

Location as described under Sections 8.6.23 and 8.6.24 of this Attachment AE.

(a) To the extent that the SPP Balancing Authority or associated external

Balancing Authority can no longer maintain the Resource pseudo-tie for

28

reliability reasons, the Market Participant representing the pseudo-tied

Resource must immediately reduce the output of the pseudo-tied resource

to the available pseudo-tie capability after receiving notification from the

affected Balancing Authority of the reduced capability. A Market

Participant shall not generate any energy in excess of the available pseudo-

tie capability after receiving such notification and shall not be compensated

in the Energy and Operating Reserve Markets settlement for any energy

generated in excess of the available pseudo-tie capability.

(15) Western-UGP shall provide to the Transmission Provider the information necessary

to administer the FSE. The required information shall include the following:

(a) Resource Settlement Locations;

(b) Load Settlement Locations;

(c) The maximum MW capacity contracted under the FSE;

(d) The identification of the FSE Statutory Load Obligations as described in the

SPP-Western-UGP NITSA; and

(e) Any other information reasonably required by the Transmission Provider.

(16) The Transmission Provider shall establish FSE Transfer Points consistent with the

FSE transmission service power flow impacts.

(17) A Market Participant registering a Staggered Start Resource shall attest that the

Resource meets the Staggered Start Resource definition in this Attachment AE.

The attestation shall contain sufficient detail regarding the specific circumstances

of the Resource to demonstrate that it meets the definition of a Staggered Start

Resource. A Market Participant that has registered a Staggered Start Resource shall

change the registration status no later than thirty (30) business days from the date

the Resource ceases to meet the Staggered Start Resource definition.

4.1 Offer Submittal Beginning seven (7) days prior to the Operating Day, Market Participants may

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

Day-Ahead Market Offers may be updated up to the close of the Day-Ahead Market and

29

RTBM Offers may be updated thirty (30) minutes prior to each Operating Hour. Offer

submittals shall conform to the following:

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

in the RTBM except that, if Regulation-Up Service and/or Regulation-Down

Service is cleared in the Day-Ahead Market, Regulation-Up Mileage Offers and/or

Regulation-Down Mileage Offers for the associated Resources for use in the RTBM

are set equal to the Regulation-Up Mileage Offers and/or Regulation-Down

Mileage Offers for the associated Resources submitted for use in the Day-Ahead

Market;

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

also apply in the RTBM;

(a) Such an Offer shall be rejected in the RTBM if the Market Participant has

submitted a Resource commitment status of “not participating” as described

in Section 4.1(10)(e) of this Attachment AE and the Resource is not

participating in the Day-Ahead Market.

(3) Submitted Resource Offers will automatically roll forward hour to hour within each

respective market only when no Resource Offer has been submitted for that

interval;

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

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

which a single value is submitted. These unit commitment Offer parameters will

automatically roll forward in each hour of the subsequent Operating Day only when

no unit commitment Offer parameters have been submitted for that Operating Day;

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

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

Interchange Transaction Offers may only be submitted at External Interface

Settlement Locations and Virtual Energy Offers may be submitted at any

Settlement Location;

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

Market Participants may submit Regulation-Up Offers, Regulation-Up Mileage

Offers, Spinning Reserve Offers and Supplemental Reserve Offers provided that if

30

the Regulation-Up Offer is negative, the Regulation-Up Mileage Offer must equal

zero. For Regulation-Down Qualified Resources and Regulation Qualified

Resources, Market Participants may submit Regulation-Down Offers and

Regulation-Down Mileage Offers provided that if the Regulation-Down Offer is

negative, the Regulation-Down Mileage Offer must equal zero. For Spin Qualified

Resources, Market Participants may submit Resource Offers for Spinning Reserve

and Supplemental Reserve. For Supplemental Qualified Resources, Market

Participants may submit Resource Offers for Supplemental Reserve. If a Spinning

Reserve Offer is submitted for a Resource, and a Resource Offer for Supplemental

Reserve is not submitted, then the Supplemental Reserve Offer is set equal to zero.

Resource qualifications are verified by the Transmission Provider as part of the

registration process as follows:

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

Regulation-Down Qualified Resource must pass a specific regulation test

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

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

Regulation-Down within the Regulation Response Time for a continuous

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

meets the technical requirements specified in the Market Protocols.

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

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

cleared Supplemental Reserve within the Contingency Reserve Deployment

Period for a continuous duration of sixty (60) minutes and provide

telemetered output data that meets the technical requirements specified in

the Market Protocols.

(c) Supplemental Qualified Resource:

(i) A Supplemental Qualified Resource must self-certify that the

Resource is capable of deploying one hundred percent (100%) of cleared

Supplemental Reserve from an off-line state within the Contingency

Reserve Deployment Period for a continuous duration of sixty (60) minutes

31

and provide telemetered output data that meets the technical requirements

specified in the Market Protocols.

(ii) Alternatively, an MCR may also become a Supplemental

Qualified Resource by self-certifying that the MCR is capable of deploying

100% of cleared Supplemental Reserve through a transition to a higher

capacity configuration within the Contingency Reserve Deployment Period

for a continuous duration of sixty (60) minutes and provide telemetered

output data that meets the technical requirements specified in the Market

Protocols.

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

of this Attachment AE;

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

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

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

further defined in the Market Protocols):

• Resource Name

• Resource Type

• Start-up Offer

• No-Load Offer

• Energy Offer Curve

• Transition State Offer (for an MCR)

• Transition State Time (for an MCR)

• Regulation–Up and Regulation-Down Offers

• Regulation-Up Mileage and Regulation-Down Mileage Offers

• Spinning and Supplemental Reserve Offers

• Sync-To-Min and Min-To-Off Times

• Start-Up Time

• Hot to Intermediate and Hot to Cold Times

• Maximum Daily and Weekly Starts

• Maximum Daily Energy

32

• Maximum and Minimum Run Times

• Plant Minimum Run Time (for an MCR)

• Group Minimum Run Time (for an MCR)

• Minimum Down Time

• Minimum Emergency Capacity Operating Limit and Run Time

• Minimum Normal, Economic, and Regulation Capacity Operating Limits

• Maximum Normal, Economic, and Regulation Capacity Operating Limits

• Maximum Emergency Capacity Operating Limits and Run Time

• Maximum Quick-Start Response Limit

• Maximum Transition State Supplemental Reserve Resource Response

Limit (for an MCR)

• Ramp-Rate-Up and Ramp-Rate-Down

• Turn-Around Ramp Rate Factor

• Regulation Ramp Rate

• Contingency Reserve Ramp Rate

• Resource Status

• JOU Ownership Share

• JOU Minimum Physical Capacity Operating Limit

• JOU Minimum Physical Regulation Capacity Operating Limit

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

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

Market Protocols. Market Participants use the commitment status to indicate;

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

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

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

only to alleviate an anticipated Emergency Condition or local reliability

issue;

(d) Whether the Resource is on an outage; or

(e) Whether the Resource is not participating in the Day-Ahead Market.

33

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

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

Protocols. Market Participants use the dispatch status to notify the Transmission

Provider whether the Resource is:

(a) Eligible for Energy Dispatch;

(b) Eligible for Operating Reserve clearing; or

(c) Self-scheduled for Operating Reserve.

If the dispatch status for a Resource does not indicate it is eligible for Energy

Dispatch, then such Resource shall not be subject to charges and credits calculated

under Section 8.6.15 of this Attachment AE and shall not be subject to the deviation

calculations under Sections 8.6.7(A)(2)(e) and 8.6.7(A)(2)(g) of this Attachment

AE.

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

rules defined in the Market Protocols, otherwise, the Resource Offer will be

rejected; and

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

in Section 2.11 of this Attachment AE.

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4.1.2.3 Jointly Owned Unit Under the individual Jointly Owned Unit Resource option, Eeach Market

Participant may submit Resource Offers for its share of the Jointly Owned Unit as specified

in the Market Protocols. Offer parameters must meet the following criteria in order to be

accepted as valid Offers, otherwise the last submitted valid offer shall apply:

(1) The sum of the Maximum Emergency Capacity Operating Limits of all shares of

the Jointly Owned Unit must be less than or equal to the Jointly Owned Unit

maximum physical capacity operating limit.

Commitment of individual Jointly Owned Unit shares that have registered under the

individual Resource option will be evaluated by security constrained unit commitment

(“SCUC”) based on the individually submitted Offers for each Jointly Owned Unit share.

Under the combined Jointly Owned Unit Resource option, the designated Asset Owner of

the JOU will submit the Resource Offer to be used for commitment, dispatch, and

Operating Reserve clearingthe designated Asset Owner as specified in the Market

Protocols. Commitment of a combined Jointly Owned Unit shares that have registered

under the combined Resource option will be evaluated by SCUC based on a combination

of the individually submitted Resource Offers for each Jointly Owned Unit share and the

commitment related Offer parameterst submitted by the designated Market Participant that

appliesy to the entire Jointly Owned Unit. given the additional constraint that if one of the

Jointly Owned Units is committed, all Resource shares for each Jointly Owned Unit must

be committed. This rule also applies to clearing of Supplemental Reserve from off-line

Quick-Start Resources. Each Market Participant of a Jointly Owned Unit share under the

combined Resource option must submit a zero for Minimum Emergency Capacity

Operating Limit, Minimum Normal Capacity Operating Limit, Minimum Regulation

Capacity Operating Limit, and Minimum Economic Capacity Operating Limit. A Jointly

Owned Unit under the combined Resource option will be dispatched using an aggregated

Energy Offer Curve. When committed, each Jointly Owned Unit share is eligible for

recovery of Start-Up Offer and No-Load Offer costs as described under Sections 8.5.9 and

8.6.5 of this Attachment AE. For Make Whole Payment calculation purposes, the Resource

Offer for each JOU Share Resource associated with the JOU Resource is set equal to the

JOU’s Resource Offer as submitted by or on behalf of the designated Asset Owner and

of 35

each share’s Make Whole Payment will be determined based on the JOU Ownership

Percent Share.

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Revision Request Form SPP STAFF TO COMPLETE THIS SECTION

RR #: 273 Date: 1/16/2017

RR Title: Market Settlements RNU Rounding System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes


Name: John Luallen Company: Southwest Power Pool

Email: [email protected] Phone: 501.688.1655 Only Qualified Entities may submit Revision Requests.

Please select at least one applicable option below, as it applies to the named submitter(s).

SPP Staff SPP Market Participant SPP Member An entity designated by a Qualified Entity to submit

a Revision Request “on their behalf”

SPP Market Monitor Staff of government authority with jurisdiction over

SPP/SPP member Rostered individual of SPP Committee, Task Force or

Working Group Transmission Customers or other entities that are parties to

transactions under the Tariff REVISION REQUEST DETAILS

Requested Resolution Timing: Normal Expedited Urgent Action

Reason for Expedited/Urgent Resolution:

Type of Revision (select all that apply):

Correction

Clarification

Design Enhancement

New Protocol, Business Practice, Criteria, Tariff

NERC Standard Impact (Specifically state if revision relates to/or impacts NERC Standards, list standard(s))

FERC Mandate (List order number(s))

REVISION REQUEST RISK DRIVERS

Are there existing risks to one or more SPP Members or the BES driving the need for this RR? Yes No

If yes, provided details to explain the risk and timelines associated:

Compliance (Tariff, NERC, Other)

Reliability/Operations

Financial

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SPP Documents Requiring Revision: Please select your primary intended document(s) as well as all others known that could be impacted by the requested revision (e.g. a change to a protocol that would necessitate a criteria or business practice revision).

Market Protocols Section(s): 4.5.8.18, 4.5.8.27, 4.5.8.28, 4.5.10.6, 4.5.12 Protocol Version: 53

Operating Criteria Section(s): Criteria Date: Planning Criteria Section(s): Criteria Date: Tariff (OATT) Section(s): Attachment AE - 8.8 Business Practice Business Practice Number: Integrated Planning Model (ITP Manual) Section(s): Revision Request Process Section(s): Minimum Transmission Design



SPP Communications Protocols Section(s):


Objectives of Revision Request: Describe the problem/issue this revision request will resolve.

The current Settlement System contains charge types that are currently not part of RNU processing that result in rounding/residual amounts that have to be manually processed and distributed to remain revenue neutral through Miscellaneous charges. The following proposal would be implemented as part of the new Settlement System scheduled to go live May 2019.

Automate the distribution of rounding/residual issues for the following by incorporating them into the RNU process:

• GFA Daily Distributions – Incorporate GFA Daily Distributions per section 4.5.8.26 of the Protocols into 4.5.12 Revenue Neutrality Uplift Distribution Amount calculation to account for any rounding issues.

• GFA Monthly Distributions – Incorporate GFA Monthly Distributions per section 4.5.8.27 of the Protocols into 4.5.12 Revenue Neutrality Uplift Distribution Amount calculation to account for any rounding issues. The precision is being increased in the share factor to reduce the amount of rounding issues.

• GFA Yearly Distributions – Incorporate GFA Yearly Distributions per section 4.5.8.28 of the Protocols into 4.5.12 Revenue Neutrality Uplift Distribution Amount calculation to account for any rounding issues. The precision is being increased in the share factor to reduce the amount of rounding issues.

• TCR Annual Closeout – Incorporate Transmission Congestion Rights Annual Closeout per section 4.5.8.18 of the Protocols into 4.5.12 Revenue Neutrality Uplift Distribution Amount calculation to account for any rounding issues.

• ARR Annual Closeout – Incorporate Auction Revenue Rights Annual Closeout per section 4.5.10.6 into 4.5.12 Revenue Neutrality Uplift Distribution Amount calculation to account for any rounding issues.

• RNU Residual/Rounding – Incorporate logic to automatically apply any RNU residual amount to the Market Participant with the maximum RNU amount. If multiple Market Participants have the maximum RNU amount, the Market Participant with that max will be selected based on alphabetic order.

Describe the benefits that will be realized from this revision.

The automation of processing will replace manual processing and distribution through Miscellaneous charges.

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REVISIONS TO SPP DOCUMENTS In the appropriate sections below, please provide the language from the current document(s) for which you are requesting revision(s), with all edits redlined.

Market Protocols

4.5.8.18 Transmission Congestion Rights Annual Closeout Amount

(1) A DA Market annual credit or charge1 will be calculated for each Asset Owner Transmission Customer with an ARR Nomination Caps established under Section 5.1.3 to the extent that there are any funds remaining once all credits are paid under Section 4.5.8.17. The calculation of the Transmission Congestion Rights Annual Closeout Amount for each Asset Owner with an ARR nomination Cap can result in a residual amounts due to rounding as established under Section 4.5.7. The sum of the residual amounts due to rounding across Asset Owners can result in the Transmission Congestion Rights not being revenue neutral for the year, whether a credit or charge, will be included in the Revenue Neutrality Uplift as established under Section 4.5.12 on the last Operating Day of the planning year. The difference, whether a credit or charge, will be uplifted to the Asset Owners on a yearly basis. On Operating Day March 1, of every year, SPP will uplift the annual residual amount with a Miscellaneous Adjustment to the Asset Owners. The Transmission Congestion Rights Annual Closeout amount is calculated as follows:

#TcrCloseoutYrlyAmt a, yr = (-1) * [ ECFYrlyAmt yr + TcrPaybackSppYrlyAmt yr ]

* ArrNominationCapAoYrlyQty a, yr

/ ArrNominationCapSppYrlyQty yr

(a) TcrPaybackSppYrlyAmt yr = ∑a

TcrPaybackYrlyAmt a, yr

(b) ArrNominationCapAoYrlyQty a, yr = ∑d

ArrNominationCapQty a, d

1 Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.

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(c) ArrNominationCapSppYrlyQty yr = ∑a∑

d ArrNominationCapQty a, d

(2) For each Market Participant, an annual amount is calculated representing the sum of all Asset Owner amounts associated with that Market Participant. The annual amount is calculated as follows:

TcrCloseoutYrlyMpAmt m, yr = ∑a

TcrCloseoutYrlyAmt a, yr

…

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4.5.8.27 GFA Carve Out Distribution Monthly Amount

(1) A charge or credit will be calculated at each Settlement Location for each Asset Owner in order for SPP to remain revenue neutral on a monthly basis. Contributors to revenue non-neutrality include:

(a) Reversal of credits to GFA Carve-Outs and FSEs through Monthly TCR Payback and

(b) Reversal of credits to GFA Carve-Outs and FSEs through Monthly ARR Payback;

The amount will be determined by multiplying the Asset Owner monthly determinant by the monthly GFA Carve-Out revenue inadequacy amount. The Asset Owner monthly determinant is equal to the Asset Owner’s monthly real-time load ratio share where such real-time load ratio share excludes GFA Carve Out load and FSE load.

The amount to each applicable Asset Owner is calculated as follows.

#DaGFACarveOutDistMnthlyAmt a, s, mn =

(GFARevInadqcSppMnthlyAmt spp, mn *

RtGFALoadRatioShareMnthlyFct a, s, mn ) * (-1)

Where,

(a) #RtGFALoadRatioShareMnthlyFct a, s, mn =

(∑d

RtGFALoadRatioShareDlyFct a, s, d)

/ (∑a∑

s∑

d RtGFALoadRatioShareDlyFct a, s, d)

(b) GFARevInadqcSppMnthlyAmt spp, mn = ∑m

DaGFAMpMnthlyAmt m, mn

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(2) For each Asset Owner associated with Market Participant m, a monthly amount is calculated. The monthly amount is calculated as follows:

DaGFACarveOutDistAoMnthlyAmt a, m, mn =

∑s

DaGFACarveOutDistMnthlyAmt a, s, mn

(3) For each Market Participant, a monthly amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The monthly amount is calculated as follows:

DaGFACarveOutDistMpMnthlyAmt m, mn =

∑a

DaGFACarveOutDistAoMnthlyAmt a, m, mn

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4.5.8.28 GFA Carve Out Distribution Yearly Amount

(1) A charge or credit will be calculated at each Settlement Location for each Asset Owner in order for SPP to remain revenue neutral on a yearly basis. Contributors to revenue non-neutrality include:

(a) Reversal of credits to GFA Carve-Outs and FSEs through Yearly TCR Payback;

(b) Reversal of credits to GFA Carve-Outs and FSEs through Yearly TCR Closeout;

(c) Reversal of credits to GFA Carve-Outs and FSEs through Yearly ARR Payback and

(d) Reversal of credits to GFA Carve-Outs and FSEs through Yearly ARR Closeout

The amount will be determined by multiplying the Asset Owner yearly determinant by the yearly GFA Carve-Out revenue inadequacy amount. The Asset Owner yearly determinant is equal to the Asset Owner’s yearly load ratio share where such load ratio excludes GFA Carve Out load and FSE load.


#DaGFACarveOutDistYrlyAmt a, s, yr =

(GFARevInadqcSppYrlyAmt spp, yr * RtGFALoadRatioShareYrlyFct a, s, yr ) * (-1)

Where,

(a) #RtGFALoadRatioShareYrlyFct a, s, yr =

(∑d

RtGFALoadRatioShareDlyFct a, s, d)

/ (∑a∑

s∑

d RtGFALoadRatioShareDlyFctQty a, s, d )

…

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4.5.10.6 Auction Revenue Rights Annual Closeout Amount

(1) An annual credit or charge2 will be calculated for each Asset Owner with ARR Nomination Caps established under Section 5.1.3 to the extent that there are any funds remaining once all credits are paid under Section 4.5.10.4. The calculation for the Auction Revenue Rights Annual Closeout Amount for each Asset Owner with an ARR Nomination Cap can result in a residual amounts due to rounding as established in Section 4.5.7. The sum of the residual amounts due to rounding across Asset Owners, whether a credit or charge, can result in the Auction Revenue Rights not being revenue neutral for the year. The difference, whether a credit or charge, will be uplifted to the Asset Owners on a yearly basis. On Operating Day March 1, of every year, SPP will uplift the annual residual amount with a Miscellaneous Adjustment to the Asset Ownerswill be included in the Revenue Neutrality Uplift as established under Section 4.5.12 on the last Operating Day of the planning year. The Auction Revenue Rights Annual Closeout amount is calculated as follows:

#ArrCloseoutYrlyAmt a, yr = (-1) * [ARFYrlyAmt yr + ArrPaybackSppYrlyAmt yr]

* [ArrNominationCapAoYrlyQty a, yr / ArrNominationCapSppYrlyQty yr]

Where,

ArrPaybackSppYrlyAmt yr = ∑a

ArrPaybackYrlyAmt a, yr

(2) For each Market Participant, an annual amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The annual amount is calculated as follows:

ArrCloseoutYrlyMpAmt m, yr = ∑a

ArrCloseoutYrlyAmt a, yr


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The above variables are defined as follows: Variable

Unit

Settlement Interval

Definition

ArrCloseoutYrlyAmt a, yr $ Year Auction Revenue Rights Annual Payback Amount per AO per Year - AO a’s share of any remaining ARFYrlyAmt mn in year yr.

ArrPaybackYrlyAmt a, yr $ Year Auction Revenue Rights Annual Payback Amount per AO per Year - The value calculated under Section 4.5.8.17.

ArrNominationCapAoYrlyQty a, yr MW Year ARR Nomination Cap per AO per Year – The sum of the values described under Section 0 for AO a for year yr.

ArrNominationCapSppYrlyQty yr MW Year ARR Nomination Cap Total per Year – The value calculated under Section 0.

ArrPaybackSppYrlyAmt yr $ Year Auction Revenue Rights Annual Payback Amount per Year - The value calculated under Section 0.

ARFYrlyAmt yr $ Year Auction Revenue Fund Yearly Amount – The sum of ARFMthlyAmt

mn in year yr. ArrNominationCapQty a, d MW Operating

Day ARR Nomination Cap per AO per Operating Day – The value described under Section 0.

ArrCloseoutYrlyMpAmt m, yr $ Year Auction Revenue Rights Annual Payback Amount per MP per Year - MP a’s share of the ARFYrlyAmt yr in year yr.

a none none An Asset Owner. d none none An Operating Day. yr none none A year. m none none A Market Participant.

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4.5.12 Revenue Neutrality Uplift Distribution Amount

(1) A charge or credit will be calculated at each Settlement Location for each Asset Owner for each hour in order for SPP to remain revenue neutral. Contributors to revenue non-neutrality include:

(a) Rounding errors (related to the calculation of all Charges/Credits);

(b) Inadvertent Interchange (as calculated as shown in equation b.3 below);

(c) Joint Operating Agreement Charges/Credits;

(d) RTBM congestion (as calculated as shown in equation b.4 below);

(e) RTBM Regulation Deployment Adjustment;

(f) Make Whole Payments for Out-of-Merit Energy; and

(g) Miscellaneous Charges/Credits.

The amount will be determined by multiplying the Asset Owner hourly determinant by a daily Revenue Neutrality Uplift (RNU) rate. The Asset Owner hourly determinant is equal to the sum that Asset Owner’s actual generation MWh, actual load MWh, actual Interchange Transaction MWh, DA Market cleared Virtual Offer MWh and DA Market cleared Virtual Bid MWh for the Hour, where all of these values are assumed to be positive values.

The calculation of the Revenue Neutrality Uplift (RNU) for each Asset Owner and Settlement Location in the SPP footprint region can result in residual amounts due to rounding as established in Section 4.5.7. The sum of the residual amounts due to rounding can result in SPP not being revenue neutral for the an Operating Day will be uplifted to the Market Participant with the Asset Owner who has the largest daily market activity as defined by summing the hourly determinant established in the previous paragraph across all hours of the Operating Day. The residual amounts for each Operating Day will be summed on a yearly basis. The annual residual amount, whether a credit or a charge, will be uplifted to the Asset Owners and Settlement Locations. On Operating Day March 1 of every year, SPP will uplift the annual residual amount with a Miscellaneous Adjustment to the Asset Owners and Settlement Locations.


#RtRnuHrlyAmt a, s, h = ( RtRnuSppDistRate d * RtRnuDistHrlyQty a, s, h ) * (-1)

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Where,

(a) #RtRnuDistHrlyQty a, s, h = (∑i

ABS (RtBillMtr5minQty a, s, i ) / 12) + (∑i∑

t[ (ABS

(RtImpExp5minQty a, s, i, t )/12) * (1 – RsgCrdFlgt ) ]) + (∑t

ABS (DaClrdVHrlyQty

a, s, h, t))

(b) #RtRnuSppDistRate d = RtRnuSppDlyAmt spp, d / RtRnuDistSppQty spp, d

(bc) #RtRnuSppDistRate RtRnuSppDlyAmt spp, d =

( DaRevInadqcSppAmt spp, d

+ RtRevInadqcSppAmt spp, d

+ RtOomSppAmt spp, d

+ RtRegAdjSppAmt spp, d

+ RtJoaSppAmt spp, d

- RtNetInadvertentSppAmt spp, d

+ RtCongestionSppAmt spp, d ) / RtRnuDistSppQty spp, d

Where,

RtOomSppAmt spp, d = ∑m

RtOomMpAmt m, d

RtRegAdjSppAmt spp, d =∑m

RtRegAdjMpAmt m, d

RtJoaSppAmt spp, d =∑a∑

h∑

fRtJoaHrlyAmt a, h, f

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RtRnuDistSppQty spp, d =∑a∑

s∑

hRtRnuDistHrlyQty a, s, h

(bc.1) DaRevInadqcSppAmt spp, d =

∑m

( DaEnergyMpAmt m, d + DaNEnergyMpAmt m, d + DaVEnergyMpAmt m, d

+ DaGFACarveOutDistMpDlyAmt m, d

+ DaRegUpMpAmt m, d + DaSpinMpAmt m, d + DaSuppMpAmt m, d

+ DaRegDnMpAmt m, d + DaRegUpDistMpAmt m, d + DaSpinDistMpAmt m, d

+ DaSuppDistMpAmt m, d + DaRegDnDistMpAmt m, d + DaMwpMpAmt m, d

+ DaMwpDistMpAmt m, d + TcrFundMpAmt m, d + TcrUpliftDlyMpAmt m, d


+ DaGFACarveOutDistMpMnthlyAmt m, mn

+ DaGFACarveOutDistMpYrlyAmt m, yr

+ TcrAucTxnMpAmt m, d + ArrAucTxnMpAmt m, d

+ ArrUpliftMpAmt m, d + DaDRMpAmt m, d + DaDRDistMpAmt m, d

+ TcrCloseoutYrlyMpAmt m, yr + ArrCloseoutYrlyMpAmt m, yr )

- ECFDlyAmt d - ARFDlyAmt d + ECFYrlyAmt yr + ARFYrlyAmt yr

+ TcrPaybackSppYrlyAmt spp, yr + ArrPaybackSppYrlyAmt spp, yr

+ GFARevInadqcSppAmt spp, d + GFARevInadqcSppMnthlyAmt spp, mn

+ GFARevInadqcSppYrlyAmt spp, yr

-∑h

DaOclHrlyAmt h

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(bc.2) RtRevInadqcSppAmt spp, d =

∑m

( RtEnergyMpAmt m, d + RtNEnergyMpAmt m, d + RtVEnergyMpAmt m, d

+ RtRegUpMpAmt m, d + RtRegDnMpAmt m, d + RtSpinMpAmt m, d

+ RtSuppMpAmt m, d + RtMwpMpAmt m, d

+ RtMwpDistMpAmt m, d + RtRegNonPerfMpAmt m, d

+ RtRegNonPerfDistMpAmt m, d + RtCRDeplFailMpAmt m, d

+ RtOclDistMpAmt m, d + RtCRDeplFailDistMpAmt m, d

+ RtRegUpDistMpAmt m, d + RtRegDnDistMpAmt m, d

+ RegUpUnusedMileMwpMpAmt m, d

+ RegDnUnusedMileMwpMpAmt m, d

+ RtSpinDistMpAmt m, d + RtSuppDistMpAmt m, d

+ RtRsgDistMpAmt m, d + RtDRMpAmt m, d + RtDRDistMpAmt m, d

+ RtPseudoTieCongMpAmt m, d + RtPseudoTieLossMpAmt m, d

+ ∑a

RtRsgDlyAmt a, d )

+ ∑a∑

c∑

s{ IF rnu = 1, THEN MiscDlyAmt a, c, s, rnu, d , ELSE 0 } +

RtNetInadvertentSppAmt spp, d

- RtCongestionSppAmt spp, d

+∑h

DaOclHrlyAmt h

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(bc.3) RtNetInadvertentSppAmt spp, d = ∑i

RtNetInadvertentSpp5minAmt i

(bc.3.1) #RtNetInadvertentSpp5minAmt i =

( ( RtNetActIntrchngSpp5minQty i - RtNetSchIntrchngSpp5minQty i )

* RtMec5minPrc i ) / 12

(bc.4) #RtCongestionSppAmt spp, d = RtPseudoTieCongSppAmt d +

∑a∑

s∑

i ( ( ( RtBillMtr5minQty a, s, i – DaClrdHrlyQty a, s, h )

+ ∑t

(RtImpExp5MinQty a, s, i, t - DaImpExp5MinQty a, s, i, t )

- ∑t

DaClrdVHrlyQty a, s, h, t ) * RtMcc5minPrc s, i ) / 12

(bc.4.1) RtPseudoTieCongSppAmt d = ∑

m RtPseudoTieCongMpAmt m, d

(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The amount is calculated as follows:

RtRnuDlyAmt a, s, d = ∑h

RtRnuHrlyAmt a, s, h

(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The daily amount is calculated as follows:

RtRnuAoAmt a, m, d = ∑s

RtRnuDlyAmt a, s, d

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(4) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The Market Participant with the Asset Owner who has the largest daily market activity will be assessed the residual amount due to rounding as established in Section 4.5.7. The daily amount is calculated as follows:

RtRnuMpAmt m, d = ∑a

[ RtRnuAoAmt a, m, d

+ ( RtRnuMaxAoDlyFlg a, m, d * RtRnuResidualDlyAmt spp, d ) ]

(a) RtRnuResidualDlyAmt spp, d =

( RtRnuSppDlyAmt spp, d + ∑m∑

a RtRnuAoAmt a, m, d ) * (-1)

(b) RtRnuMaxAoDlyFlg a, m, d =

SORTATTRIBUTE a, m ( ( RtRnuMaxAoDlyAmt a, m, d ), “a”, 1 )

(b.1) IF ABS ( RtRnuAoAmt a, m, d ) = RtRnuMaxDlyAmt spp, d

THEN

RtRnuMaxAoDlyAmt a, m, d = RtRnuAoAmt a, m, d

(b.2) RtRnuMaxDlyAmt spp, d = MAX a, m ( ABS ( RtRnuAoAmt a, m, d ) )

Field Code Changed

Field Code Changed

of 26


Unit

Settlement Interval

Definition

RtRnuHrlyAmt a, s, h $ Hour Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Hour – The amount for revenue neutrality to AO a at Settlement Location s in Hour h.

RtRnuSppDistRate d $/MW Operating Day

Real-Time Revenue Neutrality Uplift SPP Distribution Rate per Operating Day – The rate applied to AO a’s RtRnuDistHrlyQty a, s, h in each Hour h at Settlement Location s in Operating Day d.

RtRnuSppDlyAmt spp, d $ Operating Day

Real-Time Revenue Neutrality Uplift SPP Daily Amount – The total amount SPP is not revenue neutral, through all other charge types, in an Operating Day. The amount that is to be uplifted to the SPP market for Operating Day d.

RtRnuResidualDlyAmt spp, d $ Operating Day

Real-Time Revenue Neutrality Uplift Residual Daily Amount – The residual amount, due to rounding, left after allocating RtRnuSppDlyAmt to Asset Owners at Settlement Locations in Operating Day d.

RtRnuDistHrlyQty a, s, h

MWh Hour Real-Time Revenue Neutrality Uplift Quantity per AO per Hour

per Settlement Location – The total MWh RNU allocation determinant for AO a at Settlement Location s for Hour h.

RtRnuDistSppQty spp, d

MWh Operating

Day Real-Time Revenue Neutrality Uplift Quantity for SPP per Operating Day – The total MWh RNU allocation determinant for SPP on a system-wide basis.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Cleared Virtual Energy Quantity per AO per Transaction per Settlement Location per Hour – The value defined under Section 4.5.8.3.

RtOomSppAmt spp, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section 4.5.9.9.

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Variable

Unit

Settlement Interval

Definition

RtRegAdjSppAmt spp, d $ Operating Day

Real-Time Regulation Deployment Adjustment Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section 4.5.9.18.

RtJoaSppAmt spp, d $ Operating Day

Real-Time Joint Operating Agreement Amount for SPP per Operating Day – The SPP system-wide total of the values calculated under Section 4.5.9.21.

DaRevInadqcSppAmt spp, d $ Operating Day

Day-Ahead Revenue Inadequacy Amount – The amount of mismatch on an SPP-wide basis between total DA Market charges and DA Market credits for Operating Day d.

DaEnergyMpAmt m, d $ Operating Day

Day-Ahead Asset Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.1.

DaNEnergyMpAmt m, d $ Operating Day

Day-Ahead Non-Asset Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.2.

DaVEnergyMpAmt m, d $ Operating Day

Day-Ahead Virtual Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.3.

DaRegUpMpAmt m, d $ Operating Day

Day-Ahead Regulation-Up Service Amount per MP per Operating Day – The value calculated under Section 4.5.8.4.

DaRegDnMpAmt m, d $ Operating Day

Day-Ahead Regulation-Down Service Amount per MP per Operating Day – The value calculated under Section 4.5.8.5.

DaSpinMpAmt m, d $ Operating Day

Day-Ahead Spinning Reserve Amount per MP per Operating Day – The value calculated under Section4.5.8.6.

DaSuppMpAmt m, d $ Operating Day

Day-Ahead Supplemental Reserve Amount per MP per Operating Day – The value calculated under Section 4.5.8.7.

DaRegUpDistMpAmt m, d $ Operating Day

Day-Ahead Regulation-Up Service Distribution Amount per MP per Operating Day – The value calculated under Section4.5.8.8.

DaRegDnDistMpAmt m, d $ Operating Day

Day-Ahead Regulation-Down Service Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.9.

DaSpinDistMpAmt m, d $ Operating Day

Day-Ahead Spinning Reserve Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.10.

of 26

Variable

Unit

Settlement Interval

Definition

DaSuppDistMpAmt m, d $ Operating Day

Day-Ahead Supplemental Reserve Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.11.

DaMwpMpAmt m, d $ Operating Day

Day-Ahead Make Whole Payment Amount per MP per Operating Day – The value calculated under Section 4.5.8.12.

DaMwpDistMpAmt m, d $ Operating Day

Day-Ahead Make Whole Payment Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.13.

TcrFundMpAmt m, d $ Operating Day

Transmission Congestion Rights Funding Amount per MP per Operating Day – The value calculated under Section 4.5.8.14.

TcrUpliftDlyMpAmt m, d $ Operating Day

Transmission Congestion Rights Uplift Amount per MP per Operating Day – The value calculated under Section 4.5.8.15.

ECFDlyAmt d $ Operating Day

Excess Congestion Fund Amount per Operating Day – The value calculated under Section 4.5.8.16.

ECFYrlyAmt yr $ Year Excess Congestion Fund Yearly Amount – The value calculated under Section 4.5.8.18.

ARFDlyAmt d $ Operating Day

Auction Revenue Fund Amount per Operating Day – The value calculated under Section 4.5.10.4.

ARFYrlyAmt yr $ Year Auction Revenue Yearly Fund – The value calculated under Section 4.5.10.6.

DaOclHrlyAmt h $ Hour Day-Ahead Incremental Over Collected Losses Amount per Hour – The value described under Section 4.5.9.20.

TcrAucTxnMpAmt m, d $ Operating Day

Transmission Congestion Right Auction Daily Amount per MP per Operating Day – The value calculated under Section 4.5.10.1.

TcrPaybackSppYrlyAmt yr $ Year Transmission Congestion Rights Annual Payback Amount – The value calculated under Section 4.5.8.18

TcrCloseoutYrlyMpAmt m, yr $ Year Transmission Congestion Rights Annual Closeout Amount per MP per Year – The value calculated under Section 4.5.8.18.

ArrAucTxnMpAmt m, d $ Operating Day

Auction Revenue Rights Funding Amount per MP per Operating Day – The value calculated under Section 4.5.10.2.

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Variable

Unit

Settlement Interval

Definition

ArrUpliftMpAmt m, d $ Operating Day

Auction Revenue Rights Funding Uplift Amount per MP per Operating Day – The value calculated under Section 4.5.10.3.

ArrPaybackSppYrlyAmt yr $ Year Auction Revenue Rights Annual Payback Amount per Year – The value calculated under Section 4.5.10.6.

ArrCloseoutYrlyMpAmt m, yr $ Year Auction Revenue Rights Annual Closeout Amount per MP per Year – The value calculated under Section 4.5.10.6.

DaDRMpAmt m, d $ Operating Day

Day-Ahead Demand Reduction Amount per Market Participant per Operating Day – The value calculated under Section 4.5.9.24.

DaDRDistMpAmt m, d $ Operating Day

Day-Ahead Demand Reduction Distribution Amount per Market Participant per Operating Day – The value calculated under Section 4.5.9.25.

RtRevInadqcSppAmt spp, d $ Operating Day

Real-Time Revenue Inadequacy Amount – The amount of mismatch on an SPP-wide basis between total RTBM charges and RTBM credits.

RtBillMtr5minQty a, s, i MW Dispatch Interval

Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1.

RtImpExp5minQty a, s, i, t MW Dispatch Interval

Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2.

RsgCrdFlg t

(Not Available on Settlement Statement)

none none Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Virtual Energy Quantity per AO per Settlement Location per Hour per Transaction – The value described under Section 4.5.8.3.

DaClrdHrlyQty a, s, h MWh Hour Day-Ahead Asset Energy Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.1.

DaImpExp5MinQty a, s, i, t MW Dispatch Interval

Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.8.2.

of 26

Variable

Unit

Settlement Interval

Definition

RtMcc5minPrc s, i $/MW Dispatch Interval

Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of the Real-Time LMP at Settlement Location s for Dispatch Interval i.

RtEnergyMpAmt m, d $ Operating Day

Real-Time Energy Amount per MP per Operating Day – The value described under Section 4.5.9.1.

RtNEnergyMpAmt m, d $ Operating Day

Real-Time Non-Asset Energy Amount per MP per Operating Day – The value described under Section 4.5.9.2.

RtVEnergyMpAmt m, d $ Operating Day

Real-Time Virtual Energy Amount per MP per Operating Day – The value described under Section 4.5.9.3.

RtRegUpMpAmt m, d $ Operating Day

Real-Time Regulation-Up Service Amount per MP per Operating Day – The value described under Section 4.5.9.4.

RegUpUnsedMileMwpMpAmt m, d $ Operating Day

Unused Regulation-Up Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.28.

RtRegDnMpAmt m, d $ Operating Day

Real-Time Regulation-Down Service Amount per MP per Operating Day – The value described under Section 4.5.9.5.

RegUpUnsedMileMwpMpAmt m, d $ Operating Day

Unused Regulation-Down Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.29.

RtSpinMpAmt m, d $ Operating Day

Real-Time Spinning Reserve Amount per MP per Operating Day – The value described under Section 4.5.9.6.

RtSuppMpAmt m, d $ Operating Day

Real-Time Supplemental Reserve Amount per MP per Operating Day – The value described under Section 4.5.9.7.

RtMwpMpAmt m, d $ Operating Day

RUC Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.8.

RtOomMpAmt m, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount per MP per Operating Day - The value described under Section 4.5.9.9.

RtMwpDistMpAmt m, d $ Operating Day

RUC Make Whole Payment Distribution Amount per MP per Operating Day – The value described under Section 4.5.9.10.

of 26

Variable

Unit

Settlement Interval

Definition

RtRegNonPerfMpAmt m, d $ Operating Day

Real-Time Regulation Non-Performance Amount per MP per Operating Day – The value described under Section 4.5.9.15.

RtCRDeplFailMpAmt m, d $ Operating Day

Real-Time Contingency Reserve Deployment Failure Amount per MP per Operating Day – The value described under Section 4.5.9.17.

RtRegAdjMpAmt m, d $ Operating Day

Real-Time Regulation Deployment Adjustment Amount per MP per Operating Day - The value described under Section 4.5.9.19.

RtOclDistMpAmt m, d $ Operating Day

Real-Time Over Collected Losses Distribution Amount per MP per Operating Day - The value calculated under Section4.5.9.20.

RtNetInadvertentSpp5minAmt i $ Dispatch Interval

Real-Time SPP Inadvertent Energy Amount per Dispatch Interval – SPP net Inadvertent Energy for Dispatch Interval i valued at the Real-Time LMP MEC.

RtNetInadvertentSppAmt spp, d $ Operating Day

Real-Time SPP Inadvertent Energy Amount per Operating Day – The sum of RtNetInadvertentSpp5minAmt i for Operating Day d.

RtCongestionSppAmt spp, d $ Operating Day

Real-Time SPP Net Congestion Revenue Amount – The net amount of total Real-Time congestion revenue collected over Operating Day d.

RtNetActIntrchngSpp5minQty i MW Dispatch Interval

Real-Time SPP Net Actual Interchange per Dispatch Interval – SPP Net Actual Interchange in Dispatch Interval i.

RtNetSchIntrchngSpp5minQty i MW Dispatch Interval

Real-Time SPP Net Scheduled Interchange per Dispatch Interval – SPP Net Scheduled Interchange in Dispatch Interval i.

RtMec5minPrc i $/MW Dispatch Interval

Marginal Energy Component of Real-Time LMP per Dispatch Interval – The Real-Time LMP MEC in Dispatch Interval i.

RtJoaHrlyAmt a, h, f $ Hour Real-Time Joint Operating Agreement Hourly Amount - The value calculated under Section 4.5.9.21.

RtRegNonPerfDistMpAmt m, d $ Operating Day

Real-Time Regulation Non-Performance Distribution Amount - The value calculated under Section 4.5.9.16.

RtCRDeplFailDistMpAmt m, d

$ Operating

Day Real-Time Contingency Reserve Deployment Failure Distribution Amount - The value calculated under Section 4.5.9.18.

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Variable

Unit

Settlement Interval

Definition

RtRegUpDistMpAmt m, d $ Operating Day

Real-Time Regulation-Up Service Distribution Amount – The value calculated under Section 4.5.9.11.

RtRegDnDistMpAmt m, d $ Operating Day

Real-Time Regulation-Down Service Distribution Amount – The value calculated under Section 4.5.9.12.

RtSpinDistMpAmt m, d $ Operating Day

Real-Time Spinning Reserve Distribution Amount – The value calculated under Section 4.5.9.13.

RtSuppDistMpAmt m, d $ Operating Day

Real-Time Supplemental Reserve Distribution Amount – The value calculated under Section 4.5.9.14.

RtRsgDistMpAmt m, d $ Operating Day

Real-Time Reserve Sharing Group Distribution Amount – The amount calculated under Section 4.5.9.23.

RtDRMpAmt m, d $ Operating Day

Real-Time Demand Reduction Amount per Market Participant per Operating Day – The amount calculated under Section 4.5.9.24.

RtDRDistMpAmt m, d $ Operating Day

Real-Time Demand Reduction Distribution Amount per Market Participant per Operating Day – The amount calculated under Section 4.5.9.25.

RtRsgDlyAmt a, d $ Operating Day

Real-Time Reserve Sharing Group Amount – The amount calculated under Section 4.5.9.22.

MiscDlyAmt a, c, d $ Operating Day

Real-Time Miscellaneous Amount per AO per Charge Type per Operating Day – The miscellaneous amount to AO a for charge type c in Operating Day d as described under Section 4.5.10.4.

RtRnuDlyAmt a, s, d $ Operating Day

Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Operating Day– The amount for revenue neutrality to AO a at Settlement Location s in Operating Day d.

RtRnuAoAmt a, m, d $ Operating Day

Real-Time Revenue Neutrality Uplift Amount per AO per Operating Day – The amount for revenue neutrality to AO a associated with Market Participant m in Operating Day d.

RtRnuMaxDlyAmt spp, d $ Operating Day

Real-Time Revenue Neutrality Uplift Maximum Daily Amount – The Maximum Real-Time Revenue Neutrality Uplift allocated to any AO in Operating Day d.

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Variable

Unit

Settlement Interval

Definition

RtRnuMaxAoDlyAmt a, m, d $ Operating Day

Real-Time Revenue Neutrality Uplift Maximum Asset Owner Daily Amount – Any Asset Owner who was allocated Revenue Neutrality Uplift equal to the RtRnuMaxDlyAmt in Operating Day d.

RtRnuMaxAoDlyFlg a, m, d None Operating Day

Real-Time Revenue Neutrality Uplift Maximum Asset Owner Daily Flag – The first Asset Owner who was allocated Revenue Neutrality Uplift equal to the RtRnuMaxDlyAmt in alphabetic order by AO in Operating Day d.

RtRnuMpAmt m, d $ Operating Day

Real-Time Revenue Neutrality Uplift Amount per MP per Operating Day – The amount for revenue neutrality to MP m in Operating Day d.

RtPseudoTieCongSppAmt d $ Dispatch Interval

Real-Time SPP Total Pseudo-Tie Congestion Amount per Dispatch Interval - The total amount for congestion on Pseudo-Ties for the Operating Day.

RtPseudoTieLossMpAmt m, d $ Operating Day

Real-Time Pseudo-Tie Losses Amount per Asset Owner per Operating Day - The amount for Pseudo-Tie losses on all paths for MP m for the Operating Day.

RtPseudoTieCongMpAmt m, d $ Operating Day

Real-Time Pseudo-Tie Congestion Amount per Market Participant per Operating Day - The value described under 4.5.9. 26 for MP m for the Operating Day.

GFARevInadqcSppAmt spp, d $ Operating Day

Grandfathered Agreement Carve-Out Revenue Inadequacy Daily Amount – The amount of charges and credits to GFA Carve-Out responsible entities on an SPP-wide basis from the settlement of Day-Ahead Asset & Non-Asset Energy, Day-Ahead Over-Collected Losses Distribution, Transmission Congestion Rights Funding & Uplift, Transmission Congestion Rights Auction and Auction Revenue Rights & Uplift amount for Operating Day d.

DaGFACarveOutDistMpDlyAmt m, d $ Operating Day

Day Ahead GFA Carve Out Distribution Daily Amount per MP per Operating Day – The value calculated under Section 4.5.8.26.

DaGFACarveOutDistMpMnthlyAmt m,

mn $ Month Day-Ahead GFA Carve Out Distribution Amount per MP per

Month – The value calculated under Section 4.5.8.27.

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Variable

Unit

Settlement Interval

Definition

DaGFACarveOutDistMpYrlyAmt m, yr $ Year Day-Ahead GFA Carve Out Distribution Amount per MP per Year – The value calculated under Section 4.5.8.28.

GFARevInadqcSppMnthlyAmt spp, mn $ Month Grandfather Agreement Carve-Out Revenue Inadequacy Monthly Amount – The value calculated under Section 4.5.8.27.

GFARevInadqcSppYrlyAmt spp, yr $ Year Grandfather Agreement Carve-Out Revenue Inadequacy Yearly Amount – The value calculated under Section 4.5.8.28.

A none none An Asset Owner. S none none A Resource Settlement Location. h none none An Hour. i none none A Dispatch Interval. t none none A single tagged Interchange Transaction, a single virtual energy

transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction.

f none none A flowgate identified in the applicable JOA. d none none An Operating Day. rnu none none A flag which instructs the settlement system to include the amount

in Revenue Neutrality Uplift calculations (1 = Y, 0 = N). m none none A Market Participant.

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SPP Tariff (OATT)

Attachment AE

8.8 Revenue Neutrality Uplift Distribution Amount

The Transmission Provider shall perform the following calculation for each hour of the Operating

Day for each Asset Owner and Settlement Location to ensure that the Transmission Provider is revenue

neutral in each hour of the Operating Day. The Transmission Provider shall calculate hourly summations

to each Market Participant for all Asset Owners it represents and shall calculate daily summations as

specified in the Market Protocols. The calculations below can result in residual amounts due to rounding.

The Transmission Provider will sum up those residual amounts per Operating Day on an annual basis and

will uplift the annual residual amounts to all ofand allocate it to the Market Participant with the Asset

Owners Owner who has the largest daily summation for the Operating Day as specified in the Market

Protocols.

Revenue Neutrality Uplift Distribution Amount =

Daily RNU Distribution Rate * RNU Distribution Volume * (-1)

(1) The Daily RNU Distribution Rate is equal to the Daily RNU Distribution Amount divided by the

Daily RNU Distribution Volume.

(a) The Daily RNU Distribution Amount is equal to:

(i) The sum of all Asset Owners’ charges and payments calculated under Section 8.5,

excluding payments under Sections 8.5.13, 8.5.14 and 8.5.15, for the Operating

Day; plus

(ii) The sum of all Asset Owners’ charges and payments calculated under Section 8.6

for the Operating Day; plus

(iii) The sum of all Asset Owners’ charges and payments calculated under Section 8.7,

excluding payments under Sections 8.7.4, 8.7.5 and 8.7.6; plus

(iv) The sum of all charges and payments for emergency purchases and sales entered

into by the Transmission Provider in its Balancing Authority role in order to

alleviate a capacity shortage inside the SPP Balancing Authority Area or to assist

an external Balancing Authority in alleviating a capacity shortage; plus

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(v) Any other charges and credits not accounted for in subsections (i) through (iv)

above; minus

(vi) The Excess Congestion Fund Daily Amount calculated under Section 8.5.13(3)(a)

for the Operating Day; minusplus

(vii) The Excess Congestion Fund Yearly Amount calculated under Section 8.5.14(3)

for the year corresponding with the annual TCR auction; minus

(viii) The Excess TCR Revenue Fund Daily Amount calculated under Section 8.7.4(3)(a)

for the Operating Day; plus

(iv) The Excess TCR Revenue Fund Yearly Amount calculated under Section 8.7.5(3)

for the Operating Day.

(b) The Daily RNU Distribution Volume is equal to the sum of all Asset Owners’ RNU

Distribution Volumes for the Operating Day.

(2) An Asset Owner’s RNU Distribution Volume at a Settlement Location for an hour is equal to the

sum of:

(a) The absolute value of actual metered generation or load in the hour; and

(b) The absolute value of scheduled Interchange Transactions in the hour; and

(c) The absolute value of cleared Virtual Energy Offers and Bids in the hour.

2016-2017 ARR Holders % Hedged (Correction)

Market Working Group (MWG)

February 6-7, 2018

Debbie James

[email protected]

Reason for Correction• Staff presented 2016-2017 congestion hedging %

graphs at the August 2017 MWG meeting

• Staff recently discovered an error in the graphs ARR holders that received Day-Ahead Market congestion

payments instead of charges should be shown as having no exposure instead of a hedge %

• Also included SPP GFA Carveout ARR holder in the corrected version 52 ARR holders instead of 51 GFA ARR holder included in over 100%

• 20 no exposures vs. 6 no exposures previously Under 70% - 9 Over 70% - 1 Over 100% - 4

2

ARR Holder Changes

Note: GFA Carveout ARR Holder increases the “over 100%” new category to 19

3

ARR Holder Category New Old Difference

Over 100% 18 22 -4

No Exposure 20 6 +14

Over 70% 3 5 -2

Under 70% 10 18 -8

Total ARR Holders 51 51 0

2016-2017 ARR Holders % Hedged (Old)

4

2016-2017 Congestion Hedging % by ARR Holders (Old)

5

2016-2017 ARR Holders % Hedged (New)

6

2016 Congestion Hedging % by ARR Holders (New)

7

Integrated Marketplace Congestion Hedging Training Non-SPP member users may establish accounts in the SPP Learning Center by clicking here and then selecting non-member registration on the right hand side of the screen.

As a non-member, reliability training courses will incur costs, and you will not get a course unless the payment is processed. However, most of the Marketplace training (there are a few exceptions) is offered at no cost to non-members.

SPP Learning Center

Integrated Marketplace TCR Basics series1) Understanding Congestion

This is module 1 of 4 in the Integrated Marketplace TCR Basics series. In this module you will:Identify the instrument used to hedge against congestion in the Integrated Marketplace

2) Transmission Congestion Rights (TCR) OverviewTraining Type:

Online Class

Provider: SPP Customer Training Version: 1.0 Training Hours:

0 Hours 16 Min

Description: This is module 2 of 4 in the Integrated Marketplace TCR Basics series. In this module you will:

• Define Transmission Congestion Rights• Identify which component of the LMP is used to calculate the financial impact of aTCR• Identify the 5 characteristics of TCRs• List the three methods Market Participants may utilize to obtain TCRs• Identify the circumstances causing TCRs to be a benefit or liability• Recall and apply the formula used to calculate a TCR's value• Recall and apply the formula used to calculate a TCR Credit• Recall and apply the formula used to calculate a TCR Congestion Charge• List three possible congestion hedging types and outcomes• Given a scenario, determine whether a TCR is a benefit or liability

1

https://spp.csod.com/client/spp/default2.aspx

https://spp.csod.com/ui/lms-learner-home/home?tab_page_id=-200300006&tab_id=-2

• Given a scenario, determine the Hedging type of a TCR• Given a scenario, determine an MP's net total cost of congestion

3) Auction Revenue Rights (ARR) OverviewTraining Type:

Online Class


0 Hours 15 Min

Description: This is module 3 of 4 in the Integrated Marketplace TCR Basics series. In this module you will:

• Define Auction Revenue Rights• Identify how ARRs are allocated• Identify the four characteristics of ARRs• List the options available to holders of CANDIDATE ARRs• Identify the two options available to holders of ARRs• Identify how ARR values are calculated• Given a scenario, calculate an ARR daily value and a TCR daily value; then use thosevalues to determine an MP's net total cost

4) Tying It All Together: ARRs and TCRsTraining Type:

Online Class


0 Hours 7 Min

Description: This is module 4 of 4 in the Integrated Marketplace TCR Basics series.

(To provide the necessary background information for this topic, it is recommended to view the other three modules in this series prior to this one. They are: Understanding Congestion, ARR Overview, and TCR Overview.)

The Tying It All Together module will discuss aspects for MPs to consider when participating in the TCR Market. Congestion costs, the value of TCRs owned, the cost of TCRS and ARRs held will all be considered. Examples will also be provided in this module.

2

Long-Term Congestion Rights (LTCR) Overview Long-Term Congestion Rights (LTCR) Overview Training Type:

Online Class


0 Hours 15 Min

Description: What is a Long-Term Congestion Right, or LTCR? An LTCR is a financial instrument, similar to a Transmission Congestion Right, or TCR, that allows load serving entities (LSEs) and then non-LSEs to hedge long-term power supply arrangements for more than one year. The LTCR Overview course will discuss the components of LTCRs and how they are allocated in the TCR Market.

Integrated Marketplace Acquiring TCRs series 1) Acquiring TCRs in the Annual TCR Auction

Training Type:

Online Class


0 Hours 44 Min

Description: This is module 1 of 3 in the Integrated Marketplace Acquiring TCRs series. In this module you will: • Identify the three sets of activities that comprise the TCR Annual Auction • Identify the month in which the Annual TCR Auction occurs • Identify the month in which Market Participants must submit ARR nominations • Identify the purpose and types of Transmission Service Verification • List the three characteristics that define a Candidate ARR • Identify how Candidate ARRs are aggregated within the Annual TCR Process • Identify the two types of Nomination Caps • Identify the information necessary for nominating ARRs • Identify the purpose of the Simultaneous Feasibility Test • List the characteristics required in a TCR Bid Submittal • Identify the available Grid Capacity percentage by month and/or season for TCR Auctions • Identify how the awarded MW from Auction Clearing are reduced for an infeasible SFT example

3

2) Acquiring TCRs in the Monthly TCR Auction Training Type:

Online Class


0 Hours 13 Min

Description: This is module 2 of 3 in the Integrated Marketplace Acquiring TCRs series. In this module you will: • Identify when the Monthly TCR Auction is a Single Round Process and when it is a Two Round Process • State the number of days requests for monthly candidate ARRs to be submitted before the start of the TCR Monthly Auction Process • State the number of days Market Participants have to correct OASIS data before the start of the TCR Monthly Auction Process • Identify the processes used to assign monthly candidate ARRs • Identify which rules of the Monthly ARR SFT are similar to those in the Annual SFT process • Identify the purpose for having "TWO ROUND" auctions rather than "ONE ROUND" auctions in the Monthly TCR Auction process • Identify the three bid types used in the bid submittal process of the Monthly TCR Auction

3) Acquiring TCRs in the Secondary Market

Training Type:

Online Class


0 Hours 3 Min

Description: This is module 3 of 3 in the Integrated Marketplace Acquiring TCRs series. In this module you will: • Identify how SPP facilitates the TCR Secondary Market • State the frequency TCRs can be traded on the Secondary Market • Identify who Market Participants contact in order to purchase or sell a TCR • Identify SPP's responsibilities once a TCR has been purchased or sold

4

Virtuals as a Hedging Mechanism Virtuals as a Hedging Mechanism Training Type:

Online Class


0 Hours 12 Min

Description: In this training, you will: • Identify the type of Virtual Transaction a Market Participant should submit in a specific derate example. • Identify how a Virtual Transaction can hedge the Market Participant from a possible derate. • Identify how to use Virtual Transactions to reduce the financial risk exposure caused by a possible capacity loss in a specific example

TCR Settlements TCR Settlements Training Type:

Online Class


0 Hours 12 Min

Description: In the TCR Settlements Module you will: • Identify the purpose of ARR and TCR Auction Settlements • Identify the section of the Daily Settlement Statement which contains the ARR and TCR Auction Charge • Identify the section of the Daily Settlement Statement which contains TCR Market Settlement Charge Types • Identify how ARR and TCR Auction Settlements charges and credits are determined and then applied on the Daily Settlement Statement • Identify the frequency that TCR Auction Settlements are calculated • Explain how ARR Auction Settlements are structured and reconciled daily, monthly and yearly • Identify the components of the TCR Market Settlements Charge Types • Identify the frequency that TCR Market Settlements are calculated • Identify how TCR Market Settlements charges/credits are determined and then applied on the Daily Settlement Statement • Explain how TCR Auction Settlements and TCR Market Settlements charges/credits are structured and reconciled daily, monthly and yearly

5

ARR and TCR Charge Types

ARR and TCR Charge Types Course Description: This self-study course lists the various Auction Revenue Rights (ARR) and Transmission Congestion Rights (TCR) Charge Types. You will learn the purpose of these Charge Types, as well as the high-level formula for each. Objectives:

• Identify the ARR and TCR Charge Type Formulas • Identify the function of TCRs • Identify the components of the ARR and TCR Charge Types

Transmission Congestion Rights (TCR) Process Quick Reference Guide Transmission Congestion Rights (TCR) Process Quick Reference Guide This document details the Market Participant (MP) activities that must be completed for the Annual Long-Term Congestion Rights (LCTR) Allocation, the annual and monthly Auction Revenue Rights (ARR) Allocation, and the annual and monthly Transmission Congestion Rights (TCR) Auction.

Transmission Congestion Rights (TCR) Market User Interface (MUI) Quick Reference Guide Transmission Congestion Rights (TCR) Market User Interface (MUI) Quick Reference Guide This reference guide provides Market Participants with step-by-step instructions to navigate the Transmission Congestion Rights (TCR) Market User Interface (MUI) for the purpose of completing tasks associated with: Initial Incremental Long-Term Congestion Rights (ILTCRs), Long-Term Congestion Rights (LTCR) nominations, Annual Auction Revenue Rights (ARR) Allocations, Annual TCR Auctions, Monthly ARR Allocations, Monthly TCR Auctions, and TCR Secondary Market Activities. (v5.0)

6

of 3

UPDATE: MOPC Action Item 276: ARR/TSR Firm – Inability to Hedge as Expected -

Parties paying for transmission service are not receiving hedge for congestion cost

In February 2017, the Market Working Group (MWG) was tasked by the Strategic Planning

Committee (SPC) with considering options to improve the process of granting hedges for

congestion, taking into consideration the impacts to existing Transmission Service Rights (TSR)

and Transmission Congestion Rights (TCR) processes. MWG and SPP staff discussed a

substantial amount of analysis throughout the year, as evident from the list provided below in

this summary. As a result of these discussions, the MWG has determined the focus moving

forward is best tuned to reviewing and discussing potential improvements to TCR process

clearing methodologies and counterflow practices, in addition to determining any TCR process

training development that may be beneficial to stakeholders. The list of completed analysis and

discussions are itemized below, as well as the path forward for 2018. All MWG action items

taken throughout 2017 related to the below listed analysis and discussion have been closed.

Over the 2017 year, the MWG reviewed and discussed the following:

• Education on “the differences between the TSR and TCR processes” and “Understanding

the Value of Counterflow”

• Congestion hedging percent by Asset Owner for those who requested their individual

data

• Benefits of the implementation of RR91 during the period of October 2016 through May

2017

o Improved funding

• Cumulative TCR percentages for 3 TCR years

• A duration curve of LTCRs and ARRs requested vs. awarded by path for the last 12

months, excluding round 3, from June 2016 to May 2017

• Analytical comparison of ARR/TCR market performance during the 2015/2016 versus

2016/2017 year

• ARR/TCR Feasibility Study to conduct a least cost study to allocate a higher percentage

of Round 1 ARRs to Firm Transmission using two methods to compare cost; 1) Upgrade

Transmission to allocate ARRs in Round 1 and 2) Unfeasibly grant requested ARRs in

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Round 1. The study scope covered June on peak and winter on peak of the 2107-2018

Annual ARR Allocation.

o Study Process Part 1:

1. Determine system limitations that prevent Round 1 ARR requests from

being allocated

2. Identify and model future transmission upgrades that have already

received a notification to construct to mitigate limitations identified in step

1


1. Calculate the uplift cost associated with awarding all or a high percentage

of the requested ARRs in Round 1


1. Identification of additional transmission upgrades needed and associated

costs

• Value of awarding ARRs in Round 1 of the 2016/2017 TCR year at a 100%, 50%, and

75%

• Identification of Resources that would be available/unavailable for nomination in Round

1 of the ARR process based on a capacity factor breakpoint of 40% and 50% and how the

breakpoints apply to the ARR allocation process

• Total MWs of available candidate ARRs considering the MPs’ nomination caps are based

on their individual capacity factors

• Original total MWs of nominations for the 2017-2018 annual round 1 ARR Allocation

The MWG will focus on the following during the February meeting:

• Eliminating Impact of <3% Impacts from ARR Clearing

• Changing Clearing Methodology to Match TSR Assessment (if proration is based on

impacts)

• Requiring Counterflow Nominations

• TCR related training needs beyond what is offered in SPP’s Learning Management

System

of 3

Respectfully Submitted – Erin Cathey, MWG Staff Secretary

SPP NDVER TO DVER CONVERSION ANALYSIS

February 2018 Report to MWG

Published on 2/6/2018

By Operations Analysis & Support/Market Design

Southwest Power Pool, Inc.

CONTENTS

Section 1: Introduction .......................................................................................................................................................... 1

Subsection A: Purpose, Benefits and Background .................................................................................... 1

Section 2: Wind, Hydro, & Solar Resource Statistics ................................................................................................. 4

Subsection A: Wind-Powered Generator Resource Statictics .................................................................. 4

Subsection B: Hydro-Powered Generator Resource Statistics ................................................................. 4

Subsection C: Solar-Powered Generator Resource Statistics ................................................................... 4

Section 3: NDVERs Price Following ................................................................................................................................. 5

Section 4: Individual NDVER Resource Conversion – Financial Analysis ........................................................ 9

Section 5: Wind-powered DVER Type I and II Operational Option .................................................................. 14

Subsection A: Type I and II Interim Proposal .......................................................................................... 14


1

SECTION 1: INTRODUCTION

SUBSECTION A: PURPOSE, BENEFITS AND BACKGROUND

SPP proposes via RR272 (NDVER to DVER Conversion) to require that, after a two year transition

period, all Variable Energy Resources registered as Non-Dispatchable Variable Energy Resources

(NDVERs) be required to register as Dispatchable Variable Energy Resources (DVERs) unless they are a

Qualified Facility (QF) exercising their rights under the Public Utility Regulatory Policies Act of 1978

(PURPA).

NDVERs in Southwest Power Pool’s (SPP’s) market create market inefficiencies and reliability risks that

SPP resources and systems must mitigated.

1) Market Efficiency: Collections of NDVERs are generally located in the same region, however it

is often necessary to redispatch many Resources (DVERs and others with potentially lower shift

factors) around them in order to solve constraints, leading to higher congestion costs for the

market. Additionally, SPP has observed NDVERs reacting to Locational Marginal Price (LMP)

signals - dropping offline when the LMP drops and responding to increased LMPs by generating

at the same prior output; although by definition, NDVERs are not capable of being incrementally

dispatched by the Transmission Provider. When this price-following behavior from NDVERs

occurs, the subsequent market redispatch and pricing are inefficient, due to the assumption that

NDVERs are not capable of dispatching and reacting to price. Additionally, SPP may issue an

Out-of-Merit Energy (OOME) to NDVERs today. However, the issuance of an OOME is less

precise than the systematic redispatch provided by the market when resources are

dispatchable. This imprecision results in either too much or too little redispatch being provided

requiring other market and reliability mechanisms to make up the difference.

2) Reliability: The price-following behavior of NDVERs also present reliability and operational

challenges when NDVERs suddenly drop offline and then return to follow an increase in LMP as

more relief may be realized than was requested by the Security Constrained Economic Dispatch

(SCED) solution; SCED is unable to effectively clear energy and cover regulation when

NDVERs behave in this manner. This behavior results in the SPP Balancing Authority (BA)

having to manually manage the additional lost output with regulation, putting the Reliability

Coordinator in a position to possibly issue an OOME to the NDVERs who are responding to

LMP changes in order to mitigate flowgates becoming unstable from the unexpected oscillations

caused by NDVERs that follow price. Additionally, NDVERs make up a large majority of the


2

Resources to which OOMEs are issued. The need to issue an OOME inherently represents an

actual reliability issue that has risen to the attention of the Reliability Coordinator (RC) and

requires the RC to take action to maintain reliability. Although these reliability issues are

manageable, converting NDVERs to DVERs would help to alleviate these reliability risks.

In the 2015 ASOM Report, the SPP Market Monitoring Unit (MMU) stated their concern with NDVERs

due to their adverse impact on market prices. The SPP MMU stated that when prices are depressed in

high wind production regions, NDVERs have an adverse impact on prices in two ways. Some resources

chase price, ignoring the system dispatch and self dispatching to a lower level in an attempt to avoid the

cost associated with producing when prices are very low. This behavior at times causes unexpected

volatility on the system and distorts market prices. The alternative behavior is for these NDVER units to

continue to produce as expected even when prices are below what would be an appropriate market

clearing price. Both cases result in sub-optimal market results. The SPP MMU recommended SPP

transition NDVER Resources to DVER status to lessen the negative impact of such resources on the

market. Work to respond the MMU’s recommendation has been tracked via both the Markets and

Operations Policy Committee (MOPC) and the Market Working Group (MWG) action items.

Benefits of NDVERs converting to DVERs include, but are not limited to:

Increased reliability realized through collective dispatchable Resources mitigating multiple

constraints simultaneously

Increases reliability and economic efficiency through reduction of manual Out-of-Merit Energy

(OOME) instructions

Reduction of price volatility (reliability and economic benefit)

Having more VERs be controllable by the market and not subject only to variable fuel and external

control behaviors leads to less pricing uncertainty as a result of:

Reduction of ramp scarcity events by having NDVERs controllable within SCED

Further optimization of quick start Resource needs by having a larger set of Resources that

are under SCED control

Increased pricing convergence between Day-Ahead and Real-Time due to larger set of

controllable Resources in Real-Time

Further potential optimization of Operating Reserves with potentially more VERs

participating in the offering of certain ancillary services. If they convert, they will be

controllable and may qualify for Regulation-Down

Increased reliability by reducing NDVER generation oscillation


3

Market efficiencies are gained by adding dispatchable generation to resolve congestion in the

load pocket, rather than redispatching less effective generation to protect the NDVER output;

this has the potential to reduce the congestion costs from less effective generation redispatch


4

SECTION 2: WIND, HYDRO, & SOLAR RESOURCE STATISTICS

SUBSECTION A: WIND-POWERED GENERATOR RESOURCE STATICTICS Total current wind-powered VER capacity – ~17.6GW

Additional 600MW on SPP lines Pseudo-tied out not registered in SPP’s market Wind VER Breakdown

Total DVER – ~11.2 GW Total NDVER – ~6.430 GW

NDVER breakdown by wind turbine type: Type III and IV wind turbine – ~5.564 GW

Type I and II wind turbine – ~.866GW Total NDVER QFs exercising their rights under PURPA – ~1.016GW

NDVER Type I and Type II QFs - ~.039GW

NDVER Type III and Type IV QFs –.977GW

Total DVER QFs total .049GW ~78% of Total NDVERs have some amount of Firm PTP/Firm NITS

~ 43% of Type I and Type II have 100 % Firm PTP/Firm NITS Total future wind-powered DVER capacity – ~37GW in the queue

SPP expects ~2.5GW of this to be in service by the end of 2020

SUBSECTION B: HYDRO-POWERED GENERATOR RESOURCE STATISTICS Total current Hydro capacity – ~3.4GW

Hydro DVER – ~0GW Hydro NDVER – ~1.4GW Hydro PLT/GEN – ~ 2GW

SUBSECTION C: SOLAR-POWERED GENERATOR RESOURCE STATISTICS Total current Solar-Powered VER capacity – ~.215GW

Solar DVER – ~.14GW Solar NDVER – ~.075GW

Total future Solar-Powered DVER capacity – ~8GW


5

SECTION 3: NDVERS PRICE FOLLOWING

Real-time price-following behavior from NDVERs creates economic inefficiencies and contributes to reliability issues.

Reliability Impacts The most notable impacts to reliability are the sharp changes observed on transmission constraints when NDVERs follow pricing after the SCED dispatch has already been determined. These impacts are not just isolated to the local transmission constraints around the NDVER – they can also have an impact on the redispatch needed to resolve transmission constraints further away as the sharp changes in flows require more redispatch in the RTBM. Outside of the transmission impacts, there are also additional needs for regulation to help maintain control of the SPP BA’s ACE when the NDVERs deviate from expected output much more than standard forecast error. Some examples include

1. Impact to local transmission constraints – As shown in the example charts in the following pages, NDVERs near a flowgate can cause large swings on the transmission constraint which can push the constraint loading over its System Operating Limit (SOL). This often requires remedial action to be taken by operators to either manually redispatch resources (via OOME) of lower the effective limit of a constraint in the RTBM to provide an adequate margin to prevent future SOL exceedances.

2. Additional regulating reserves – Regulating reserves may also need to be deployed to maintain proper control of ACE in the SPP BA, due to the large deviation from expected dispatch for price-following NDVERs. These deviations are typically much larger than standard forecast/persistence error for the RTBM dispatch of NDVERs that are not following prices.

3. Impact to redispatch and control of other transmission constraints – Sharp changes in NDVER output can cause the RTBM SCED to redispatch many resources to provide relief on the transmission constraint. These other resources may also be needed to manage other transmission constraints closer to them, and in times of large swings on the constraint near a price-following NDVER, the SCED may have to solve one constraint at the expense of violating the other constraint due to the relief needed to offset the sharp change in impact from the non-dispatchable resource.

Economic inefficiencies The economic impacts of price-following can also be substantial, ranging from inefficient RTBM dispatch and commitments to extreme price separation and divergences from Day Ahead Market results. Many of the issues stem from the NDVER responding to a real-time price after the dispatch/commitment decisions have already been made.

1. Inefficient dispatch – Since NDVERs are not considered dispatchable by the RTBM SCED, when redispatch is required for a constraint the SCED will use other resources to provide this relief. If the NDVER follows price and moves at the same time as the resources being moved by RTBM, there ends up being more relief provided than necessary, where the SCED could have provide a more optimum solution if the NDVER was allowed to be dispatched.

2. Inefficient commitments – NDVERs are treated as fixed (price takers) at the forecast MW in the RUC studies, so any transmission constraints that NDVERs could be contributing to could also require unit commitments to manage since dispatchable relief cannot be received from the


6

NDVERs. When the NDVER follows the prices in real-time, it can provide relief on the transmission constraint, which lowers the congestion and lowers the LMPs at the committed resource and makes it uneconomic – in some cases so uneconomic that it was not necessary to be committed. This is similar to the redispatch problem, but instead of getting unnecessary relief from a redispatch, in this case there is unnecessary relief acquired from the commitment of another resource when the more efficient solution would have been to drop output on the NDVER if it was dispatchable. This would ultimately turn into a make-whole payment as the commitment was made from the RUC process but real-time LMPs were not high enough to cover the costs of the resources due to the relief suddenly provided by the NDVER in real-time.

3. Extreme price separation – Sharp swings in constraint loading can cause large ramping requirements for RTBM to meet the relief necessary to bring flowgates under control. This would cause heavy price separation as resources from far away are needed to provide the relief. If there are competing constraints for those same dispatchable resources, those other constraints will see higher shadow prices and drive LMPs apart in those locations as well. In addition to the extreme price separate seen in real-time, these events can also cause price separation across markets (RTBM to Day Ahead), where the sharp changes in real-time are not present in the Day Ahead Market.


7

Price Following Volatility Example

The example below shows a flowgate loading and an NDVER that is following price. This price-following causes large swings on the transmission system and contributes to the flowgate moving from an unloaded to a loaded state. Additionally, a nearby DVER is being dispatched by RTBM at the same time to resolve the constraint. When we get to real-time both the DVER (following its dispatch set by RTBM) and the NDVER (following the RTBM price) move at the same time. This causes the flowgate loading to drop off sharply. The next RTBM solution begins to reload the DVER (with the assumption that the NDVER will not change significantly), but instead the NDVER ramps up at the same time now that prices have increased. This causes overshoot on the flowgate loading and can contribute to SOL exceedances.


8

Price Following Volatility Example (continued)

With a further illustration of a similar situation, the chart below shows the smooth control of the transmission constraint during the middle portion of the graph when only the DVER is moving due to RTBM dispatch. Once the NDVER begins following price around the 18:00 time, the flowgate loading begins to swing again and the constraint exceeds its SOL on several occasions.


9

SECTION 4: INDIVIDUAL NDVER RESOURCE CONVERSION – FINANCIAL ANALYSIS

SPP reran market studies to provide and estimated impact of a single NDVER to DVER conversion. While this analysis will almost invariably show some benefit regardless of the NDVER selection, this only shows one side of the equation and this market analysis is not intended to represent all costs to the resource. SPP only has access to its market and operational information and the offer data provided by the market participant and cannot provide an accurate estimate of the costs, as those costs can vary greatly across resources and requires specific knowledge about the resource.

The selected NDVER was based on a request from a member and was not hand-picked to provide the largest benefit assumption. The analysis is provided here because it has already been completed and SPP believes it not to be an extreme case. However, due to the confidential nature of some of the information, not all of the specifics can be shared, such as resource name, offer prices, nearby transmission constraints, etc. It is important to understand when reviewing the results that this analysis does not claim that the specific resource here is exactly representative of all NDVERs nor that it would represent the full impact if multiple NDVERs were to convert to DVER at the same time. Any costs, benefits, prices, or uneconomic intervals in this example are not intended to apply to all other resources. In terms of total uneconomic intervals experienced for the assumed study period (October 2016 – October 2017), this NDVER was actually on the low end (#85 of 133) of NDVERs.

In terms of a percentage of total energy production for the same time period, the resource was positioned in roughly the same spot relative to other NDVERs (#82 of 133 – first chart below). When using pure energy production (second chart below), the resource ranked higher (#33 of 133).


10

Looking at the entire NDVER fleet shows that 10% of energy is generated uneconomically (LMP lower than marginal offer price), which translates to an average of 311.6 MW at any given time.

10/15/16 – 10/14/17 NDVER ENERGY

ANNUAL MWHR

AVERAGE MW

Total Energy 25,650,353.5 2,928.1

Uneconomic Energy 2,729,401.1 311.6

% of Total is Uneconomic

10.64% 10.64%

The study was performed using historical market cases to

• Evaluate the effect of treating a single NDVER as a DVER in the Market System

• More importantly to estimate the benefit for the resource if it were treated as a DVER


11

This study used historical RTBM data for two time periods (August and October 2017) to show impacts across peak and off-peak times of the year. The studies were run with the assumption that the NDVER would be converted to DVER, and an additional sensitivity was run varying the ramp rate. The selected resource was not participating in Ancillary Service clearing (DVERs can currently only participate in Regulation Down clearing). Ranges for the analysis were

• A period of time (8/1-8/31) when the LMP was greater than the Marginal Cost. This period would be expected to show the least total benefits due to higher LMPs during the summer months.

• A period of time (10/1-10/14) when the LMP was less than the Marginal Cost. . This period would be expected to show the most total benefits due to lower LMPs during the shoulder months.

For the studied time periods, the benefits were quantified as the difference in resource revenue received from Dispatch times LMP (divided by 12 to account for 5-minute interval length of RTBM). While many days and intervals were analyzed, benefits were only calculated for as the difference in revenues for intervals where the resource LMP was less than the resource marginal offer price.

The three scenarios studied during the above time range were

• Baseline – The resource stays as NDVER and the studies are re-run using the simulated dispatch • DVER – The resource is converted to DVER and participates in energy dispatch during the

simulation using a 1 MW/min ramp rate • DVER +8 – The resource is converted to DVER and participates in energy dispatch during the

simulation using an 8 MW/min ramp rate

A baseline scenario was needed (that was a simulation as well) to provide the basis for the calculations and remove the impact of any potential differences between historical results and the simulation. The total number of intervals analyzed were over 10,000 across the two study periods and all scenarios were run through the same intervals.

Baseline DVER DVER+8

August 7,775 7,775 7,775 October 3,166 3,166 3,166

Total Count 10,941 10,941 10,941


12

Savings for the simulations during intervals where the resource LMP was less than the resource marginal offer price were $17.82 per interval in the DVER scenario (relative to the Baseline) and $21.64 per interval in the DVER+8 scenario (relative to the Baseline). This difference between scenarios (higher benefits with higher ramp rates) is expected because the converted DVER would be allowed to be curtailed faster when uneconomic and reloaded faster when economic if the DVER had a higher ramp rate.

DVER

Intervals (LMP<MP)

Total Savings($)

Average Savings($) per Interval

August 16 $404.62 $25.29

October 615 $10,836.98 $17.62

Total 631 $11,241.60 $17.82

DVER+8

Intervals (LMP<MP)

Total Savings($)

Average Savings($) per Interval

August 16 $692.48 $43.28

October 615 $12,961.04 $21.07

Total 631 $13,653.52 $21.64

These savings were extrapolated for the entire year, based on the number of intervals in historical months where the same NDVER’s LMP was below the marginal offer price in RTBM. The annual savings ranged from $94k to $115k.

DVER DVER+8

Month Count LMP <

MC Savings($)/ Interval Savings Savings($)/

Interval Savings

2016-10 166 17.82 2,957.38 21.64 3,591.89

2016-11 243 17.82 4,329.17 21.64 5,258.01

2016-12 350 17.82 6,235.44 21.64 7,573.27

2017-01 188 17.82 3,349.32 21.64 4,067.93

2017-02 346 17.82 6,164.17 21.64 7,486.72

2017-03 978 17.82 17,423.59 21.64 21,161.87


13

2017-04 567 17.82 10,101.41 21.64 12,268.69

2017-05 1055 17.82 18,795.39 21.64 22,827.99

2017-06 368 17.82 6,556.12 21.64 7,962.75

2017-07 9 17.82 160.34 21.64 194.74

2017-08 44 17.82 783.88 21.64 952.07

2017-09 380 17.82 6,769.90 21.64 8,222.41

2017-10 622 17.82 11,081.26 21.64 13,458.78

Yearly Benefit 5,316 $94,707.36 $115,027.12

Market Inception 16,664 $296,878.01 $360,574.10

For additional reference, here are the averages for change in dispatch and change in LMP over the intervals the benefit calculations were derived from.

DVER

Intervals Avg Change in Dispatch

Average Change in LMP

August 16 -4.044 $5.33

October 615 -1.029 $14.44

Total 631 -1.106 $14.21

DVER+8

Intervals Avg Change

in Dispatch Average Change in

LMP

August 16 -26.381 $6.58

October 615 -6.783 $14.59

Total 631 -7.280 $14.39


14

SECTION 5: WIND-POWERED DVER TYPE I AND II OPERATIONAL OPTION

SUBSECTION A: TYPE I AND II INTERIM PROPOSAL

Type I and II wind turbines may not be able to follow a five-minute Setpoint instruction without a large capital investment and communication and control overhaul. This subsection helps describe that a wind NDVER with physical Type I or II turbines may reregister as a DVER, and leverage existing market offer optionality as an alternative.

Note: The Southwest Power Pool Reliability Coordinator (RC) recommends that all Resources follow Setpoint Instructions as indicated by the Real-Time Balancing Market (RTBM) Security Constrained Economic Dispatch (SCED) engine. These signals are used to maximize efficiency, while maintaining reliability of the bulk electric system. If there are legitimate reasons any Resource may not follow the Setpoint Instructions, the Resource, inclusive of run-of-river hydroelectric and Type I and II wind turbines, may elect to submit a Control Mode Status 3, which will allow the RTBM study to echo the Resource’s SCADA. It is strongly recommended that Control Mode Status 3 be leveraged only when that Resource does not have the ability to follow the market offer-based SCED instruction.

Proposal:

• Use offer curve of blocked - this means all MWs between the blocks are priced the same.

• Submit a Ramp Rate profile that equals each block of offer curve

• Except in periods where the Resource is marginal, this allows for dispatch down to be based on

logical groupings of turbines that are either on or off

• Note that this option is available to any NDVER today

Pros

• Defacto block dispatch for a VER

• Allows dispatch possibility without hardware/software upgrades

Cons

• If marginal, dispatch could be between the blocks

o Uninstructed Resource Deviation (URD) exposure can be mitigated by block size

• Operationally, if between blocks, SPP is sending signal that the Resource might not meet


15

o Based on block size, this is better than any current NDVER, where there is no

dispatchability at all

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RR #: 272 Date: 1/16/2018

RR Title: NDVER to DVER Conversion System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes


Name: Erin Cathey on behalf of SPP Company: Southwest Power Pool












Correction

Clarification

Design Enhancement






If yes, provided details to explain the risk and timelines associated: See the RR Description



Financial SPP Documents Requiring Revision: Please select your primary intended document(s) as well as all others known that could be impacted by the requested revision (e.g. a change to a protocol that would necessitate a criteria or business practice revision).

Market Protocols Section(s): 1, 6.1.8, 6.1.9 Protocol Version: 54a Operating Criteria Section(s): Criteria Date: Planning Criteria Section(s): Criteria Date:

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Tariff (OATT) Section(s): 1.1, 2.2 Business Practice Business Practice Number:


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SPP proposes in this revision request to require that, after a two year transition period, all Variable Energy Resources registered as Non-Dispatchable Variable Energy Resources be required to register as Dispatchable Variable Energy Resources unless they are a Qualified Facility exercising their rights under the Public Utility Regulatory Policies Act of 1978 (PURPA).

Non-Dispatchable Variable Energy Resources in SPP’s market create market inefficiencies and reliability risks that SPP resources and systems must mitigated.

1) Market Efficiency: Collections of NDVERs are generally located in the same region, however it is often necessary to redispatch many Resources (DVERs and others with potentially lower shift factors) around them in order to solve constraints, leading to higher congestion costs for the market. Additionally, SPP has observed NDVERs reacting to LMP signals - dropping offline when the LMP drops and responding to increased LMPs by generating at the same prior output; although by definition, NDVERs are not capable of being incrementally dispatched by the Transmission Provider. When this price-following behavior from NDVERs occurs, the subsequent market redispatch and pricing are inefficient, due to the assumption that NDVERs are not capable of dispatching and reacting to price. Additionally, SPP may OOME NDVERs today. However, the issuance of an OOME is less precise than the systematic redispatch provided by the market when resources are dispatchable. This imprecision results in either too much or too little redispatch being provided requiring other market and reliability mechanisms to make up the difference.

2) Reliability: The price-following behavior of NDVERs also present reliability and operational challenges when NDVERs suddenly drop offline and then return to follow an increase in LMP as more relief may be realized than was requested by the SCED solution; SCED is unable to effectively clear energy and cover regulation when NDVERs behave in this manner. This behavior results in the SPP BA having to manually manage the additional lost output with regulation, putting the Reliability Coordinator in a position to possibly issue an OOME to the NDVERs who are responding to LMP changes in order to mitigate flowgates becoming unstable from the unexpected oscillations caused by NDVERs that follow price. Additionally, NDVERs make up a large majority of the Resources to which OOMEs are issued. The need to issue an OOME inherently represents an actual reliability issue that has risen to the attention of the RC and requires the RC to take action to maintain reliability. Although these reliability issues are manageable, converting NDVERs to DVERs would remove the associated reliability risks.

In the 2015 ASOM Report, the SPP MMU stated their concern with Non-Dispatchable Variable Energy Resources due to their adverse impact on market prices. The SPP MMU stated that when prices are depressed in high wind production regions, NDVERs have an adverse impact on prices in two ways. Some resources chase price, ignoring the system dispatch and self dispatching to a lower level in an attempt to avoid the cost associated with producing when prices are very low. This behavior at times causes unexpected volatility on the system and distorts market prices. The alternative behavior is for these NDVER units to continue to produce as expected even when prices are below what would be an appropriate market clearing price. Both cases result in sub-optimal market results. The SPP MMU recommended SPP transition NDVER Resources to DVER status to lessen the negative impact of such resources on the market. Work to respond the MMU’s recommendation has been tracked via both MOPC and MWG action items.


Increased reliability realized through collective dispatchable Resources mitigating multiple constraints simultaneously Increased economic efficiency through reduction of manual Out-of-Merit Energy (OOME) instructions Reduction of price volatility (reliability and economic benefit) Having more VERs be controllable by the market and not subject only to variable fuel and external control behaviors leads to

less pricing uncertainty as a result of: Reduction of ramp scarcity events by having NDVERs controllable within SCED Further optimization of quick start Resource needs by having a larger set of Resources that are under SCED control Increased pricing convergence between Day Ahead and Real-Time due to larger set of controllable Resources in RT Further potential optimization of Operating Reserves with potentially more VERs participating in the offering of

certain ancillary services. If they convert, they will be controllable and may qualify for REG DN Increased reliability by reducing NDVER generation oscillation Market efficiencies are gained by adding dispatchable generation to resolve congestion in the load pocket, rather than

redispatching less effective generation to protect the NDVER output. This has the potential to reduce the congestion costs from less effective generation redispatch

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Market Protocols 1. Glossary

Dispatchable Variable Energy Resource

A Variable Energy Resource that is capable of being incrementally dispatched down by the

Transmission Provider. As defined in Attachment AE of the tariff.

Non-Dispatchable Variable Energy Resource

A Variable Energy Resource that is not capable of being incrementally dispatched down by the

Transmission Provider.As defined in Attachment AE of the tariff.

6.1.8 Dispatchable Variable Energy Resource

All Variable Energy Resources in the market must be registered as a Dispatchable Variable Energy

Resource (DVER) except for (i) Wind Powered Variable Energy Resources with an interconnection

agreement executed on or prior to May 21, 2011 and that commenced Commercial Operation before

October 15, 2012 or (ii) a Qualifying Facility exercising its rights under PURPA to deliver its net output to

its host utility, or (iii) Non-wind Variable Energy Resources registered on or prior to January 1, 2017 and

with an interconnection agreement executed on or prior to January 1, 2017. VERs included in (i) and (iii)

above may register as Dispatchable Variable Energy Resources if they are capable of being incrementally

dispatched by the Transmission Provider. Any other Variable energy Resource previously registered as a

NDVER must re-register as a DVER on or prior to July 1, 2020. A Qualifying Facility exercising its rights

under PURPA to deliver its net output to its host utility may register as a Dispatchable Variable Energy

Resource if it is capable of being incrementally dispatched by the Transmission Provider and will be subject

to the DVER market rules including Uninstructed Resource Deviation Charges.

Any Resource that has previously registered as a Dispatchable Variable Energy Resource shall not

subsequently register as a Non-Dispatchable Variable Energy Resources.

(1) A Dispatchable Variable Energy Resource is eligible to submit Offers for Regulation-Down if that

Resource qualifies to provide Regulation-Down by passing the test described under Section

6.1.11.3.

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(2) A Dispatchable Variable Energy Resource is not eligible to submit Offers for Regulation-Up,

Spinning Reserve or Supplemental Reserve;

(3) Dispatchable Variable Energy Resources are committed and dispatched the same as any other

Resource in the Day-Ahead Market.

(4) For the RUC and RTBM, special commitment and dispatch rules apply as defined under Section

4.2.2.5.5.

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

Section 4.1.2.

6.1.9 Non-Dispatchable Variable Energy Resource

Variable Energy Resources that qualify may register as a Non-Dispatchable Variable Energy Resource.

The Market Participant registering a Non-Dispatchable Variable Energy Resource must provide

documentation to SPP verifying that it meets one or more of the exceptions in Section 6.1.8. Otherwise,

the Resource must be registered as a Dispatchable Variable Energy Resource.Only a Qualifying Facility

exercising its rights under PURPA to deliver its net output to its host utility may register as a Non-

Dispatchable Variable Energy Resource. Any Resource that has previously registered as a Dispatchable

Variable Energy Resource shall not subsequently register as a Non-Dispatchable Variable Energy Resource.

NDVERs are committed and dispatched the same as any other Resource in the Day-Ahead Market. For

the RUC and RTBM, special commitment and dispatch rules apply as defined under Section 4.2.2.5.6.

Non-Dispatchable Variable Energy Resource data submittal requirements are defined in Section 4.1.2in

the SPP Criteria.

SPP Tariff (OATT)

SPP Tariff

1.1 Definitions and Acronyms


A Variable Energy Resource registered in the market that is capable of being incrementally dispatched by

the Transmission Provider.


A Variable Energy Resource registered in the market that is not capable of being incrementally dispatched

by the Transmission Provider.

2.2 Application and Asset Registration

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…

(10) All Variable Energy Resources in the market must be registered as a Dispatchable Variable

Energy Resource (DVER)All Variable Energy Resources must register as a Dispatchable

Variable Energy Resource except for (1) a wind-powered Variable Energy Resource with

an interconnection agreement executed on or prior to May 21, 2011 and that commenced

Commercial Operation before October 15, 2012 or (2) a Qualifying Facility exercising its

rights under PURPA to deliver its net output to its host utility or (3) a non-wind powered

Variable Energy Resource registered on or prior to January 1, 2017 and with an

interconnection agreement executed on or prior to January 1, 2017. Variable Energy

Resources included in (1) and (3) above may register as Dispatchable Variable Energy

Resources if they are capable of being incrementally dispatched by the Transmission

Provider. . Any other Variable Energy Resource previously registered as a NDVER must

re-register as a DVER on or prior to July 1, 2020. A Qualifying Facility exercising its

rights under PURPA to deliver its net output to its host utility may register as a

Dispatchable Variable Energy Resource if it is capable of being incrementally dispatched

by the Transmission Provider and will be subject to the Dispatchable Variable Energy

Resource market rules including Uninstructed Resource Deviation charges. Any Resource

that has previously registered as a Dispatchable Variable Energy Resource shall not

subsequently register as a Non-Dispatchable Variable Energy Resource.

…

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Revision Request Comment Form

RR #: 272 Date: 2/1/2018

RR Title: NDVER to DVER Conversion


Name: Ronald Thompson Jr. Company: NPPD




SPP proposes in this revision request to require that, after a two year transition period, all Variable Energy Resources registered as Non-Dispatchable Variable Energy Resources be required to register as Dispatchable Variable Energy Resources unless they are a Qualified Facility exercising their rights under the Public Utility Regulatory Policies Act of 1978 (PURPA).

Non-Dispatchable Variable Energy Resources in SPP’s market create market inefficiencies and reliability risks that SPP resources and systems must mitigated.

1) Market Efficiency: Collections of NDVERs are generally located in the same region, however it is often necessary to redispatch many Resources (DVERs and others with potentially lower shift factors) around them in order to solve constraints, leading to higher congestion costs for the market. Additionally, SPP has observed NDVERs reacting to LMP signals - dropping offline when the LMP drops and responding to increased LMPs by generating at the same prior output; although by definition, NDVERs are not capable of being incrementally dispatched by the Transmission Provider. When this price-following behavior from NDVERs occurs, the subsequent market redispatch and pricing are inefficient, due to the assumption that NDVERs are not capable of dispatching and reacting to price. Additionally, SPP may OOME NDVERs today. However, the issuance of an OOME is less precise than the systematic redispatch provided by the market when resources are dispatchable. This imprecision results in either too much or too little redispatch being provided requiring other market and reliability mechanisms to make up the difference.

2) Reliability: The price-following behavior of NDVERs also present reliability and operational challenges when NDVERs suddenly drop offline and then return to follow an increase in LMP as more relief may be realized than was requested by the SCED solution; SCED is unable to effectively clear energy and cover regulation when NDVERs behave in this manner. This behavior results in the SPP BA having to manually manage the additional lost output with regulation, putting the Reliability Coordinator in a position to possibly issue an OOME to the NDVERs who are responding to LMP changes in order to mitigate flowgates becoming unstable from the unexpected oscillations caused by NDVERs that follow price. Additionally, NDVERs make up a large majority of the Resources to which OOMEs are issued. The need to issue an OOME inherently represents an actual reliability issue that has risen to the attention of the RC and requires the RC to take action to maintain reliability. Although these reliability issues are manageable, converting NDVERs to DVERs would remove the associated reliability risks.

In the 2015 ASOM Report, the SPP MMU stated their concern with Non-Dispatchable Variable Energy Resources due to their adverse impact on market prices. The SPP MMU stated that when prices are depressed in high wind production regions, NDVERs have an adverse impact on prices in two ways. Some resources chase price, ignoring the system dispatch and self dispatching to a lower level in an attempt to avoid the cost associated with producing when prices are very low. This behavior at times causes unexpected volatility on the system and distorts market prices. The alternative behavior is for these NDVER units to continue to produce as expected even when prices are below what would be an appropriate market clearing price. Both cases result in sub-optimal market results. The SPP MMU recommended SPP transition NDVER Resources to DVER status to lessen the negative impact of such resources on the market. Work to respond the MMU’s recommendation has been tracked via both MOPC and MWG action items.


Increased reliability realized through collective dispatchable Resources mitigating multiple constraints simultaneously Increased economic efficiency through reduction of manual Out-of-Merit Energy (OOME) instructions Reduction of price volatility (reliability and economic benefit) Having more VERs be controllable by the market and not subject only to variable fuel and external control behaviors leads to

less pricing uncertainty as a result of: Reduction of ramp scarcity events by having NDVERs controllable within SCED

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Further optimization of quick start Resource needs by having a larger set of Resources that are under SCED control Increased pricing convergence between Day Ahead and Real-Time due to larger set of controllable Resources in RT Further potential optimization of Operating Reserves with potentially more VERs participating in the offering of

certain ancillary services. If they convert, they will be controllable and may qualify for REG DN Increased reliability by reducing NDVER generation oscillation Market efficiencies are gained by adding dispatchable generation to resolve congestion in the load pocket, rather than

redispatching less effective generation to protect the NDVER output. This has the potential to reduce the congestion costs from less effective generation redispatch

COMMENTS

NPPD has concerns with RR272

See below for NPPD comments related to RR272:

- SPP has stated that conversion of the NDVER to DVER units would have a positive impact on market efficiencies. With a potential of market benefits, we believe it to be short sighted to not address the cost impacts of such a conversion on the member utilities. This would include a process to determine the level of cost by that Entity and have the market compensate the costs.

- There are some Resources not designed to move every 5 minutes. Example would be Type 1 and Type 2 wind turbines. Converting these types of Wind Turbines would likely result in additional maintenance costs and increased risk of turbine failures. These costs and risks will be borne by the member or developer with potentially no chance of cost recovery from SPP.

- Generally speaking, there is a broader issue that should be addressed. And that is the lack of market systems recognizing that there are a number of generating units that have connected to the SPP system utilizing only a Generator Interconnect Agreement (GIA). The SPP Tariff has historically allowed this type of service, but the market needs to be able to recognize that these units are essentially utilizing non-firm transmission and being dispatched comparatively to units that have requested, and paid for, firm transmission service. Most NDVER’s have requested and paid for upgrades to get firm transmission for delivery to their load. The Firm Transmission Rights allow a hedge however that still is not enough to offset the impacts of resources not having Firm Transmission Rights. Also getting the congestion rights needed, are at times, not possible even if having firm transmission rights. If SPP could differentiate between these types of resources and dispatch those non-firm resources that are impacting the congestion before prices become volatile that would result in a better overall market. At this time there is not much in enhancement of acquiring Firm Transmission by resources. If SPP would curtail resources without firm transmission before those with Firm it could enhance more firm transmission being requested and upgrades that the costs are currently borne by the Load.

- The SPP Market sees many periods of price spikes in the RT Market due to flowgate congestion. At what level of a price spike due to a CME event is a Reliability Signal? NPPD believes that there are times that when flowgates are “Binding” or “Breached” and flows need to change address reliability concerns it should be a Reliability Signal. The reason for the price spikes is due to a current or projected transmission line overload or N-1 condition. That is a reliability concern and that signal should be treated that way. NPPD has asked for a clarification on this subject from SPP and has yet to see a response.

- Additionally, this is an example of SPP changing the market rules which were agreed upon during the SPP IM integration phase. SPP allowed the use of NDVERs and now that agreement is potentially changing with the added cost burden of the changes being placed on the member utilities.

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RR #: 272 Date: 2/2/2018

RR Title: NDVER to DVER Conversion


Name: Grant Wilkerson

Cliff Franklin Company: Westar Energy, Inc.

Email: [email protected]

[email protected]

Phone: 785.231.9331

443.226.7787



Describe the problem/issue this revision request will resolve.

SPP proposes in this revision request to require that, after a two year transition period, all Variable Energy Resources registered as

Non-Dispatchable Variable Energy Resources be required to register as Dispatchable Variable Energy Resources unless they are a

Qualified Facility exercising their rights under the Public Utility Regulatory Policies Act of 1978 (PURPA).

Non-Dispatchable Variable Energy Resources in SPP’s market create market inefficiencies and reliability risks that SPP resources

and systems must mitigated.

1) Market Efficiency: Collections of NDVERs are generally located in the same region, however it is often necessary to

redispatch many Resources (DVERs and others with potentially lower shift factors) around them in order to solve

constraints, leading to higher congestion costs for the market. Additionally, SPP has observed NDVERs reacting to LMP

signals - dropping offline when the LMP drops and responding to increased LMPs by generating at the same prior output;

although by definition, NDVERs are not capable of being incrementally dispatched by the Transmission Provider. When

this price-following behavior from NDVERs occurs, the subsequent market redispatch and pricing are inefficient, due to

the assumption that NDVERs are not capable of dispatching and reacting to price. Additionally, SPP may OOME

NDVERs today. However, the issuance of an OOME is less precise than the systematic redispatch provided by the market

when resources are dispatchable. This imprecision results in either too much or too little redispatch being provided

requiring other market and reliability mechanisms to make up the difference.

2) Reliability: The price-following behavior of NDVERs also present reliability and operational challenges when NDVERs

suddenly drop offline and then return to follow an increase in LMP as more relief may be realized than was requested by

the SCED solution; SCED is unable to effectively clear energy and cover regulation when NDVERs behave in this

manner. This behavior results in the SPP BA having to manually manage the additional lost output with regulation,

putting the Reliability Coordinator in a position to possibly issue an OOME to the NDVERs who are responding to LMP

changes in order to mitigate flowgates becoming unstable from the unexpected oscillations caused by NDVERs that follow

price. Additionally, NDVERs make up a large majority of the Resources to which OOMEs are issued. The need to issue

an OOME inherently represents an actual reliability issue that has risen to the attention of the RC and requires the RC to

take action to maintain reliability. Although these reliability issues are manageable, converting NDVERs to DVERs

would remove the associated reliability risks.

In the 2015 ASOM Report, the SPP MMU stated their concern with Non-Dispatchable Variable Energy Resources due to their

adverse impact on market prices. The SPP MMU stated that when prices are depressed in high wind production regions, NDVERs

have an adverse impact on prices in two ways. Some resources chase price, ignoring the system dispatch and self dispatching to a

lower level in an attempt to avoid the cost associated with producing when prices are very low. This behavior at times causes

unexpected volatility on the system and distorts market prices. The alternative behavior is for these NDVER units to continue to

produce as expected even when prices are below what would be an appropriate market clearing price. Both cases result in sub-

optimal market results. The SPP MMU recommended SPP transition NDVER Resources to DVER status to lessen the negative

impact of such resources on the market. Work to respond the MMU’s recommendation has been tracked via both MOPC and

MWG action items.


Increased reliability realized through collective dispatchable Resources mitigating multiple constraints simultaneously

Increased economic efficiency through reduction of manual Out-of-Merit Energy (OOME) instructions

Reduction of price volatility (reliability and economic benefit)

Having more VERs be controllable by the market and not subject only to variable fuel and external control behaviors leads to

less pricing uncertainty as a result of:

mailto:[email protected]

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Reduction of ramp scarcity events by having NDVERs controllable within SCED

Further optimization of quick start Resource needs by having a larger set of Resources that are under SCED control

Increased pricing convergence between Day Ahead and Real-Time due to larger set of controllable Resources in RT

Further potential optimization of Operating Reserves with potentially more VERs participating in the offering of

certain ancillary services. If they convert, they will be controllable and may qualify for REG DN

Increased reliability by reducing NDVER generation oscillation

Market efficiencies are gained by adding dispatchable generation to resolve congestion in the load pocket, rather than

redispatching less effective generation to protect the NDVER output. This has the potential to reduce the congestion

costs from less effective generation redispatch

COMMENTS

Westar has concerns with RR272:

Westar agrees with the NPPD comments listed at the bottom of this document but would add several considerations not addressed

by SPP staff in RR272.

- First and foremost, SPP staff has repeatedly communicated their desire to make NDVER dispatchable, either through

dispatch instruction NDVER clips, RR272, or in MWG discussions on wind. They state that price-following

NDVERs have caused significant reliability issues since the start of Integrated Marketplace (IM) in 2014. If price-

following NDVERs are the real problem, then at a minimum, SPP staff should have submitted an option for MWG

consideration to penalize price-following NDVERs instead of forcing all NDVER conversions as in RR272.

- SPP provides a presentation 8.a.NDVER to DVER Conversion Analysis.pdf claiming there have been reliability issues

associated with price following NDVERs and there exists significant market efficiency benefits to be gained in forcing

NDVER to DVER conversion. There is no study, nor does it include financial impacts forced upon NDVER

owners/buyers in making conversions. The presentation states “78% of NDVERs have Firm PTP/Firm NITS” but fails

to acknowledge that the market dispatch provides no recognition of this fact. In fact, this RR fails to recognize the fact

that it is the interconnection process that has allowed additional generation to be connected to the grid creating existing

generation NDVERs to become congested and now look for the NDVER party to financially remedy this short coming

in market design. In SECTION 4: INDIVIDUAL NDVER RESOURCE CONVERSION – FINANCIAL ANALYSIS,

SPP states, “The annual savings ranged from $94k to $115k” for a single NDVER to DVER conversion. We can

assess nothing from this analysis. Was the unit the most constrained NDVER or was it truly a representation of the

average. Someone once said that you can twist the arm of statistics/modeling until they confess to anything. SPP fails

to provide critical information needed to make their analysis credible;

1. What was the name and location of the NDVER resource?

2. What was the size in MW of the NDVER resource and was it representative of all NDVERs?

3. Is SPP claiming 5000 intervals where NDVER offers fall below LMP representative of all SPP NDVERs and

is it necessary to achieve positive economics and is it representative of all NDVERs?

4. Do NDVERs having less than 5000 intervals where their offer fell below the LMP not benefit from a NDVER

conversion?

5. What transmission constraints were applicable to the study NDVER and was it representative of all NDVERs?

6. How many hours of negative pricing were experienced by this resource and is it representative of all

NDVERs?

7. During high wind and low load intervals, what was the bottom standard deviation LMP pricing and was it

representative of all NDVERs?

8. Did SPP re-price SCED dispatch for both the NDVER, NDVER→DVER conv, DVER, DVER+8 or did SPP

staff just add subtract NDVER/DVER scenarios assuming historical LMPs would not change?

9. What transmission constraints were applicable to the study NDVER and was it representative of all NDVERs?

10. Would conversion of all NDVERs reduce benefits for the study NDVER if SPP completely re-priced all SPP

LMP locations?

11. Is 10/2016 – 10/207 representative of wind and wind/generation mix since market startup or did that time

frame contain higher wind values that historically seen in SPP?

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- RR272 effectively abrogates all NDVER PPA contracts, except for qualifying facilities, by undermining the

grandfathered non-dispatchable status over older wind farms upon which their supply contracts were based. RR272

fails to address the financial exposure of owners/buyers of NDVERs by forcing them to become dispatchable which

they may be incapable to perform within URD guides and which their contracts lacked notice to consider. RR272

throws NDVER owners/buyers “under the bus” by financially exposing them “economic dispatch” of which neither

contract accounted for nor the unit was operationally constructed. RR272 forces NDVER conversion and abrogates

NDVER contracts making RR272 unjust and unreasonable.

- RR272 fails to address the issue that many Market Participants (MPs) manage many NDVERs in the market owned by

an Asset Owner which is not an MP. SPP puts the burden of NDVER conversions completely onto MPs which may

not own the NDVER nor have any control over upgrades for the resource. Likewise, in cases where NDVERs

capacity/energy is sold from AO seller to MP buyer, RR272 places all burden of NDVER conversion to the buyer MP

in which RR272 has no regard for their inability or lack of authority to make NDVER→DVER upgrades. This will

leave the buyer MP in a badly disadvantaged position to renegotiate unit upgrades and contract terms, likely resulting

in significant financial loss exposure. RR272 lack of consideration for NDVER financial exposure to make them

dispatchable is clearly unjust and unreasonable. RR272, at minimum, should be changed to make Generation

Interconnection Owners have the burden of upgrading NDVERs.

- Last and perhaps the most import factor not considered by RR272 is SPP’s market reputation. NDVERs were a

condition of several MPs agreeing to transition from EIS to IM. If we go back on our word, will other MPs lose

confidence in the stability of SPP tariff grandfathering and agreements made to prospective Balancing Authorities,

Asset Owners, and Market Participants considering the benefits of join SPP as a stable settlement & market platform?

NPPD has concerns with RR272

See below for NPPD comments related to RR272:

- SPP has stated that conversion of the NDVER to DVER units would have a positive impact on market efficiencies.

With a potential of market benefits, we believe it to be short sighted to not address the cost impacts of such a

conversion on the member utilities. This would include a process to determine the level of cost by that Entity and have

the market compensate the costs.

- There are some Resources not designed to move every 5 minutes. Example would be Type 1 and Type 2 wind

turbines. Converting these types of Wind Turbines would likely result in additional maintenance costs and increased

risk of turbine failures. These costs and risks will be borne by the member or developer with potentially no chance of

cost recovery from SPP.

- Generally speaking, there is a broader issue that should be addressed. And that is the lack of market systems

recognizing that there are a number of generating units that have connected to the SPP system utilizing only a

Generator Interconnect Agreement (GIA). The SPP Tariff has historically allowed this type of service, but the market

needs to be able to recognize that these units are essentially utilizing non-firm transmission and being dispatched

comparatively to units that have requested, and paid for, firm transmission service. Most NDVER’s have requested

and paid for upgrades to get firm transmission for delivery to their load. The Firm Transmission Rights allow a hedge

however that still is not enough to offset the impacts of resources not having Firm Transmission Rights. Also getting

the congestion rights needed, are at times, not possible even if having firm transmission rights. If SPP could

differentiate between these types of resources and dispatch those non-firm resources that are impacting the congestion

before prices become volatile that would result in a better overall market. At this time there is not much in

enhancement of acquiring Firm Transmission by resources. If SPP would curtail resources without firm transmission

before those with Firm it could enhance more firm transmission being requested and upgrades that the costs are

currently borne by the Load.

- The SPP Market sees many periods of price spikes in the RT Market due to flowgate congestion. At what level of a

price spike due to a CME event is a Reliability Signal? NPPD believes that there are times that when flowgates are

“Binding” or “Breached” and flows need to change address reliability concerns it should be a Reliability Signal. The

reason for the price spikes is due to a current or projected transmission line overload or N-1 condition. That is a

reliability concern and that signal should be treated that way. NPPD has asked for a clarification on this subject from

SPP and has yet to see a response.

- Additionally, this is an example of SPP changing the market rules which were agreed upon during the SPP IM

integration phase. SPP allowed the use of NDVERs and now that agreement is potentially changing with the added

cost burden of the changes being placed on only a sub-group of Market Participants.

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RR #: 263 Date: 11/19/2017

RR Title: NDVER to DVER Conversion through Incentives System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes


Name: Grant Wilkerson & Clifford Franklin Company: Westar Energy, Inc (WRGS) Email: [email protected], [email protected] Phone: Grant 785-575-8074, Cliff 443-226-7787

Only Qualified Entities may submit Revision Requests. Please select at least one applicable option below, as it applies to the named submitter(s).










Correction

Clarification

Design Enhancement










Market Protocols

Section(s): 1, 4.5.3.4, 4.5.4, 4.5.4.1, 4.5.4.1.1, 4.5.4.1.2, 4.5.4.1.3, 4.5.4.2, 4.5.5, 6.1.8, 6.1.9, 6.1.10, 6.1.11, 6.1.11.1, G.8.1, G.8.2, G.8.3, G.8.4, G.8.5, G.9, G.9.1, G.9.2, G.9.3, G.9.4, G.10, G.10.1, G.10.2, G.10.3

Protocol Version: 44



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Operating Criteria Section(s): Criteria Date: Planning Criteria Section(s): Criteria Date:

Tariff (OATT) Section(s): Sixth Revised Volume No. 1, Generated On: 10/1/2017 Attachment AE, Sections 1, 2.7 – 9, 4.1.2.5- 7

Business Practice Business Practice Number: Integrated Planning Model (ITP Manual) Section(s): Revision Request Process Section(s): Minimum Transmission Design






This RR provides to MWG a true incentive “carrot” for a Non-Dispatchable Variable Energy Wind Resource (NDVER) to have the option to voluntarily upgrade their wind farm dispatch controls so SPP can curtail NDVERs for non-emergency events based upon a follow dispatch flag and a 5-minute dispatch signal. NDVERs could then voluntarily allow SPP to curtail their output for non-emergency events such as;

1. economic dispatch,

2. helping to relieve binding constraints,

3. helping reduce system capacity during Minimum Generation events, or

4. helping relieve SPP regulation up/down ramping deficiencies.

PPA contracts were formed by NDVER owning Market Participants (MPs) assuming the SPP Integrated Marketplace would continue to grandfather older wind farms built prior to 10/15/2012 and not be forced into being economically dispatchable. It was one of the requirements for some to MPs to join SPP EIS and IM markets. FERC agreed with the SPP 10/15/2015 compromise, by approving tariff language and not requiring some older wind farms to be dispatchable.

Some recent proposals by SPP advocate making all NDVERs dispatchable, regardless of upgrade or PPA cost exposure imposed onto NDVER owner/buyers. Thus, SPP proposes abrogating all previously negotiated NDVER PPA contracts, forcing the NDVER sellers/buyers into PPA renegotiation, or the more likely outcome, owners/buyer financial losses.

However, this RR proposes incentives for MP NDVER owners to upgrade their controls, requires the market to pay NDVER wind farms, optionally choosing dispatchable control status, to be paid for their curtailment according to the buyers PPA contract financial exposure by reimbursing wind owners for lost federal government PTC revenues and does not financially abrogate grandfathered NDVER PPA contracts between sellers/buyers.


Contrary to the “stick” approaches previously proposed by SPP staff or stakeholders, the RR offers SPP & MWG a legitimate “carrot” approach to incent NDVERs to voluntarily become dispatchable. This RR proposes that LMPs and MCPs be formulated to compensate NDVERs for the lost PTC and PPA rate (if contractually applicable) into both local LMPs & MCPs, as a type of SPP DRR payment. This type of DRR payment will be known as a Dispatch Curtailment Pseudo Load (NDVER-DCPL). The NDVER-DCPL placed at the renewable resource location (e.g. Non-dispatchable NDVER wind, solar, storage, hydro, etc.) can submit a NDVER-DCPL offer curve which will be settled at the renewable curtailed output at the negative LMP at an electrically equivalent output location to the NDVER output terminals.

For the example above, Windfarm A is an NDVER voluntarily registering a NDVER-DCPL, will be paid according to the curtailed output of the NDVER.


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Market Protocols

1. Glossary

….

Demand Response Load

A measurable load that is capable of being reduced at the instruction of the SPP operator and subsequently increased at the instruction of the SPP operator that is identified in the registration of a Dispatchable Demand Response Resource or a Block Demand Response Resource.

….


A Variable Energy Resource that is capable of being incrementally dispatched by the Transmission Provider.

….


A Variable Energy Resource that is not capable of being incrementally dispatched down by the Transmission Provider.

Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load – (NDVER-DCPL)

After a Market Participant (MP) has upgraded a Non-Dipatchable Variable Energy Resource (NDVER) to accept 5-minute economic/reliability dispatch instructions from SPP, the MP may register a Dispatch Curtailment Pseudo Load NDVER-DCPL so the MP can be paid by SPP for NDVER curtailments without SPP having to issue an OOME instruction. The NDVER-DCPL will represent a MP capacity/price offer for SPP to using in clearing curtailment NDVER MWs.. During emergencies or reliability issues which SCED can’t solve, SPP shall continue to issue OOME instructions to NDVERs.

SPP shall clear NDVER-DCPL curtailment MWs for the NDVER using the negated NDVER LMPi.. SPP shall settle the NDVER-DCPL based NDVER curtailed MWs at a negated NDVER LMPi or negated NDVER MCP price based upon the NDVER-DCPL offer curves. Self or curtailment more than SPP dispatch instructions will not be cleared by SPP.

-….

4.5.3.4 GFA Carve Out or FSE Uplift

GFA Carve Out or FSE Schedules result in removal of the energy, congestion, and marginal losses for the transaction from settlement statements. SPP will capture the congestion charges and marginal loss charges related to the GFA Carve Outs or FSEs. These charges will be offset by the ARR/TCR settlement that would have been claimed for the GFA Carve Out or FSE

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under the normal ARR/TCR process and the distribution of the Marginal Loss Overcollection funds. Candidate ARRs associated with the GFA Carve Out or FSE service shall not be nominated for a product period if, based upon the twelve preceding months for which congestion data is available, such ARR, had it been converted to a TCR, would have resulted in a TcrFundHrlyAmt net charge to the holder of the TCR over that product period, as defined for the annual ARR allocation process. However, until twelve months of Integrated Marketplace data is available, SPP will use relevant data from both the EIS Market and the Integrated Marketplace to estimate whether the result is a net charge.

(i) For the MW capacity associated with each FSE, the sink for the ARR/TCR shall be the (1) load Settlement Location within the UMZ, (2) interface with an external Balancing Authority, or (3) FSE Transfer Point, as appropriate. For ARR/TCR activity from FSE Transfer Points to load external to the UMZ but internal to the Transmission Provider, the normal ARR/TCR process is available to the applicable Market Participants from the FSE Transfer Point to the load consistent with the transmission service reservation.

4.5.4 Calculation of LMPs, LMP Components and MCPs

SPP uses a co-optimized SCED model to compute Locational Marginal Prices (LMPs) for Energy at PNodes. The LMPs are then mapped to Settlement Locations in the commercial model. The SCED model also computes Market Clearing Prices (MCPs) for Regulation-Up Service, Regulation-Up Mileage, Regulation-Down Service, Regulation-Down Mileage, Spinning Reserve and Supplemental Reserve on a Reserve Zone basis. For the DA Market, LMPs and MCPs are calculated on an hourly basis. For the RTBM, LMPs and MCPs are calculated for each 5-minute Dispatch Interval. Inputs to SCED for the DA Market are as described under Section 4.3.1.1 and inputs to SCED for the RTBM are as described under Section 4.4.2.2. The following subsections further describe how LMPs, LMP Components and MCPs are calculated.

4.5.4.1 LMP Calculations and LMP Components

The LMP at a PNode is the cost of delivering an incremental MW of energy at that specific PNode, while satisfying all operational constraints where such cost will include applicable Demand Curve prices if the incremental MW of energy causes a corresponding increase in shortage conditions where such Demand Curve prices and shortage conditions are as described under Section 4.1.5. The LMP at any PNode is the sum of three components; the marginal costs of Energy (Marginal Energy Component or MEC), the marginal cost of losses (Marginal Loss Component or MLC), and the marginal cost of congestion (Marginal Congestion Component or MCC).

LMP Components at PNode i are calculated based upon the following formulas:

LMPi = MEC + MLCi + MCCi

Where:

(1) MEC is the component of LMPi representing the marginal cost of Energy;

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(2) MLCi is the component of LMPi representing the marginal cost of losses at PNode i relative to the Reference Bus;

(3) MCCi is the component of LMPi representing the marginal cost of congestion at ENode i relative to the Reference Bus; and

(4) The Reference Bus represents the network Distributed Load Bus.

(5) NDVER-DCPL curtailment load locations are always linked to a NDVER resource. The NDVER-DCPL LMP shall be the negative of the linked NDVER LMP where,

NDVER-DCPLk LMPi = (NDVERk LMPi ) ( -1 )

4.5.4.1.1 Marginal Losses Component Calculation

The MLCi at each PNode i is defined by the following equations:

MLCi = -MLSFi * MEC

MLSFi = ∂ (SPP Losses) / ∂ Pi

Where:

(1) SPP Losses = SPP transmission system losses;

(2) MLSFi = Marginal Loss Sensitivity Factor at PNode i;


(4) Pi = Net injection at PNode i.

(4)(5) NDVER-DCPL pseudo load will not be considered within MLCi since it represents a curtailment of NDVER generation and does not represent actual physical load.

The MLSFi is a linearized estimate of the change in SPP transmission losses that will result from a 1 MW injection at PNode i coupled with a corresponding withdrawal at the Reference Bus to maintain global power balance (the withdrawal at the Reference Bus will generally be higher or lower than 1 MW since there will be a change in losses). Marginal loss sensitivity factors are dependent on topology, node injections and node withdrawals, and are only considered constant within a small deviation from a fixed operating point.

4.5.4.1.2 Marginal Congestion Component Calculation

The MCC at each PNode i is defined by the following equations

MCCi = - ( ∑=

K

k 1Sensik * SPk )

Sensik = ∂ Flowk / ∂ Pi

Where:

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(1) K is the number of transmission constraints;

(2) Sensik is the linearized estimate of the change in the constraint k flow resulting from an incremental energy injection at PNode i coupled with an incremental energy withdrawal at the Reference Bus;

(3) Flowk = Calculated flow for constraint k;

(4) SPk = is the Shadow Price of constraint k;


4.5.4.1.3 Marginal Energy Component Calculation

The MEC is defined as the computed LMP at the Reference Bus. By definition, MCC and MLC components are zero at the Reference Bus.

4.5.4.2 MCP Calculations

The MCP represents the cost of supplying an increment of operating reserve, taking into account lost opportunity cost and is composed of the marginal Operating Reserve costs and marginal costs associated with Operating Reserve scarcity. The DA Market and RTBM MCPs for Regulation-Up Service, Spinning Reserve and Supplemental Reserve at a Reserve Zone for Resources with cleared Regulation-Up Service, Spinning Reserve and/or Supplemental Reserve at that Reserve Zone are equal to the summation of the applicable Shadow Prices associated with each Operating Reserve constraint. This type of MCP formulation is referred to as “price-cascading”. MCPs applied to Excess Regulation-Up Mileage, Unused Regulation-Up Mileage. Excess Regulation-Down Mileage and Unused Regulation-Down Mileage are calculated for the RTBM only as described in (2) and (3) below.

(1) There are four sets of constraints: (i) an Operating Reserve constraint which is set equal to the sum of the Contingency Reserve requirement and the Regulation-Up requirement; (ii) a Regulation-Up Service plus Spinning Reserve constraint which is set equal to the sum of the Regulation-Up requirement and the Spinning Reserve requirement; and (iii) a Regulation-Up Service constraint which is set equal to the Regulation-Up requirement; and (iv) a Regulation-Down Service constraint which is set equal to the Regulation-Down requirement. These constraints apply on both a system-wide basis and a Reserve Zone basis. MCPs for each Reserve Zone are calculated as follows:

(a) The zonal Regulation-Up Service MCP is equal to sum of the system-wide and zonal Shadow Prices for the Regulation-Up constraint, Regulation-Up Service plus Spinning Reserve constraint and the Operating Reserve constraint;

(b) The zonal Spinning Reserve MCP is equal to the sum of the Shadow Prices for the system-wide and zonal Regulation-Up Service plus Spinning Reserve constraint and the Operating Reserve constraint;

(c) The zonal Supplemental Reserve MCP is equal to the sum of the Shadow Price of the system-wide and zonal Operating Reserve constraint and

(d) The zonal Regulation-Down Service MCP is equal to sum of the system-wide and zonal Shadow Prices for the Regulation-Down constraint.

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(2) RTBM MCPs for Expected Regulation-Up Mileage are set equal to the highest Regulation-Up Mileage Offer of all Resource’s economically cleared to provide Regulation-Up Service in a particular Dispatch Interval. For Resource’s submitting a Regulation-Up Service Dispatch Status of “Fixed”, the cleared amount of Regulation-Up Service MW must be greater than the submitted “Fixed” MW in order to be considered economically cleared;

(3) RTBM MCPs for Expected Regulation-Down Mileage are set equal to the highest Regulation-Down Mileage Offer of all Resource’s economically cleared to provide Regulation-Down Service in a particular Dispatch Interval. For Resource’s submitting a Regulation-Down Service Dispatch Status of “Fixed”, the cleared amount of Regulation-Up Service MW must be greater than the submitted “Fixed” MW in order to be considered economically cleared;

(4) During times of Operating Reserve scarcity, MCPs will be impacted by Scarcity Prices as described under Section 4.1.5;

(5) The MCP formulations allow for the substitution of higher quality reserve products for lower quality reserve products to meet the Operating Reserve requirements to the extent that there is excess higher quality Operating Reserve available and these excess amounts provide a more economical solution. In the case of allowing Regulation-Up Service to substitute for Contingency Reserve, only the Regulation-Up Offers will be used in the evaluation. Allowing for this substitution in combination with the “price-cascading” rules described in (1) above ensures that the clearing for Operating Reserve produces Regulation-Up Service MCPs that are greater than or equal to Spinning Reserve MCPs and Spinning Reserve MCPs that are greater than or equal to Supplemental Reserve MCPs;

(a) Regulation-Down is not eligible to substitute for Spinning Reserve and Supplemental Reserve. Therefore, Resource Regulation-Down Service MCPs can be less than Spinning Reserve and/or Supplemental Reserve MCPs.

(6) The MCPs for the various Operating Reserve products as determined by the market clearing process will be sufficient to cover the Offer costs of each Resource as well as the opportunity costs incurred to allocate a portion of the Resource capacity to the supply of the corresponding Operating Reserve product in lieu of another product. The recovery of both offered cost and opportunity costs via Market Clearing Prices is inherent in the co-optimized SCED formulations, thus the separate calculation of opportunity costs is unnecessary.

(7) NDVER-DCPL curtailment load locations are always linked to a NDVER resource. The NDVER-DCPL MCP shall be the negative of the linked NDVER MCP where,

NDVER-DCPLk MCP = (NDVERk MCP ) ( -1 )

4.5.5 Settlement Location LMPs and LMP Components

For Settlement Locations that are associated with more than one PNode, the following calculations are performed to calculate the Settlement Location LMPs and the associated LMP Components. The LMPs for Settlement Locations associated with a single PNode are those LMPs directly calculated by the DA Market software as

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described under Section 4.3.1.3 and the RTBM software as described under Section 4.4.2.3.4. All nodal LMPs are subject to the price correction procedures described under Section 6.6.1. Resource Hub LMPs and the associated LMP Components will be calculated using the same methodology as Trading Hubs as described in Section 4.5.5.1.


All Variable Energy Resources must register as a Dispatchable Variable Energy Resource except for (i) Wind powered Variable Energy Resources with an interconnection agreement executed on or prior to May 21, 2011 and that commenced Commercial Operation before October 15, 2012 or (ii) a Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility, or (iii) Non-wind Variable Energy Resources registered on or prior to January 1, 2017 and with an interconnection agreement executed on or prior to January 1, 2017. VERs included in (i) and (iii) above may register as Dispatchable Variable Energy Resources if they are capable of being incrementally dispatched by the Transmission Provider. A Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility may register as a Dispatchable Variable Energy Resource if it is capable of being incrementally dispatched by the Transmission Provider and will be subject to the DVER market rules including Uninstructed Resource Deviation Charges. Any Resource that has previously registered as a Dispatchable Variable Energy Resource shall not subsequently register as a Non-Dispatchable Variable Energy Resources.

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

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

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

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

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


Variable Energy Resources that qualify may register as a Non-Dispatchable Variable Energy Resource. The Market Participant registering a Non-Dispatchable Variable Energy Resource must provide documentation to SPP verifying that it meets one or more of the exceptions in Section 6.1.7.1. Otherwise, the Resource must be registered as a Dispatchable Variable Energy Resource. NDVERs are committed and dispatched the same as any other Resource in the Day-Ahead Market. For the RUC and RTBM, special commitment and dispatch rules apply as defined under Section 4.2.2.5.6. Non-Dispatchable Variable Energy Resource data submittal requirements are defined in the SPP Criteria.

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6.1.10 Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load (NDVER-DCPL)

Market Participants managing Non-Dispatchable Variable Energy Resource (NDVER) resources may also register as a type Demand Response Resource called a NDVER-DCPL.. The NDVER-DCPL will be registered as a type of DRR, at a separate but electrically equivalent “common bus” settlement location, connected to a NDVER resource settlement location. The NDVER-DCPL represents curtailable NDVER output for SPP economic/reliability dispatch. For the network model, the NDVER-DCPL which represents generation curtailment from an NDVER somewhat like a DRR represents curtail of load at a load settlement location.

The NDVER must first be upgraded by the owner and Market Participant (MP) in order to have the capability to accept 5-minute SPP economic/reliability dispatch instructions. The MP is required to set up and send to SPP a 5-minute NDVER Available MW capability input variable “NDVERDCPL_AMW”. Once the upgrade is completed, the MP can register a NDVER-DCPL settlement location which will indicate to SPP the NDVER is ready for SPP dispatch. The MP will then submit offer curves for both the

1) NDVER-DCPLk curtailment settlement location is linked by a Common Bus to its host

2) NDVERk

The NDVER-DCPL clearing price is formulated simply by negating the NDVER LMP or MCP price. The negating of the NDVER LMP MCP prices can at times reasonably reflect to LMP MCP price of load on constrained side of binding constraints for which the NDVER contributes to congestion.

SPP can then dispatch this type of NDVER registration by sending the resource an economic/reliability Actual dispatch instruction level through “NDVERDCPL_EMW” and will pay the MP registered NDVER-DCPL for economic/reliability curtailments based on the following calculation.

The following provides an simple example how the NDVER-DCPL A and NDVER A works together to

represent a NDVER curtailment and SPP payment when there is NDVER curtailment.

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Exhibit 6.1.10a Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load (NDVER-DCPL) Simple Example

SPP SCED will treat the NDVER- DCPLs and host NDVER resources will be treated separately, each connected by a Common Bus to the NDVER output terminals having separate settlement locations with the pseudo load having a negated price from the NDVER resource

NDVER-DCPLk curtailment loads are always linked with a host NDVERk representing the curtailment from

the actual NDVERk MW capability.

The cleared NDVER-DCPL MW quantity is calculated as follows.

NDVER-DCPLki = NDVERki MW capability – actual NDVERki MW output , where

i….dispatch interval, and

k…NDVER unit numbering

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Exhibit 6.1.10b Simple Example layout

In addition to the responsibilities described in Section 4.1.2 of this Attachment AE and under the Market

Protocols, Market Participants optionally registering a Non-Dispatachable Variable Energy Resource - Disaptch

Curtailment Pseudo Load (NDVER-DCPL) must:

(1) Identify an associated Disaptch Curtailment Pseudo Load Calculation Data Submittal Location;

(2) Identify an associated Disaptch Curtailment Pseudo Load Calculation Settlement Location;

(3) Set up for the NDVER-DCPL pseudo load electrically equivalent settlement location to NDVER

output terminals

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Exhibit 6.1.10c Simple Example for SPP Dispatch

NDVER-DCPL The NDVER must also submit 5-minute NDVER output MW capabilities. SPP will then be able to dispatch the NDVER on 5-minute intervals, resulting in SPP NDVER-DCPL 5-minute interval settlement payment when cleared by SPP for curtailment/deployment and $ 0.0 when not curtailed/deployed. Registering a NDVER-DCPL is strictly voluntary on the part of a NDVER owner who must upgrade to dispatchable controls like DVER registration requirements.

SPP SCED will treat the NDVER and associated DCPLs as mutually exclusive dispatch generation and load, each located at applicable NDVER output terminal settlement locations. The DCPL is dispatched against negation of the NDVER LMP. During periods in which SPP SCED deploys NDVER-DCPL, SPP will

1st) send a follow dispatch flag set to the NDVER and then

2nd) send an NDVER dispatch signal equal to the NDVER 5-minute curtailed output instruction (e.g. net of NDVER actual capability minus DCPL curtailed output).

SPP can curtail this type of NDVER economically in SCED through DCPL deployment without having to issue NDVER OOME instruction. SPP shall not clear any NDVER-DCPL if self-curtailed or clear amounts beyond/below the SPP dispatch instruction. The following special modeling rules apply to a DCPL Resource.

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(1) A NDVER-DCPL is a special type of Resource created to model registered curtailment settlement location linked with a host upgraded/dispatchable NDVER;

(2) A NDVER-DCPL is modeled in the Commercial Model with a separately defined Settlement Location from a NDVER that has been upgraded to be dispatchable. Thus, the NDVER-DCPL will have separate PNode or APNodes at an electrically equivalent location to the associated NDVER PNode or APNode location;

(3) A NDVER-DCPL is also included in the SPP Network Model as a load addition representing offered price of curtailment of the associate NDVER generation output;

(4) A NDVER-DCPL must have a corresponding NDVER at an electrically equivalent location;

(5) The NDVER must have telemetering installed as with DVER registration in which curtailment MW volumes can be measured by SPP settlement;

(6) The Market Participant must submit the real-time actual base NDVER output capability to SPP via SCADA on a 10-second basis

(7) The Market Participant must submit the real-time achieved curtailment of the SPP deployed NDVER-DCPL value to SPP via SCADA on a 10-second basis.

(8) SPP will issue a follow dispatch flag to all NDVERs that have deployed NDVER-DCPL curtailments. The SPP NDVER dispatch instruction will consist of the actual NDVER cleared curtailed output target during for the interval or the actual NDVER output capability during intervals in which the resource is not curtailed.

(9) For each interval, SPP will settle deployed NDVER-DCPL cleared curtailment load resulting from the SCED economic curtailment of an NDVER, if any, and will clear 0.0 MW for the NDVER-DCPL if not curtailed.

(10) The NDVER-DCPL is settled at a common bus electrically equivalent settlement locations with the NDVER LMP and MCP negated. NDVER-DCPLs can be deployed during emergency events or to avoid Regulation scarcity pricing.

Exhibit 4-9: Calculated NDVER and NDVER-DCPL Output and settlements

6.1.10 11 Resources External to the SPP BA

6.1.1011.1 External Dynamic Resources

A Market Participant registers an EDR for the purposes of accounting for importing of Operating Reserve that is sourced external to the SPP BA. An External Dynamic Resource that is modeled in the Eastern Interconnection may either represent a single Resource or a fleet of Resources and is not subject to Energy dispatch, only clearing and deployment of the Operating Reserve products that the EDR is qualified to provide, except that an associated Dynamic Schedule for Energy may be used for the purposes of providing Regulation-Down Service which must

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be specified at registration. An EDR that is associated with a DC tie-line is modeled as a single Resource and may be available for Energy dispatch and/or Operating Reserve clearing which must be specified at registration. See Section 4.2.2.5.7 for specific modeling details.

…

Appendix G Mitigated Offer Development Guidelines … G.8 Demand Response Guidelines A Demand Response Resource is a special type of Resource created to model demand reduction associated with controllable load and/or a behind the meter Resource that is dispatchable either on a 5-minute basis or an hourly basis;

G.8.1 Demand Response Resource (DRR) Cost for Behind the Meter Generation

Market Participants using behind the meter Resource as a DDR Resource should refer to the appropriate unit type defined in this manual to develop incremental cost,

G.8.2 DRR Cost for Demand Reduction

Demand Reduction is the actual reduction of load at the direction of SPP through the commitment and dispatch of as associated DRR. This could include the cycling of air conditioners or the shutdown of an industrial production process in order to reduce the load at a site. Incremental costs can include quantifiable opportunity costs associated with the reduction, net of related offsetting increases in usage. Typically, demand reduction would be registered as a Block Demand Response Resource but an industrial site that can control its load consumption on a real-time basis could register as a Dispatchable Demand Response Resource.

G.8.3 DRR Start-Up Cost

DRR Start-Up cost is the cost to shut down or curtail a load for a given period, which does not vary with output, or the start cost of a behind the meter Resource. Start costs for DRRs represented by behind the meter Resources are defined by unit type in this manual. Start-Up costs for DRRs representing load curtailment are not specifically defined but will be evaluated on a case by case basis when submitted as part of a Market Participants fuel cost policy for reasonableness.

G.8.4 DRR Cost to Provide Spinning and/or Supplemental Reserves

Spinning Reserves from Demand Response Resources must be provided by equipment electrically synchronized to the system, and able to be fully deployed for the cleared amount within ten minutes upon request by SPP. The costs of spinning reserves from a DRR are the quantifiable incremental costs to reduce load by the offered amount within ten minutes. Incremental costs include shut down costs and opportunity costs.

G.8.5 DRR Cost to Provide Regulation

Regulation-Up and/or Regulation-Down from Dispatchable Demand Response Resources must be provided by equipment electrically synchronized to the system and able qualify for provision of

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regulation services. The costs of regulation from DDR Resources are the quantifiable incremental costs to reduce load by the offered amount within five minutes. Incremental costs include shut down costs and opportunity costs.

G.9 Non-Dispatchable Variable Energy Resource – Dispatch Curtailment Pseudo Load (NDVER-DCPL) NDVER-DCPL- NDVER curtailment load amount which is settled at the negated NDVER LMP or MCP price and is offered at a price at which the NDVER Market Participant is willing to accept economic curtailment of their NDVER.

G.9.1 NDVER-DCPL: SPP NDVER dispatch Curtailment Energy Cost Exposure

NDVER with unexpired Federal Government Production Tax Credits (PTCs) or unexpired Purchase Power Agreement (PPA) purchase contracts may include lost PTC revenue exposure or PPA buyer cost obligations associated with NDVERs within a registered NDVER-DCPL pseudo curtailment load mitigated energy or reserve offer. Lost revenues can include, but is not necessarily limited to, PTC lost revenue exposure or contractual PPA buyer cost obligations triggered by economic/reliability SPP dispatch.

NDVER Conversions to Dispatchable and Market Benefits:

The SPP MMU has made frequent claims there are significant benefits from NDVERs becoming dispatchable. Thus, for NDVERs that both register and offer NDVER-DCPL curtailments for the at least 95% of NDVER capacity, the MMU shall allow reasonable PTC revenue and contractual PPA seller/buyer cost obligations for any SPP economic/reliability dispatch.

Market Participant Release from Burden of Proof:

If the parties to NDVER PPA contract dispute the contractual terms for cost obligations when SPP economically/reliability dispatches an NDVER-DCPL, within reason, the MMU will allow such cost exposure into mitigated offers so that nether the owners/sellers/buyers placed with burden of proof for disputed contractual terms.

G.9.2 Mitigated Start-Up Offer

NDVER-DCPLs do not have start costs.

G.9.3 Mitigated No-Load Offer

NDVER-DCPLs do not have No-Load costs.

G.9.4 VOM

NDVER-DCPLs should reflect their short-run incremental VOM costs for incrementing or decrementing of NDVER output by using the most current data available. This could include the previous actual short-run incremental cost where available. For wind units, VOM dollars from the previous years should be divided by MWh generated in the same period.

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𝐸𝐸𝐸𝐸𝐸𝐸 𝑉𝑉𝐸𝐸𝑉𝑉 𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴𝐴 ($/𝑉𝑉𝑀𝑀ℎ) =𝑉𝑉𝐸𝐸𝑉𝑉 𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐷𝐴𝐴𝐷𝐷 ($)

𝑉𝑉𝑀𝑀ℎ 𝐺𝐺𝐴𝐴𝐺𝐺𝐴𝐴𝐴𝐴𝐷𝐷𝐺𝐺𝐺𝐺𝐷𝐷𝐺𝐺 𝑃𝑃𝐴𝐴𝐷𝐷𝐴𝐴𝑃𝑃𝑃𝑃𝐴𝐴𝐴𝐴

G.9 10 Wind Guidelines

Wind Units- Generating unit in which wind spins the turbine Resource to produce electricity. G.109.1 Fuel Cost

Wind Units may include applicable costs that vary by MWh output.


Wind Units do not have start costs.


Wind Units do not have No-Load costs.

G.9.4 VOM

Wind units should reflect their short-run incremental VOM costs by using the most current data available. This could include the previous actual short-run incremental cost where available. For wind units, VOM dollars from the previous years should be divided by MWh generated in the same period.



SPP Tariff (OATT)

ATTACHMENT AE

INTEGRATED MARKETPLACE


1.1 Definitions D

....

Common Bus

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A single bus to which two or more Resources owned by the same Asset Owner are connected in an electrically

equivalent manner where such Resources may be treated as interchangeable for certain compliance monitoring

purposes.

....


A registered measurable load that is capable of being reduced at the instruction of the Transmission Provider

and subsequently may be increased at the instruction of the Transmission Provider.

Demand Response Resource

A Dispatchable Demand Response Resource or a Block Demand Response Resource.

Dispatch Instruction

The communicated Resource target Energy Megawatt output level at the end of the Dispatch Interval.

Dispatchable Demand Response Load Settlement Location

A registered load Settlement Location that contains the Demand Response Load associated with a Dispatchable

Demand Response Resource.

Dispatchable Demand Response Resource

A Resource created to model Demand Response Load reduction associated with controllable load or a Behind-

The-Meter generator that is dispatchable on a five (5) minute basis.

…


A Variable Energy Resource that is not capable of being incrementally dispatched by the Transmission Provider.

Non-Dispatchable Variable Energy Resource – Dispatch Curtailment Pseudo Load (NDVER-DCPL)

After a Market Participant (MP) has upgraded a Non-Dipatchable Variable Energy Resource (NDVER) to

accept 5-minute economic/reliability dispatch instructions from SPP, the MP may register a Dispatch

Curtailment Pseudo Load NDVER-DCPL so the MP can be paid by SPP for NDVER curtailments without SPP

having to issue an OOME instruction. The NDVER-DCPL will represent a MP capacity/price offer for SPP to

using in clearing curtailment NDVER MWs.. During emergencies or reliability issues which SCED can’t

solve, SPP shall continue to issue OOME instructions to NDVERs.

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SPP shall clear NDVER-DCPL curtailment MWs for the NDVER using the negated NDVER LMPi.. SPP shall

settle the NDVER-DCPL based NDVER curtailed MWs at a negated NDVER LMPi or negated NDVER MCP

price based upon the NDVER-DCPL offer curves. Self or curtailment more than SPP dispatch instructions will

not be cleared by SPP.

…

4.1 Offer Submittal

…

4.1.2.5 Non-Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Non-Dispatchable Variable

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

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

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

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

output at the start of the Dispatch Interval and the Resources must operate as non-

dispatchable;

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

calculating production costs relating to RUC make whole payments and cost allocation

thereof under Sections 8.6.5 and 8.6.7 of this Attachment AE;

(5) An OOME may be issued to a Non-Dispatchable Variable Energy Resource. In addition,

the Transmission Provider will issue the dispatch instruction to the Resource in accordance

with Section 6.2.4 of this Attachment AE; and

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

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

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

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

maximum operating limits shall be equal to those submitted in the Resource Offer;

(a) Non-Dispatchable Variable Energy Resources for which the Transmission Provider

is calculating an output forecast are not eligible to receive RUC make whole

payments as described under Section 8.6.5 of this Attachment AE.

4.1.2.6 Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load (NDVER-DCPL)

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Market Participants managing Non-Dispatchable Variable Energy Resource (NDVER) resources may

also register a type of Demand Response Resource (DRR) called a Dispatch Curtailment Pseudo Load –

(NDVER-DCPL) so the MP can be paid by SPP for NDVER curtailments without SPP having to issue

an OOME instruction to the NDVER. The NDVER-DCPL will be modeled on a Common Bus to the

NDVER at a separate settlement location. The NDVER-DCPL represents SPP economic/reliability

curtailment of NDVER output referred here as 5-minute dispatchable. SPP will clear the NDVER-

DCPL based on MP submitted curtailment dispatch curves and a negated NDVER LMPi. If there is no

curtailment of the NDVER the NDVER-DCPL will have 0.0 cleared MWs based on the following

formula.


Additionally, MCP will be cleared by SPP in the same manner.

.NDVER-DCPLk MCP = (NDVERk MCP ) ( -1 )

NDVER-DCPLk curtailment loads are always linked with a host NDVERk representing the curtailment

Registering a NDVER-DCPL is strictly a voluntary for NDVER owners and MPs. However, the

NDVER must upgraded to dispatchable controls so the NDVER can accept a 5-minute dispatch

instruction from SPP, prior to registering the NDVER-DCPL. The following provides a simple example

how the NDVER-DCPL A and NDVER A works together to represent a NDVER curtailment and SPP

payment when there is NDVER curtailment.

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Exhibit 4.1.2.6a Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load (NDVER-DCPL) Simple Example








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Exhibit 4.1.2.6b Simple Example layout

SPP can curtail this type of NDVER economically in SCED through DCPL deployment without having to issue

NDVER OOME instruction. SPP shall not clear any NDVER-DCPL if self-curtailed or clear amounts

beyond/below the SPP dispatch instruction. See example below.

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Exhibit 4.1.2.6c Simple Example for SPP Dispatch







output terminals

4.1.2.67 External Dynamic Resource

Each Market Participant may submit Resource Offers for External Dynamic Resources

(“EDR”) using the same Offer parameters available to any other Resource, except that:

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(1) A Market Participant may only submit a commitment status as defined in Section

4.1(10)(a) or (d) of this Attachment AE;

(2) For an EDR in the Eastern Interconnection, a Market Participant must submit a dispatch

status indicating that the EDR is not available for energy dispatch as described under

Section 4.1(11)(a) of this Attachment AE;

(3) For an EDR in the Eastern Interconnection, Resource Offer parameters are limited to:

Regulation-Up and Regulation-Down Offers, Spinning and Supplemental Reserve Offers,

Regulation Ramp Rate, Contingency Reserve Ramp Rate and Resource Status. All other

Resource Offer parameters as listed in Section 4.1(9) of this Attachment AE shall not apply

to EDRs in the Eastern Interconnection.

(4) For an EDR that is not in the Eastern Interconnection, Resource Offer parameters are

limited to: Energy Offer Curve, Ramp-Rate-Up, Ramp-Rate-Down, Regulation-Up and

Regulation-Down Offers, Spinning and Supplemental Reserve Offers, Regulation Ramp

Rate, Contingency Reserve Ramp Rate and Resource Status. All other Resource Offer

parameters as listed in Section 4.1(9) of this Attachment AE shall not apply to EDRs that

are not in the Eastern Interconnection.

….

ATTACHMENT AF MARKET POWER MITIGATION PLAN

…

3.2 Mitigation Measures for Energy Offer Curves

Mitigated Energy Offer Curves shall be submitted on a daily basis by the Market Participant in

accordance with the mitigated offer development guidelines in the Market Protocols. For Multi-

Configuration Resources (“MCR”), as defined in Attachment AE, for which a single configuration

allows physical units to be swapped (e.g., Combustion Turbine 2 for Combustion Turbine 1), the

costs used in the mitigated offer development for that configuration shall be those of the least cost

physical unit that is available and can be swapped in such configuration. The mitigated Energy

Offer Curve may be updated up to the close of the Day-Ahead Market as defined in Section 5.1 of

Attachment AE of this Tariff for use in the Day-Ahead Market. In the case a Resource is not

committed by the Day-Ahead Market, the mitigated Energy Offer Curve may be updated until the

Day-Ahead RUC begins. For Resources committed by the Day-Ahead Market, the mitigated

Energy Offer Curve submitted as of the close of the Day-Ahead Market will apply to the Day-

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Ahead Market on the day before the Operating Day and the RTBM on the Operating Day; for all

other Resources the mitigated Energy Offer Curve submitted at the time the Day-Ahead RUC

begins will apply to the Day-Ahead RUC on the day before the Operating Day, and the Intra-Day

RUC processes and the RTBM on the Operating Day.

A. The Energy Offer Curve conduct thresholds are as follows:

(1) For Resources committed to address a Local Reliability Issue, the conduct threshold

is a 10% increase above the mitigated Energy Offer Curve;

(2) For Resources located in a Frequently Constrained Area and not subject to Section

3.2(A)(1), the conduct threshold is a 17.5% increase above the mitigated Energy

Offer Curve;

(3) For all other Resources the conduct threshold is a 25% increase above the mitigated

Energy Offer Curve.

B. The Transmission Provider shall apply mitigation measures by replacing the Energy Offer

Curve with the mitigated Energy Offer Curve if:

(1) The Resource’s Energy Offer Curve exceeds the mitigated Energy Offer Curve by

the applicable conduct threshold; and

(2) The Resource has local market power as determined in Section 3.1; and

(3) The Resource either:

(a) Fails the Market Impact Test as described in Section 3.7, or

(b) Is manually committed by the Transmission Provider or by a local

transmission operator.

An Energy Offer below $25/MWh will not be subject to mitigation measures for economic

withholding.

C. The mitigated energy offer shall be the Resource’s short-run marginal cost of producing

energy as determined by the unit’s heat rate; fuel costs and the costs related to fuel usage,

such as transportation and emissions costs (“total fuel related costs”); and Energy Offer

Curve (“EOC”) variable operations and maintenance costs (“VOM”) as detailed in the

Market Protocols.

D. Opportunity cost shall be an estimate of the Energy and Operating Reserve Markets

revenues net of short run marginal costs for the marginal forgone run time during the

timeframe when the Resource experiences the run-time restrictions as detailed in the

Market Protocols. The run-time restrictions shall be updated as specified in the Market

Protocols, with more frequent updating to occur the fewer hours that remain available,

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consistent with the Market Protocols. The Market Participant may include in the

calculation of its mitigated Energy Offer Curve an amount reflecting the resource-specific

opportunity costs expected to be incurred under the following circumstances:

(1) Externally imposed environmental run-hour restrictions; or

(2) Physical equipment limitations on the number of starts or run-hours, as verified by

the Market Monitoring Unit and determined by reference to the manufacturer’s

recommendation or bulletin, or a documented restriction imposed by the applicable

insurance carrier; or

(3) Fuel Supply Limitations.

Resource specific opportunity costs are calculated by forecasting Locational Marginal

Prices based on futures contract prices for natural gas and the historical relationship

between the SPP system marginal Energy component of LMP and the price of natural gas,

as determined by the SPP Market Monitoring Unit. The formulas and instructions in the

price forecast model shall be determined by the SPP Market Monitoring Unit and published

in the Market Protocols as part of the Mitigated Offer Development Guidelines, updated,

as needed, by the SPP Market Monitoring Unit. Such forecasts of LMPs shall take into

account historical variability, and basis differentials affecting the Settlement Location at

which the Resource is located for the three-year period immediately preceding the period

of time in which the Resource is bound by the referenced restrictions, and shall subtract

therefrom the forecasted costs to generate energy at the Settlement Location at which the

Resource is located, as specified in more detail in Appendix G of the Market Protocols. If

the difference between the forecasted Locational Marginal Prices and forecasted costs to

generate energy is negative, the resulting opportunity cost shall be zero. The Market

Monitoring Unit will verify all Market Participants’ opportunity cost calculations for

consistency and accuracy. When the Market Monitoring Unit determines that the market

price for any period was not competitive, it will adjust the LMP forecasting process used

in the opportunity cost calculations to ensure that forecasted LMPs do not reflect non-

competitive market conditions.

The following formula shall apply to all mitigated Energy Offer Curves:

Mitigated Energy Offer ($/MWh) = HeatRate (mmBtu/MWh) *

Performance Factor * Total Fuel Related Costs ($/mmBtu) + EOC VOM ($/MWh) + Opportunity

Costs ($/MWh)

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The Market Participant shall submit heat rate curves, descriptions of how spot fuel prices and/or

contract prices are used to calculate fuel costs, variable fuel transportation and handling

costs, emissions costs, and VOM to the Market Monitoring Unit. All cost data and cost

calculation descriptions are subject to the review and approval of the SPP Market

Monitoring Unit to ensure reasonableness and consistency across Market Participants. The

information will be sufficient for replication of the mitigated Energy Offer Curve and shall

include, among other data, the following information:

(1) For fuel costs, Market Participants shall provide the Market Monitoring Unit with

an explanation of the Market Participants’ fuel cost policy, indicating whether fuel

purchases are subject to a fixed contract price and/or spot pricing and specifying

the contract price and/or referenced spot market prices. Any included fuel

transportation and handling costs must be short-run marginal costs only, exclusive

of fixed costs.

(2) For emissions costs, Market Participants shall report the emissions rate of each of

their units and indicate the applicable emissions allowance cost.

(3) For VOM costs, Market Participants shall submit VOM costs, calculated in

adherence with the Appendix G of the Market Protocols, reflecting short-run

marginal costs, exclusive of fixed costs.

Further details associated with the development, validation, and updating of these costs are

included in Appendix G of the Market Protocols.

For Demand Response Resources utilizing Behind-The-Meter Generation, the mitigated

Energy Offer Curve shall be developed in the same manner as any other generating

Resource as described above. For Demand Response Resources utilizing load reduction,

the mitigated Energy Offer Curve shall reflect the quantifiable opportunity costs associated

with the reduction, net of related offsetting increases in usage.

For Dispatchable Variable Energy Resources, the mitigated Energy Offer Curve may

include, but shall not exceed, any quantifiable costs that vary by MWh output, including

short-run incremental VOM. Mitigation will not apply to Non-Dispatchable Variable

Energy Resources in the Real-Time Balancing Market; monitoring of Energy Offers for

Non-Dispatchable Variable Energy Resources will occur.

E. Intra-day changes to the mitigated Energy Offer Curve are allowed under the following

conditions:

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1) In the event that the Transmission Provider requests that a Resource remain online

past their commitment period by the Day-Ahead Market or a RUC process, the

Market Participant may submit an updated mitigated energy offer curve that reflects

the procurement of higher cost fuel;

2) A Resource must switch fuels due to unforeseen operating conditions; or

3) A Market Participant employing the Quick-Start Resource logic as described in the

Market Protocols may update its mitigated Energy Offer Curve after the Day-Ahead

RUC clears on the day before the Operating Day, as described in Appendix G of


Intra-day changes to the mitigated energy offer curve must follow the mitigated offer

development guidelines in Appendix G of the Market Protocols. Any such changes will be

validated by the Market Monitor.

F. In all cases under this Section 3.2, cost data submitted for the development of mitigated

offers, including opportunity cost data, shall be subject to the confidentiality provisions set

forth in Section 11 of Attachment AE of this Tariff.


RR #: 263 Date: 2/3/2018

RR Title: NDVER to DVER Conversion through Incentives

SUBMITTER INFORMATION Name: Grant Wilkerson Cliff Franklin Company: Westar Energy, Inc.

Email: [email protected] [email protected]

Phone: 785.231.9331 443.226.7787

COMMENTS Westar Energy took comments from MWG members and SPP staff at the January MWG meeting. Questions were directed primarily on three questions. First, how will NDVER MPs/owners, which voluntarily re-register the unit to become dispatchable (via registration of a Dispatch Curtailment Pseudo Load “NDVER-DCPL”), be paid and how will such costs be allocated onto SPP members? Second, who would be responsible for upgrades necessary to make NDVER dispatchable if the NDVER Owner is not a Market Participant? Third, doesn’t providing incentives to NDVERs and not DVERs favorably treat similarly situated MPs inequitably? Fourth, proponents of the SPP “stick” approach forcing NDVERs to convert to DVERs asks why is this incentive necessary if such wind farms can roll in PTC & rate exposure in formulating negative resource offers (e.g. -65 $/mwh offers)? First Question: How will RR263 curtailment payment obligations be allocated?

The answer is allocation through the Real-Time RNU distribution. Westar has added language to the pre-existing RR263 to uplift SPP NDVER-DCPL payment obligations onto the RNU Distribution. Additionally, additions were made to correctly calculate the payment to NDVER-DCPL facilities for Day-Ahead and Real-Time Asset energy. Changes are highlighted to the original RR263 in yellow. Many on MWG and SPP assert the great market benefits that would result from forcing NDVER conversion to dispatchable DVERs. This constitutes an incentive for NDVERs to convert to DVER by making them whole for applicable contract payments. Like GFA carve-out transactions, Westar believes NDVERs are grandfathered from dispatchable status, which was the tariff & protocol that NDVER Purchase Power Agreements (PPAs) were based and structured around.

Second Question: Who would be responsible for upgrades necessary to make NDVER dispatchable if the NDVER Owner is not a Market Participant?

Since RR263 is voluntary for NDVER owners/buyers to become dispatchable, it leaves it to NDVER owners/buyers/MP to coordinate upgrades and contract renegotiation to make the resource dispatchable apart from SPP influence. However, RR272 which forces NDVER to DVER conversion should be changed to make the actual generator interconnection owner responsible for NDVER conversion since the AO is the only one having control over facility upgrades and operation.


Third Question: Doesn’t providing incentives to NDVERs and not DVERs favorably treat similarly situated MPs inequitably?

The premise that owners/MPs of NDVERs and DVERs wind facilities are similarly situated is simply not true. NDVER and DVER owners/MPs are no more similar than owners/MPs of GFA carve-out supply and other MPs. The primary difference is that DVER owners/buyers had SPP notice that their resource would be dispatchable, thus resource supply contracts were negotiated with that expectations. Conversely, the owners/buyers of older NDVER resources were provided notice they would not be dispatchable if the resource was constructed prior to October 15, 2012, thus construction/technology/contracts were negotiation on the resource only be curtailed by emergency OOMEs.

Fourth Question: Why is this incentive necessary if NEVER MPs can roll in PTC & rate exposure in formulating negative resource offers (e.g. -65 $/mwh offers)?

There are three answers to this question. First, forcing NDVER owners to attempt to be made-whole to NDVER PPA contract terms through market offers is risky, at best, and does not constitute an incentive for NDVERs to absorb potential repowering expenses and cost exposure (such as MMU allowable cost components) within wind offers screening which may, or may not, allow PTC and rates when evaluating when evaluating NDVER uneconomic production. Second, most NDVER owners have firm or firm w/ redispatch service approved by SPP years before many DVER interconnections, many w/o firm service or contribution to transmission deliverability. If NDVERs convert to DVER status have a greater impact on binding constraints than neighboring DVERs, the NDVER w/ firm service could be economically dispatched to 0 MW before the neighboring DVERs (having lesser impact factors and possibly having no transmission service or contribution to transmission deliverability) are allowed by SCED at full wind output. This doesn’t seem fair or equitable. Third, dispatch of wind resources can restore local area LMPs favoring other resources having less impact constraints. When the LMP price is restored and curtailment of DVERs can be deployed by SCED back to their full output capability the DVER ramp constrained to 20% of the unit rating. This is an advantage for wind resources not curtailed. If older wind resources struggle to follow dispatch instruction, the 20% ramp restriction and URD could become an issue for older NDVER resource owners having technologies not built for 5-minute economic dispatch.

PROPOSED REVISION

Market Protocols

1. Glossary

….


A measurable load that is capable of being reduced at the instruction of the SPP operator and subsequently increased at the instruction of the SPP operator that is identified in the registration of a Dispatchable Demand Response Resource or a Block Demand Response Resource.

….


A Variable Energy Resource that is capable of being incrementally dispatched by the Transmission Provider.

….


A Variable Energy Resource that is not capable of being incrementally dispatched down by the Transmission Provider.

Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load – (NDVER-DCPL)

After a Market Participant (MP) has upgraded a Non-Dipatchable Variable Energy Resource (NDVER) to accept 5-minute economic/reliability dispatch instructions from SPP, the MP may register a Dispatch Curtailment Pseudo Load NDVER-DCPL so the MP can be paid by SPP for NDVER curtailments without SPP having to issue an OOME instruction. The NDVER-DCPL will represent a MP capacity/price offer for SPP to using in clearing curtailment NDVER MWs.. During emergencies or reliability issues which SCED can’t solve, SPP shall continue to issue OOME instructions to NDVERs.

SPP shall clear NDVER-DCPL curtailment MWs for the NDVER using the negated NDVER LMPi.. SPP shall settle the NDVER-DCPL based NDVER curtailed MWs at a negated NDVER LMPi or negated NDVER MCP price based upon the NDVER-DCPL offer curves. Self or curtailment more than SPP dispatch instructions will not be cleared by SPP.

-….

4.5.3.4 GFA Carve Out or FSE Uplift

GFA Carve Out or FSE Schedules result in removal of the energy, congestion, and marginal losses for the transaction from settlement statements. SPP will capture the congestion charges and marginal loss charges related to the GFA Carve Outs or FSEs. These charges will be offset by the ARR/TCR settlement that would have been claimed for the GFA Carve Out or FSE under the normal ARR/TCR process and the distribution of the Marginal Loss Overcollection funds. Candidate ARRs associated with the GFA Carve Out or FSE service shall not be nominated for a product period if, based upon the twelve preceding months for which congestion data is available, such ARR, had it been converted to a TCR, would have resulted in a TcrFundHrlyAmt net charge to the holder of the TCR over that product period, as defined for the annual ARR allocation process. However, until twelve months of Integrated Marketplace data is available, SPP will use relevant data from both the EIS Market and the Integrated Marketplace to estimate whether the result is a net charge.

(i) For the MW capacity associated with each FSE, the sink for the ARR/TCR shall be the (1) load Settlement Location within the UMZ, (2) interface with an external Balancing Authority, or (3) FSE Transfer Point, as appropriate. For ARR/TCR activity from FSE Transfer Points to load external to the UMZ but internal to the Transmission Provider, the normal ARR/TCR process is available to the applicable Market Participants from the FSE Transfer Point to the load consistent with the transmission service reservation.

4.5.4 Calculation of LMPs, LMP Components and MCPs

SPP uses a co-optimized SCED model to compute Locational Marginal Prices (LMPs) for Energy at PNodes. The LMPs are then mapped to Settlement Locations in the commercial model. The SCED model also computes Market Clearing Prices (MCPs) for Regulation-Up Service, Regulation-Up Mileage, Regulation-Down Service, Regulation-Down Mileage, Spinning Reserve and Supplemental Reserve on a Reserve Zone basis. For the DA Market, LMPs and MCPs are calculated on an hourly basis. For the RTBM, LMPs and MCPs are calculated for each 5-minute Dispatch Interval. Inputs to SCED for the DA Market

are as described under Section 4.3.1.1 and inputs to SCED for the RTBM are as described under Section 4.4.2.2. The following subsections further describe how LMPs, LMP Components and MCPs are calculated.

4.5.4.1 LMP Calculations and LMP Components

The LMP at a PNode is the cost of delivering an incremental MW of energy at that specific PNode, while satisfying all operational constraints where such cost will include applicable Demand Curve prices if the incremental MW of energy causes a corresponding increase in shortage conditions where such Demand Curve prices and shortage conditions are as described under Section 4.1.5. The LMP at any PNode is the sum of three components; the marginal costs of Energy (Marginal Energy Component or MEC), the marginal cost of losses (Marginal Loss Component or MLC), and the marginal cost of congestion (Marginal Congestion Component or MCC).

LMP Components at PNode i are calculated based upon the following formulas:

LMPi = MEC + MLCi + MCCi

Where:


(2) MLCi is the component of LMPi representing the marginal cost of losses at PNode i relative to the Reference Bus;

(3) MCCi is the component of LMPi representing the marginal cost of congestion at ENode i relative to the Reference Bus; and

(4) The Reference Bus represents the network Distributed Load Bus.

(5) NDVER-DCPL curtailment load locations are always linked to a NDVER resource. The NDVER-DCPL LMP shall be the negative of the linked NDVER LMP where,


4.5.4.1.1 Marginal Losses Component Calculation

The MLCi at each PNode i is defined by the following equations:

MLCi = -MLSFi * MEC

MLSFi = ∂ (SPP Losses) / ∂ Pi

Where:

(1) SPP Losses = SPP transmission system losses;

(2) MLSFi = Marginal Loss Sensitivity Factor at PNode i;



(4)(5) NDVER-DCPL pseudo load will not be considered within MLCi since it represents a curtailment of NDVER generation and does not represent actual physical load.

The MLSFi is a linearized estimate of the change in SPP transmission losses that will result from a 1 MW injection at PNode i coupled with a corresponding withdrawal at the Reference Bus to maintain global power balance (the withdrawal at the Reference Bus will generally be higher or lower than 1 MW since there will be a change in losses). Marginal loss sensitivity factors are dependent on topology, node injections and node withdrawals, and are only considered constant within a small deviation from a fixed operating point.

4.5.4.1.2 Marginal Congestion Component Calculation

The MCC at each PNode i is defined by the following equations

MCCi = - ( ∑=

K

k 1Sensik * SPk )

Sensik = ∂ Flowk / ∂ Pi

Where:

(1) K is the number of transmission constraints;

(2) Sensik is the linearized estimate of the change in the constraint k flow resulting from an incremental energy injection at PNode i coupled with an incremental energy withdrawal at the Reference Bus;

(3) Flowk = Calculated flow for constraint k;

(4) SPk = is the Shadow Price of constraint k;


4.5.4.1.3 Marginal Energy Component Calculation

The MEC is defined as the computed LMP at the Reference Bus. By definition, MCC and MLC components are zero at the Reference Bus.

4.5.4.2 MCP Calculations

The MCP represents the cost of supplying an increment of operating reserve, taking into account lost opportunity cost and is composed of the marginal Operating Reserve costs and marginal costs associated with Operating Reserve scarcity. The DA Market and RTBM MCPs for Regulation-Up Service, Spinning Reserve and Supplemental Reserve at a Reserve Zone for Resources with cleared Regulation-Up Service, Spinning Reserve and/or Supplemental Reserve at that Reserve Zone are equal to the summation of the applicable Shadow Prices associated with each Operating Reserve constraint. This type of MCP formulation is referred to as “price-cascading”. MCPs applied to Excess Regulation-Up Mileage, Unused Regulation-Up Mileage. Excess Regulation-Down Mileage and Unused Regulation-Down Mileage are calculated for the RTBM only as described in (2) and (3) below.

(1) There are four sets of constraints: (i) an Operating Reserve constraint which is set equal to the sum of the Contingency Reserve requirement and the Regulation-Up requirement; (ii) a Regulation-Up Service plus Spinning Reserve constraint which is set equal to the sum of the Regulation-Up requirement and the Spinning Reserve requirement; and (iii) a Regulation-Up Service constraint which is set equal to the Regulation-Up requirement; and (iv) a Regulation-Down Service constraint which is set equal to the Regulation-Down requirement. These constraints apply on both a system-wide basis and a Reserve Zone basis. MCPs for each Reserve Zone are calculated as follows:

(a) The zonal Regulation-Up Service MCP is equal to sum of the system-wide and zonal Shadow Prices for the Regulation-Up constraint, Regulation-Up Service plus Spinning Reserve constraint and the Operating Reserve constraint;

(b) The zonal Spinning Reserve MCP is equal to the sum of the Shadow Prices for the system-wide and zonal Regulation-Up Service plus Spinning Reserve constraint and the Operating Reserve constraint;

(c) The zonal Supplemental Reserve MCP is equal to the sum of the Shadow Price of the system-wide and zonal Operating Reserve constraint and

(d) The zonal Regulation-Down Service MCP is equal to sum of the system-wide and zonal Shadow Prices for the Regulation-Down constraint.

(2) RTBM MCPs for Expected Regulation-Up Mileage are set equal to the highest Regulation-Up Mileage Offer of all Resource’s economically cleared to provide Regulation-Up Service in a particular Dispatch Interval. For Resource’s submitting a Regulation-Up Service Dispatch Status of “Fixed”, the cleared amount of Regulation-Up Service MW must be greater than the submitted “Fixed” MW in order to be considered economically cleared;

(3) RTBM MCPs for Expected Regulation-Down Mileage are set equal to the highest Regulation-Down Mileage Offer of all Resource’s economically cleared to provide Regulation-Down Service in a particular Dispatch Interval. For Resource’s submitting a Regulation-Down Service Dispatch Status of “Fixed”, the cleared amount of Regulation-Up Service MW must be greater than the submitted “Fixed” MW in order to be considered economically cleared;

(4) During times of Operating Reserve scarcity, MCPs will be impacted by Scarcity Prices as described under Section 4.1.5;

(5) The MCP formulations allow for the substitution of higher quality reserve products for lower quality reserve products to meet the Operating Reserve requirements to the extent that there is excess higher quality Operating Reserve available and these excess amounts provide a more economical solution. In the case of allowing Regulation-Up Service to substitute for Contingency Reserve, only the Regulation-Up Offers will be used in the evaluation. Allowing for this substitution in combination with the “price-cascading” rules described in (1) above ensures that the clearing for Operating Reserve produces Regulation-Up Service MCPs that are greater than or equal to Spinning Reserve MCPs and Spinning Reserve MCPs that are greater than or equal to Supplemental Reserve MCPs;

(a) Regulation-Down is not eligible to substitute for Spinning Reserve and Supplemental Reserve. Therefore, Resource Regulation-Down Service MCPs can be less than Spinning Reserve and/or Supplemental Reserve MCPs.

(6) The MCPs for the various Operating Reserve products as determined by the market clearing process will be sufficient to cover the Offer costs of each Resource as well as the opportunity costs incurred to allocate a portion of the Resource capacity to the supply of the corresponding Operating Reserve product in lieu of another product. The recovery of both offered cost and opportunity costs via Market Clearing Prices is inherent in the co-optimized SCED formulations, thus the separate calculation of opportunity costs is unnecessary.

(7) NDVER-DCPL curtailment load locations are always linked to a NDVER resource. The NDVER-DCPL MCP shall be the negative of the linked NDVER MCP where,

NDVER-DCPLk MCP = (NDVERk MCP ) ( -1 )

4.5.5 Settlement Location LMPs and LMP Components

For Settlement Locations that are associated with more than one PNode, the following calculations are performed to calculate the Settlement Location LMPs and the associated LMP Components. The LMPs for Settlement Locations associated with a single PNode are those LMPs directly calculated by the DA Market software as described under Section 4.3.1.3 and the RTBM software as described under Section 4.4.2.3.4. All nodal LMPs are subject to the price correction procedures described under Section 6.6.1. Resource Hub LMPs and the associated LMP Components will be calculated using the same methodology as Trading Hubs as described in Section 4.5.5.1.

4.5.8.1 Day-Ahead Asset Energy Amount

(1) A DA Market credit or charge for net physical Energy activity associated with load and Resources, adjusted for Bilateral Settlement Schedules for Energy, is calculated at each Settlement Location for each Asset Owner for each Hour. The net amount is calculated as follows:

#DaEnergyHrlyAmt a, s, h = DaLmpHrlyPrc s, h * ( DaClrdHrlyQty a, s, h

- ∑t

DaEnFinHrlyQty a, s, h, t )

IF DaDevCapbltyHrlyQty a, s, h > DaClrdHrlyQty a, s, h

THEN

#DaEnergyHrlyAmt a, s, h = DaLmpHrlyPrc s, h * (-1) * ( DaDevCapbltyHrlyQty a, s, h - DaClrdHrlyQty a, s, h)

+ DaLmpHrlyPrc s, h * DaClrdHrlyQty a, s, h - ∑t


(2) For each Asset Owner, a daily amount is calculated at each Settlement Location. The net daily amount is calculated as

follows:

DaEnergyDlyAmt a, s, d = ∑h

DaEnergyHrlyAmt a, s, h

(3) For each Asset Owner associated with Market Participant m, a daily amount is calculated. The net daily amount is calculated as follows:

DaEnergyAoAmt a, m, d = ∑s

DaEnergyDlyAmt a, s, d

(4) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The net amount is calculated as follows:

DaEnergyMpAmt m, d = ∑a

DaEnergyAoAmt a, m, d

Field Code Changed

(5) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates hourly sales volume and prices associated with this Charge Type for each Asset Owner as follows:

(a) #EqrDaAssetEnergyHrlyQty a, s, h

= (-1) * Min(0, DaClrdHrlyQty a, s, h - ∑t


(b) IF #EqrDaAssetEnergyHrlyQty a, s, h > 0 THEN #EqrDaAssetEnergyHrlyPrc a, s, h = DaLmpHrlyPrc s, h


Unit

Settlement Interval

Definition

DaEnergyHrlyAmt a, s, h $

Hour Day-Ahead Asset Energy Amount per AO per Settlement Location per Hour - The DA Market amount to AO a for net cleared Resource’s and load, net of Bilateral Settlement Schedules for Energy, at Settlement Location s for the Hour.

DaLmpHrlyPrc s, h $/MWh

Hour Day-Ahead LMP - The DA Market LMP at Settlement Location s for the Hour.

DaClrdHrlyQty a, s, h MWh

Hour Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour - The total net quantity of Energy represented by AO a’s DA Market cleared Resource Offers and Demand Bids in the DA Market at Settlement Location s for the Hour.

DaEnFinHrlyQty a, s, h, t MWh

Hour Day-Ahead Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour - The quantity specified by the buyer AO and seller AO in a DA Market Bilateral Settlement Schedule for Energy at Asset Settlement Location s, for each transaction t, for the Hour. The

Variable

Unit

Settlement Interval

Definition

buyer AO quantity is a positive value and the seller AO quantity is a negative value.

DaEnergyDlyAmt a, s, d $

Operating Day

Day-Ahead Asset Energy Amount per AO per Settlement Location per Operating Day - The DA Market amount to AO a for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy, at Settlement Location s for the Operating Day.

DaEnergyAoAmt a, m, d $

Operating Day

Day-Ahead Asset Energy Amount per AO per Operating Day - The DA Market amount to AO a associated with Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day.

DaEnergyMpAmt m, d $

Operating Day

Day-Ahead Asset Energy Amount per Market Participant per Operating Day - The DA Market amount to Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day.

EqrDaAssetEnergyHrlyQty a, s, h

MWh Hour Day-Ahead Electric Quarterly Reporting Asset Energy Sales per AO per Settlement Location per Hour – AO a’s DA Market Energy sales at Resource Settlement Location s, net of Bilateral Settlement Schedules, in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.

EqrDaAssetEnergyHrlyPrc a, s, h

$/MWh Hour Day-Ahead Electric Quarterly Reporting Asset Energy Sales Prices per AO per Settlement Location per Hour – AO a’s DA Market Energy sales price at Resource Settlement Location s, net of Bilateral Settlement Schedules, in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.

Variable

Unit

Settlement Interval

Definition

DaDevCapbltyHrlyQty a, s, h MW Hour Day-Ahead Variable Energy Resource output capability per AO per Settlement Location per Dispatch hour per Transaction – The value described under Sections 4.5.4.1(5), 4.5.12(1)(b.5), and wind resource output forecast as described under Section 4.1.2.2.

a none none An Asset Owner. s none none A Settlement Location. t none none A single tagged Interchange Transaction, a single

virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction.

h none none An Hour. d none none An Operating Day. m none none A Market Participant.

….

4.5.9.1 Real-Time Asset Energy Amount

(1) The Real-Time Asset Energy Amount can be either a credit to an Asset Owner or a charge to an Asset Owner and is calculated on a net basis at each Settlement Location for:

(a) The difference between actual metered supply MWh amounts in a Dispatch Interval and cleared Resource Offers in the DA Market;

(b) The difference between actual metered demand MWh amounts in a Dispatch Interval and all cleared Demand Bids in the DA Market; and

(c) Real-Time Bilateral Settlement Schedules for Energy in a Dispatch Interval.

The net amount to each Asset Owner (AO) for each Settlement Location in a Dispatch Interval is calculated as follows:

#RtEnergy5minAmt a, s, i = RtLmp5minPrc s, i

* [ (RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h )

- ∑t

RtEnFinHrlyQty a, s, t, h ] / 12

IF RtDevCapblty5minQty a, s, i > RtBillMtr5minQty a, s, i

THEN

RtEnergy5minAmt a, s, i = RtLmp5minPrc s, i

* [ (RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h )

- ∑t

RtEnFinHrlyQty a, s, t, h ] / 12

+

(( (–1) * RtLmp5minPrc s, i) * ( RtDevCapblty5minQty a, s, i – RtBillMtr5minQty a, s, i))

–

(–1)*DaLmpHrlyPrc s, h * (DaDevCapbltyHrlyQty a, s, h – DaClrdHrlyQty a, s, h))

) / 12

Field Code Changed

Where,

(a) The 5-minute billable meter determinant at the Settlement Location level is the sum of the 5-minute billable meter determinants at the Meter Data Submittal Location level as shown in the formula below. Most Settlement Locations will be comprised of only one Meter Data Submittal Location, but in certain cases a single Settlement Location will represent multiple Meter Data Submittal Locations, each of which is in a separate Settlement Area. Since the calibration function must be performed within Settlement Area boundaries, it is done before summing the data to the Settlement Location level. The 5-minute determinants are expressed in terms of levelized MW at both the Settlement Location and Meter Data Submittal Location level.

RtBillMtr5minQty a, s, i = ∑ml

RtMlBillMtr5minQty a, ml, i

(b) The 5-minute billable meter determinant at the Meter Data Submittal Location level is the sum of the 5-minute adjusted meter determinant and the 5-minute calibration meter determinants at the Meter Data Submittal Location level as shown in the formula below. Both 5-minute determinants are expressed in terms of levelized MW.

RtMlBillMtr5minQty a, ml, i =

RtAdjMtr5minQty a, ml, i + RtCalMtr5minQty a, ml, i

(c) For Resource and load assets, the 5-minute adjusted meter determinant is a hierarchal selection among 1) 5-minute submitted actual meter reading, 2) profiled hourly submitted actual meter reading and 3) default 5-minute state estimator value. Registration records whether 5-minute or hourly meter data submittals are selected. The methodologies are mutually exclusive for any given period. Market Participants who choose to submit their actual hourly meter reading into 5-minute intervals must use a profiling method consistent with the method described below using a data source as described in Appendix D Section D.10.1.1. Under the Marginal Loss

approach, it is assumed that meter submissions, with the exception of those with a “top-down load” relationship to the Settlement Area – generally those for which a top-down calculation is used – are net of transmission losses. Losses will be backed out of load submittals for the “top-down load”. For Demand Response Resources, the hierarchy is the same for submitted data, but instead of defaulting to the State Estimator data, the Resource output is calculated as the maximum of zero or the difference between (i) and (ii) below. If the baseline hourly load profile of the DRL was not submitted, the State Estimator snapshot will be used for this value in (i) below. (i) The minimum of (1) the hourly baseline load profile of the DRL submitted for the Demand Response Load,

or (2) the State Estimator snapshot for the Demand Response Load for the 5 minute interval immediately preceding the first dispatch interval (i = -1) in which the Demand Response Resource is dispatched (for a BDR, this is the dispatch interval immediately preceding the hour in which the BDR was committed. For a DDR, it is the dispatch interval immediately preceding the first dispatch interval in which the DDR receives a dispatch instruction greater than zero.) and

(ii) The Adjusted Meter Quantity for the DRL for each 5 minute interval. Registration records whether meter submittals are permitted or if the Demand Response Resource must rely solely on the calculated Resource output. For loads in which a Demand Response Resource is imbedded within a Settlement Location, the response is added to the load meter data “grossing-up” the MW to avoid introducing deviation between DA Market cleared Energy and the billable meter quantity. 5-minute adjusted meter, state estimator, SCADA and gross-up determinants are expressed in terms of levelized MW and both hourly and 5-minute submitted actual determinants are in terms of MWh. The formula for the 5-minute adjusted meter determinant is shown below.

IF EXISTS { RtActMtr5minQty a, ml, i } THEN

#RtAdjMtr5minQty a, ml, i =

RtActMtr5minQty a, ml, i * 12 + RtLoadGrossUp5minQty a, s, ml, i

- {IF TOPDOWNLOAD(ml) THEN RtSELoss5minQty sa, i , ELSE 0 }

ELSE

IF EXISTS { RtActMtrHrlyQty a, ml, h } THEN

#RtAdjMtr5minQty a, ml, i = RtSE5minQty a, ml, i

+ { ( RtActMtrHrlyQty a, ml, h -∑i

RtSE5minQty a, ml, i / 12)

* {IF (∑i

ABS (RtSE5minQtya, ml, i ) > 0 THEN [ABS (RtSE5minQtya, ml, i) / ∑i

ABS ( RtSE5minQty a,

ml, i ) ], ELSE 1 /12 } * 12 }

+ RtLoadGrossUp5minQty a, s, ml, i

- { IF TOPDOWNLOAD(ml) THEN RtSELoss5minQty sa, i , ELSE 0 }

ELSE

IF { DRR } THEN


MAX [( MIN ( RtBaseLineHrlyQtya, ml(drl) , h , RtSE5minQtya, ml(drl), i = -1 )

– RtAdjMtr5minQtya, ml(drl), i ) , 0 ] * (-1)

ELSE


RtSE5minQty a, ml, i + RtLoadGrossUp5minQty a, s, ml, i

(d) The 5-minute load gross-up determinant is the inverse of the 5-minute adjusted meter determinant for the Demand Response Resource which is behind the meter of the load. The 5-minute load gross-up determinant is expressed in terms of levelized MW. The formula for the 5-minute load gross-up determinant is shown below.

RtLoadGrossUp5minQty a, s, ml, i =

∑)(drrmlRtAdjMtr5minQty a, ml(drr), i * (-1)

(e) The 5-minute calibration meter determinant is the hourly quantity, profiled by State Estimator data into 5-minute intervals as shown in the formula below. The 5-minute calibration meter determinant is expressed in terms of levelized MW. The formula for the 5-minute calibration meter determinant is shown below.

#RtCalMtr5minQty a, ml, i =

If RtCalMtrHrlyQty a, ml, h = 0

THEN 0

ELSE

RtSE5minQty a, ml, i

+ { (RtCalMtrHrlyQty a, ml, h - ∑i

RtSE5minQty a, ml, i / 12)

* {IF ∑i

ABS(RtSE5minQty a, ml, i > 0 THEN [ ABS(RtSE5minQty a, ml, i ) / ∑i

ABS(RtSE5minQty a,

ml, i ) ] , ELSE 1/12} * 12 }

(f) The hourly calibration meter determinant is the weighted distribution of Settlement Area residual among load in the Settlement Area (excluding Resources and load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area). The hourly calibration meter determinant is expressed in terms of levelized MW. The Statutory Load Obligations in Western-UGP will be exempted fro calibration. The formula for the hourly calibration meter determinant is shown below.

IF IsPsgiPsli (ml)

THEN

#RtCalMtrHrlyQty a, ml, h = 0

ELSE

#RtCalMtrHrlyQty a, ml, h = RtResMtrHrlyQty sa, h

* [ MAX ( ( ( 1 – AoIsExemptLoadDlyFlg a, ml, d ) * RtAdjMtrHrlyQty sa, a, ml, h ) , 0 )

/ ∑ml

MAX ( ( ( 1 - AoIsExemptLoadDlyFlg a, ml, d ) * RtAdjMtrHrlyQty sa, a, ml, h ) , 0 ) ]

(g) The hourly adjusted meter determinant is the sum of the 5-minute adjusted meter determinant divided by 12. The hourly adjusted meter determinant is expressed in terms of levelized MW. The formula for the hourly adjusted meter determinant is shown below.

#RtAdjMtrHrlyQty a, ml, h = ∑i

RtAdjMtr5minQty a, ml, i / 12

(h) The hourly residual load determinant is the net difference between generation & load (excluding Resources and load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area), interchange and losses per Settlement Area. Hourly Net Actual Interchange is derived as the sum of the hourly metering submitted for aggregate ties between interconnected Settlement Areas. Missing tie values are replaced with State Estimator values. The hourly residual determinant is expressed in terms of levelized MW. The formula for the hourly residual load determinant is shown below.

RtResMtrHrlyQty sa, h = (∑a∑ml

{ IF IsPsgiPsli (ml) THEN 0 ELSE RtAdjMtrHrlyQty sa ,a, ml, h }

+ RtSaNetActIchngHrlyQty sa, h + ∑i

RtSELoss5minQty sa, i / 12) * (-1)

(2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The amount is calculated as follows:

RtEnergyHrlyAmt a, s, h = ∑i

RtEnergy5minAmt a, s, i


RtEnergyDlyAmt a, s, d = ∑h

RtEnergyHrlyAmt a, s, h


RtEnergyAoAmt a, m, d = ∑s

RtEnergyDlyAmt a, s, d

(5) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The daily amount is calculated as follows:

RtEnergyMpAmt m, d = ∑a

RtEnergyAoAmt a, m, d

(1) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates net Dispatch Interval sales volume in excess of DA Market amounts and associated prices and calculates net Dispatch Interval purchases when Real-Time sales volume less than DA Market sales volume and associated prices that are associated with this Charge Type for each Asset Owner as follows:

(a) #EqrRtAssetEnergy5minQty a, s, i =

Max ( 0, -1 * [ (RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h )

- ∑t

RtEnFinHrlyQty a, s, t, h ] / 12)

+

{ IF #EqrDaAssetEnergyHrlyQty a, s, h > 0 THEN

Min ( 0, -1 * [ (RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h )

- ∑t

RtEnFinHrlyQty a, s, t, h ] / 12) }

(b) IF #EqrRtAssetEnergy5minQty a, s, i < > 0

THEN

#EqrRtAssetEnergy5minPrc a, s, i = RtLmp5minPrc s, i

The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

RtEnergy5minAmt a, s, i $ Dispatch Interval

Real-Time Energy Amount per AO per Settlement Location per Dispatch Interval - The amount to AO a for deviations between Real-Time actual Energy amounts and net cleared energy offers and bids at Settlement Location s for the Dispatch Interval i.

RtLmp5minPrc s, i $/MW Dispatch Interval

Real-Time LMP - The RTBM LMP at Settlement Location s for Dispatch Interval i.

DaClrdHrlyQty a, s, h MWh Hour Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1.


Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The Dispatch Interval metered quantities for AO a Resources and load at Settlement Location s in Dispatch Interval i used by SPP for settlement purposes.

RtActMtr5minQty a, ml, i MWh Dispatch Interval

Real-Time Actual Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval metered quantity, in MWh, for AO a’s Resources and load directly submitted by the Market Participant.

RtActMtrHrlyQty a, ml, h MWh Hour Real-Time Actual Meter Quantity per AO per Meter Data Submittal Location per Hour - The hourly metered quantity, in MWh, for AO a’s Resources and load directly submitted by the Market Participant.

RtMlBillMtr5minQty a, ml, i MW Dispatch Interval

Real-Time Billing Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval RtAdjMtr5minQty a, ml, i quantities adjusted to account for calibration Energy for AO a load at Meter Location ml in Dispatch Interval i.

RtCalMtr5minQty a, ml, i

MW Dispatch

Interval Real-Time Calibration Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval calibration quantities calculated by SPP for AO a at load at Meter Data Submittal Location ml in Dispatch Interval i.

RtCalMtrHrlyQty a, ml, h MWh Hour Real-Time Calibration Meter Quantity per AO per Meter Settlement Location per Hour- The Dispatch Interval calibration Energy quantities calculated by SPP for AO a at load at Meter Data Submittal Location ml in Hour h.

AoIsExemptLoadDlyFlg a,

ml, d None None Asset Owner Load is Exempt from Calibration Flag per AO per

MDSL per Operating Day. – This flag is set to 1 when the Asset Owner has Load that is exempt from Calibration.

RtLoadGrossUp5minQty a,

s, ml, i MW Dispatch

Interval Real-Time Load Gross Up per AO per Meter Settlement Location per Dispatch Interval - The Dispatch Interval load gross up associated with a Demand Response Reserve for AO a at load Meter Data Submittal Location ml associated with Settlement Location s in Dispatch Interval i.

RtSE5minQty a, ml, i MW Dispatch Interval

Real-Time State Estimator Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval State Estimator value for AO a at Meter Data Submittal Location ml in Dispatch Interval i.

RtBaseLineHrlyQtya, ml(drl) ,

h MWh Hour Real-Time Base Line Load Quantity per AO per Demand

Response Load Meter Data Submittal Location per Hour – The estimated consumption value associated with AO a’s Demand Response Load as submitted prior to Operating Hour h.

RtSELoss5minQty sa, i MW Dispatch Interval

Real-Time State Estimator Losses per AO per Settlement Area per Dispatch Interval - The Dispatch Interval State Estimator total losses value for Settlement Area sa in Dispatch Interval i.

RtResMtrHrlyQty sa, h MWh Hour Real-Time Residual Load per Settlement Area per Hour - The hourly Residual Load for Settlement Area sa in Hour h.

IsPsgiPsli (ml) None None A Logical operation of the Meter Data Submittal Location to determine if it is of type PSGI or PSLI – a Resource or load pseudo-tied into SPP, but not accounted for in the submittal of interchange of any Settlement Area

RtSaNetActIchngHrlyQty sa, h

MWh Hour Real-Time Net Actual Interchange per Settlement Area per Hour - The sum of hourly actual interchange values submitted for Settlement Area sa in Hour h.

RtAdjMtr5minQty a, ml, i MW Dispatch Interval

Real-Time Adjusted Actual Meter Quantity per AO per Meter Data Submittal Location per Dispatch Interval - The Dispatch Interval metered quantity, in MW, for AO a’s Resources and load calculated by SPP to account for load adjustments related to Demand Response Resources and to calculate a default value if RtActMtrHrlyQty a, ml, h or RtActMtr5minQty a, ml, i is not submitted.

RtAdjMtrHrlyQty sa, a, ml, h MWh Hour Real-Time Adjusted Actual Meter Quantity per AO per Meter Data Submittal Location per Hour - The hourly metered quantity, in MWh, for AO a’s Resources and load calculated by SPP to account for load adjustments related to Demand Response Resources and to calculate a default value if RtActMtrHrlyQty a, ml, h or RtActMtr5minQty a, ml, i is not submitted for AO a at Meter Data Submittal Location ml in Settlement Area sa in Hour h.

RtEnFinHrlyQty a, s, t, h MWh Hour Real-Time Asset Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The amount specified by the buyer AO and seller AO in a RTBM Bilateral Settlement Schedule for Energy at Asset Settlement Location s, for transaction t, for the Hour. The buyer AO amount is a positive value and the seller AO amount is a negative value.

RtEnergyHrlyAmt a, s, h $ Hour Real-Time Energy Amount per AO per Settlement Location per Hour - The amount to AO a for deviations between Real-Time actual Energy amounts and net cleared energy offers and bids at Settlement Location s for the Hour.

RtEnergyDlyAmt a, s, d $ Operating Day

Real-Time Energy Amount per AO per Settlement Location per Operating Day - The amount to AO a for deviations between Real-Time actual Energy amounts and net cleared energy offers and bids at Settlement Location s for the Operating Day.

RtEnergyAoAmt a, m, d $ Operating Day

Real-Time Energy Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for deviations between Real-Time actual Energy amounts and net cleared energy offers and bids for the Operating Day.

RtEnergyMpAmt m, d $ Operating Day

Real-Time Energy Amount per MP per Operating Day - The amount to MP m for deviations between Real-Time actual Energy amounts and net cleared energy offers and bids for the Operating Day.

EqrRtAssetEnergy5minQty a, s, i

MWh Dispatch Interval

Real-Time Electric Quarterly Reporting net Asset Energy Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM Energy sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead, net of Bilateral Settlement Schedules, in Dispatch Interval i or AO a’s RTBM Energy purchase at Resource Settlement Location s created when the actual Real-Time output is less than the amount cleared Day-Ahead, net of Financial Schedules, in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.

EqrRtAssetEnergy5minPrc a, s, i

$/MWh Dispatch Interval

Real-Time Electric Quarterly Reporting net Asset Energy Transactions Prices per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtAssetEnergy5minQty a, s, i quantities in Dispatch Interval i for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.

RtDevCapblty5minQty a, s, i MW Dispatch Interval

Real-Time Variable Energy Resource output capability per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Sections 4.5.4.1(5), 4.5.12(1)(b.5), and wind resource output forecast as described under Section 4.1.2.2.

a none none An Asset Owner. h none none An Hour. i none none A Dispatch Interval. s none none A Settlement Location.

t none none A single tagged Interchange Transaction, a single virtual energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction.

ml(drr) none none A Demand Response Resource Meter Data Submittal Location. ml(drl) none none A Demand Response Load Meter Data Submittal Location. sa none none A Settlement Area. ml none none A Meter Data Submittal Location. d none none An Operating Day. m none none A Market Participant.

Market Protocols for SPP Integrated Marketplace

….

4.5.12 Revenue Neutrality Uplift Distribution Amount

(1) A charge or credit will be calculated at each Settlement Location for each Asset Owner for each hour in order for SPP to remain revenue neutral. Contributors to revenue non-neutrality include:

(a) Rounding errors (related to the calculation of all Charges/Credits);

(b) Inadvertent Interchange (as calculated as shown in equation b.3 below);

(c) Joint Operating Agreement Charges/Credits;

(d) RTBM congestion (as calculated as shown in equation b.4 below);

(e) RTBM Regulation Deployment Adjustment;

(f) Make-Whole payments for Out-of-Merit Energy; and

(g) Miscellaneous Charges/Credits

(g)(h) SPP Payment obligations for cleared Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load – “NDVER-DCPL” (as calculated as shown in equation b.5 below).

The amount will be determined by multiplying the Asset Owner hourly determinant by a daily Revenue Neutrality Uplift (RNU) rate. The Asset Owner hourly determinant is equal to the sum that Asset Owner’s actual generation MWh, actual load MWh, actual Interchange Transaction MWh, DA Market cleared Virtual Offer MWh and DA Market cleared Virtual Bid MWh for the Hour, where all of these values are assumed to be positive values.

The calculation of the Revenue Neutrality Uplift (RNU) for each Asset Owner and Settlement Location in the SPP footprint can result in residual amounts due to rounding. The sum of the residual amounts due to rounding can result in SPP not being revenue neutral for the Operating Day. The residual amounts for each Operating Day will be summed on a yearly basis. The annual residual amount, whether a credit or a charge, will be uplifted to the Asset Owners and Settlement Locations. On Operating Day March 1 of every year, SPP will uplift the annual residual amount with a Miscellaneous Adjustment to the Asset Owners and Settlement Locations.



#RtRnuHrlyAmt a, s, h = ( RtRnuSppDistRate d * RtRnuDistHrlyQty a, s, h ) * (-1)

Where,

(a) #RtRnuDistHrlyQty a, s, h = (∑i

ABS (RtBillMtr5minQty a, s, i ) / 12) + (∑i∑

t[ (ABS

(RtImpExp5minQty a, s, i, t )/12) * (1 – RsgCrdFlgt ) ]) + (∑t

ABS (DaClrdVHrlyQty

a, s, h, t))

(b) #RtRnuSppDistRate d =

( DaRevInadqcSppAmt spp, d + RtRevInadqcSppAmt spp, d

+ RtOomSppAmt spp, d + RtRegAdjSppAmt spp, d

+ RtJoaSppAmt spp, d - RtNetInadvertentSppAmt spp, d

+ RtCongestionSppAmt spp, d + RtDevCurtlSppAmt spp, d) / RtRnuDistSppQty

spp, d

Where,

RtOomSppAmt spp, d = ∑m

RtOomMpAmt m, d

RtRegAdjSppAmt spp, d =∑m

RtRegAdjMpAmt m, d

RtJoaSppAmt spp, d =∑a∑

h∑

fRtJoaHrlyAmt a, h, f

RtRnuDistSppQty spp, d =∑a∑

s∑

hRtRnuDistHrlyQty a, s, h

(b.1) DaRevInadqcSppAmt spp, d =


∑m

( DaEnergyMpAmt m, d + DaNEnergyMpAmt m, d + DaVEnergyMpAmt m, d


+ DaRegUpMpAmt m, d + DaSpinMpAmt m, d + DaSuppMpAmt m, d

+ DaRegDnMpAmt m, d + DaRegUpDistMpAmt m, d + DaSpinDistMpAmt m, d

+ DaSuppDistMpAmt m, d + DaRegDnDistMpAmt m, d + DaMwpMpAmt m, d

+ DaMwpDistMpAmt m, d + TcrFundMpAmt m, d + TcrUpliftDlyMpAmt m, d

+ TcrAucTxnMpAmt m, d + ArrAucTxnMpAmt m, d

+ ArrUpliftMpAmt m, d + DaDRMpAmt m, d + DaDRDistMpAmt m, d ) - ECFDlyAmt d - ARFDlyAmt d + GFARevInadqcSppAmt spp, d

- ∑h

DaOclHrlyAmt h

(b.2) RtRevInadqcSppAmt spp, d =

∑m

( RtEnergyMpAmt m, d + RtNEnergyMpAmt m, d + RtVEnergyMpAmt m, d

+ RtRegUpMpAmt m, d + RtRegDnMpAmt m, d + RtSpinMpAmt m, d

+ RtSuppMpAmt m, d + RtMwpMpAmt m, d

+ RtMwpDistMpAmt m, d + RtRegNonPerfMpAmt m, d

+ RtRegNonPerfDistMpAmt m, d + RtCRDeplFailMpAmt m, d

+ RtOclDistMpAmt m, d + RtCRDeplFailDistMpAmt m, d

+ RtRegUpDistMpAmt m, d + RtRegDnDistMpAmt m, d

+ RegUpUnusedMileMwpMpAmt m, d


+ RegDnUnusedMileMwpMpAmt m, d

+ RtSpinDistMpAmt m, d + RtSuppDistMpAmt m, d

+ RtRsgDistMpAmt m, d ) + RtDRMpAmt m, d + RtDRDistMpAmt m, d

+ RtPseudoTieCongMpAmt m, d + RtPseudoTieLossMpAmt m, d

+ ∑a

RtRsgDlyAmt a, d

+ ∑a∑

c∑

s{ IF rnu = 1, THEN MiscDlyAmt a, c, s, rnu, d , ELSE 0 } +

RtNetInadvertentSppAmt spp, d

- RtCongestionSppAmt spp, d

+∑h

DaOclHrlyAmt h

(b.3) RtNetInadvertentSppAmt spp, d = ∑i


(b.3.1) #RtNetInadvertentSpp5minAmt i =

( ( RtNetActIntrchngSpp5minQty i - RtNetSchIntrchngSpp5minQty i )

* RtMec5minPrc i ) / 12

(b.4) #RtCongestionSppAmt spp, d = RtPseudoTieCongSppAmt d +

∑a∑

s∑

i ( ( ( RtBillMtr5minQty a, s, i – DaClrdHrlyQty a, s, h )

+ ∑t

(RtImpExp5MinQty a, s, i, t - DaImpExp5MinQty a, s, i, t )


- ∑t

DaClrdVHrlyQty a, s, h, t ) * RtMcc5minPrc s, i ) / 12

(b.4.1) RtPseudoTieCongSppAmt d = ∑

m RtPseudoTieCongMpAmt m, d

(b.5) #RtDevCurtlSppAmt spp, d =

∑a

( ∑s∑

i (((–1)*RtLmp5minPrc s, i) *

( RtDevCapblty5minQty a, s, i – RtBillMtr5minQty a, s, i)) –

∑s∑

h ((–1)*DaLmpHrlyPrc s, h *

(DaDevCapbltyHrlyQty a, s, h – DaClrdHrlyQty a, s, h)) ) / 12


RtRnuDlyAmt a, s, d = ∑h

RtRnuHrlyAmt a, s, h


RtRnuAoAmt a, m, d = ∑s

RtRnuDlyAmt a, s, d


RtRnuMpAmt m, d = ∑a

RtRnuAoAmt a, m, d

Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed

of 59


Unit

Settlement Interval

Definition

RtRnuHrlyAmt a, s, h $ Hour Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Hour – The amount for revenue neutrality to AO a at Settlement Location s in Hour h.

RtRnuSppDistRate d $/MW Operating Day Real-Time Revenue Neutrality Uplift SPP Distribution Rate per Operating Day – The rate applied to AO a’s RtRnuDistHrlyQty a, s, h in each Hour h at Settlement Location s in Operating Day d.

RtRnuDistHrlyQty a, s, h

MWh Hour Real-Time Revenue Neutrality Uplift Quantity per AO per

Hour per Settlement Location – The total MWh RNU allocation determinant for AO a at Settlement Location s for Hour h.

RtRnuDistSppQty spp, d

MWh Operating Day Real-Time Revenue Neutrality Uplift Quantity for SPP per

Operating Day – The total MWh RNU allocation determinant for SPP on a system-wide basis.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Cleared Virtual Energy Quantity per AO per Transaction per Settlement Location per Hour – The value defined under Section 4.5.8.3.

RtOomSppAmt spp, d $ Operating Day Real-Time Out-Of-Merit Make Whole Payment Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section 4.5.9.9.

RtRegAdjSppAmt spp, d $ Operating Day Real-Time Regulation Deployment Adjustment Amount for SPP per Operating Day – The SPP system-wide total of the values described under Section 4.5.9.18.

RtJoaSppAmt spp, d $ Operating Day Real-Time Joint Operating Agreement Amount for SPP per Operating Day – The SPP system-wide total of the values calculated under Section 4.5.9.21.

DaRevInadqcSppAmt spp, d $ Operating Day Day-Ahead Revenue Inadequacy Amount – The amount of mismatch on an SPP-wide basis between total DA Market charges and DA Market credits for Operating Day d.

DaEnergyMpAmt m, d $ Operating Day Day-Ahead Asset Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.1.

DaNEnergyMpAmt m, d $ Operating Day Day-Ahead Non-Asset Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.2.

DaVEnergyMpAmt m, d $ Operating Day Day-Ahead Virtual Energy Amount per MP per Operating Day – The value calculated under Section 4.5.8.3.

DaRegUpMpAmt m, d $ Operating Day Day-Ahead Regulation-Up Service Amount per MP per Operating Day – The value calculated under Section 4.5.8.4.

DaRegDnMpAmt m, d $ Operating Day Day-Ahead Regulation-Down Service Amount per MP per Operating Day – The value calculated under Section 4.5.8.5.

of 59

Variable

Unit

Settlement Interval

Definition

DaSpinMpAmt m, d $ Operating Day Day-Ahead Spinning Reserve Amount per MP per Operating Day – The value calculated under Section 4.5.8.6.

DaSuppMpAmt m, d $ Operating Day Day-Ahead Supplemental Reserve Amount per MP per Operating Day – The value calculated under Section 4.5.8.7.

DaRegUpDistMpAmt m, d $ Operating Day Day-Ahead Regulation-Up Service Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.8.

DaRegDnDistMpAmt m, d $ Operating Day Day-Ahead Regulation-Down Service Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.9.

DaSpinDistMpAmt m, d $ Operating Day Day-Ahead Spinning Reserve Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.10.

DaSuppDistMpAmt m, d $ Operating Day Day-Ahead Supplemental Reserve Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.11.

DaMwpMpAmt m, d $ Operating Day Day-Ahead Make Whole Payment Amount per MP per Operating Day – The value calculated under Section 4.5.8.12.

DaMwpDistMpAmt m, d $ Operating Day Day-Ahead Make Whole Payment Distribution Amount per MP per Operating Day – The value calculated under Section 4.5.8.13.

TcrFundMpAmt m, d $ Operating Day Transmission Congestion Rights Funding Amount per MP per Operating Day – The value calculated under Section 4.5.8.14.

TcrUpliftDlyMpAmt m, d $ Operating Day Transmission Congestion Rights Uplift Amount per MP per Operating Day – The value calculated under Section 4.5.8.15.

ECFDlyAmt d $ Operating Day Excess Congestion Fund Amount per Operating Day – The value calculated under Section 4.5.8.16.

ARFDlyAmt d $ Operating Day Auction Revenue Fund Amount per Operating Day – The value calculated under Section 4.5.10.4.

DaOclHrlyAmt h $ Hour Day-Ahead Incremental Over Collected Losses Amount per Hour – The value described under Section 4.5.9.20.

TcrAucTxnMpAmt m, d $ Operating Day Transmission Congestion Right Auction Daily Amount per MP per Operating Day – The value calculated under Section 4.5.10.1.

ArrAucTxnMpAmt m, d $ Operating Day Auction Revenue Rights Funding Amount per MP per Operating Day – The value calculated under Section 4.5.10.2.

of 59

Variable

Unit

Settlement Interval

Definition

ArrUpliftMpAmt m, d $ Operating Day Auction Revenue Rights Funding Uplift Amount per MP per Operating Day – The value calculated under Section 4.5.10.3.

DaDRMpAmt m, d $ Operating Day Day-Ahead Demand Reduction Amount per Market Participant per Operating Day – The value calculated under Section 4.5.9.24

DaDRDistMpAmt m, d $ Operating Day Day-Ahead Demand Reduction Distribution Amount per Market Participant per Operating Day – The value calculated under Section 4.5.9.25

RtRevInadqcSppAmt spp, d $ Operating Day Real-Time Revenue Inadequacy Amount – The amount of mismatch on an SPP-wide basis between total RTBM charges and RTBM credits.

RtBillMtr5minQty a, s, i MW Dispatch Interval Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1.

RtImpExp5minQty a, s, i, t MW Dispatch Interval Real-Time Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.9.2.

RsgCrdFlg t

(Not Available on Settlement Statement)

none none Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Virtual Energy Quantity per AO per Settlement Location per Hour per Transaction – The value described under Section 4.5.8.3.

DaClrdHrlyQty a, s, h MWh Hour Day-Ahead Asset Energy Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.1.

DaImpExp5MinQty a, s, i, t MW Dispatch Interval Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Section 4.5.8.2.

RtMcc5minPrc s, i $/MW Dispatch Interval Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of the Real-Time LMP at Settlement Location s for Dispatch Interval i.

RtEnergyMpAmt m, d $ Operating Day Real-Time Energy Amount per MP per Operating Day – The value described under Section 4.5.9.1.

RtNEnergyMpAmt m, d $ Operating Day Real-Time Non-Asset Energy Amount per MP per Operating Day – The value described under Section 4.5.9.2.

RtVEnergyMpAmt m, d $ Operating Day Real-Time Virtual Energy Amount per MP per Operating Day – The value described under Section 4.5.9.3.

RtRegUpMpAmt m, d $ Operating Day Real-Time Regulation-Up Service Amount per MP per Operating Day – The value described under Section 4.5.9.4.

of 59

Variable

Unit

Settlement Interval

Definition

RegUpUnsedMileMwpMpAmt m, d

$ Operating Day Unused Regulation-Up Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.28.

RtRegDnMpAmt m, d $ Operating Day Real-Time Regulation-Down Service Amount per MP per Operating Day – The value described under Section 4.5.9.5.

RegUpUnsedMileMwpMpAmt m, d

$ Operating Day Unused Regulation-Down Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.29.

RtSpinMpAmt m, d $ Operating Day Real-Time Spinning Reserve Amount per MP per Operating Day – The value described under Section 4.5.9.6.

RtSuppMpAmt m, d $ Operating Day Real-Time Supplemental Reserve Amount per MP per Operating Day – The value described under Section 4.5.9.7.

RtMwpMpAmt m, d $ Operating Day RUC Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.8

RtOomMpAmt m, d $ Operating Day Real-Time Out-Of-Merit Make Whole Payment Amount per MP per Operating Day - The value described under Section 4.5.9.9.

RtMwpDistMpAmt m, d $ Operating Day RUC Make Whole Payment Distribution Amount per MP per Operating Day – The value described under Section 4.5.9.10.

RtRegNonPerfMpAmt m, d $ Operating Day Real-Time Regulation Non-Performance Amount per MP per Operating Day – The value described under Section 4.5.9.15.

RtCRDeplFailMpAmt m, d $ Operating Day Real-Time Contingency Reserve Deployment Failure Amount per MP per Operating Day – The value described under Section 4.5.9.17.

RtRegAdjMpAmt m, d $ Operating Day Real-Time Regulation Deployment Adjustment Amount per MP per Operating Day - The value described under Section 4.5.9.19.

RtOclDistMpAmt m, d $ Operating Day Real-Time Over Collected Losses Distribution Amount per MP per Operating Day - The value calculated under Section 4.5.9.20.


$ Dispatch Interval Real-Time SPP Inadvertent Energy Amount per Dispatch Interval – SPP net Inadvertent Energy for Dispatch Interval i valued at the Real-Time LMP MEC.

RtNetInadvertentSppAmt spp, d $ Operating Day Real-Time SPP Inadvertent Energy Amount per Operating Day – The sum of RtNetInadvertentSpp5minAmt i for Operating Day d.

RtCongestionSppAmt spp, d $ Operating Day Real-Time SPP Net Congestion Revenue Amount – The net amount of total Real-Time congestion revenue collected over Operating Day d.

of 59

Variable

Unit

Settlement Interval

Definition

RtNetActIntrchngSpp5minQty i

MW Dispatch Interval Real-Time SPP Net Actual Interchange per Dispatch Interval – SPP Net Actual Interchange in Dispatch Interval i.

RtNetSchIntrchngSpp5minQty i

MW Dispatch Interval Real-Time SPP Net Scheduled Interchange per Dispatch Interval – SPP Net Scheduled Interchange in Dispatch Interval i.

RtMec5minPrc i $/MW Dispatch Interval Marginal Energy Component of Real-Time LMP per Dispatch Interval – The Real-Time LMP MEC in Dispatch Interval i.

RtJoaHrlyAmt a, h, f $ Hour Real-Time Joint Operating Agreement Hourly Amount - The value calculated under Section 4.5.9.21.

RtRegNonPerfDistMpAmt m,

d $ Operating Day Real-Time Regulation Non-Performance Distribution

Amount - The value calculated under Section 4.5.9.16. RtCRDeplFailDistMpAmt m, d

$ Operating Day Real-Time Contingency Reserve Deployment Failure

Distribution Amount - The value calculated under Section 4.5.9.18.

RtRegUpDistMpAmt m, d $ Operating Day Real-Time Regulation-Up Service Distribution Amount – The value calculated under Section 4.5.9.11.

RtRegDnDistMpAmt m, d $ Operating Day Real-Time Regulation-Down Service Distribution Amount – The value calculated under Section 4.5.9.12.

RtSpinDistMpAmt m, d $ Operating Day Real-Time Spinning Reserve Distribution Amount – The value calculated under Section 4.5.9.13.

RtSuppDistMpAmt m, d $ Operating Day Real-Time Supplemental Reserve Distribution Amount – The value calculated under Section 4.5.9.14.

RtRsgDistMpAmt m, d $ Operating Day Real-Time Reserve Sharing Group Distribution Amount – The amount calculated under Section 4.5.9.23.

RtDRMpAmt m, d $ Operating Day Real-Time Demand Reduction Amount per Market Participant per Operating Day – The amount calculated under Section 4.5.9.24

RtDRDistMpAmt m, d $ Operating Day Real-Time Demand Reduction Distribution Amount per Market Participant per Operating Day – The amount calculated under Section 4.5.9.25.

RtRsgDlyAmt a, d $ Operating Day Real-Time Reserve Sharing Group Amount – The amount calculated under Section 4.5.9.22.

MiscDlyAmt a, c, d $ Operating Day Real-Time Miscellaneous Amount per AO per Charge Type per Operating Day – The miscellaneous amount to AO a for charge type c in Operating Day d as described under Section 4.5.10.4.

RtRnuDlyAmt a, s, d $ Operating Day Real-Time Revenue Neutrality Uplift Amount per AO per Settlement Location per Operating Day– The amount for revenue neutrality to AO a at Settlement Location s in Operating Day d.

of 59

Variable

Unit

Settlement Interval

Definition

RtRnuAoAmt a, m, d $ Operating Day Real-Time Revenue Neutrality Uplift Amount per AO per Operating Day – The amount for revenue neutrality to AO a associated with Market Participant m in Operating Day d.

RtRnuMpAmt m, d $ Operating Day Real-Time Revenue Neutrality Uplift Amount per MP per Operating Day – The amount for revenue neutrality to MP m in Operating Day d.

RtPseudoTieCongSppAmt d $ Dispatch Interval Real-Time SPP Total Pseudo-Tie Congestion Amount per Dispatch Interval - The total amount for congestion on Pseudo-Ties for the Operating Day.

RtPseudoTieCongMpAmt m, d $ Operating Day Real-Time Pseudo-Tie Congestion Amount per Market Participant per Operating Day - The value described under 4.5.9. 26 for MP m for the Operating Day.

RtPseudoTieLossMpAmt m, d $ Operating Day Real-Time Pseudo-Tie Losses Amount per Asset Owner per Operating Day - The amount for Pseudo-Tie losses on all paths for MP m for the Operating Day.

GFARevInadqcSppAmt spp, d $ Operating Day Grandfathered Agreement Carve-Out Revenue Inadequacy Daily Amount – The amount of charges and credits to GFA Carve-Out responsible entities on an SPP-wide basis from the settlement of Day-Ahead Asset & Non-Asset Energy, Day-Ahead Over-Collected Losses Distribution, Transmission Congestion Rights Funding & Uplift, Transmission Congestion Rights Auction and Auction Revenue Rights & Uplift amount for Operating Day d.

DaGFACarveOutDistMpDlyAmt m, d

$ Operating Day Day-Ahead GFA Carve Out Distribution Daily Amount per MP per Operating Day – The value calculated under Section 4.5.8.26

RtDevCurtlSppAmt spp, d $ Operating Day Real-Time Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load – (NDVER-DCPL) Uplift Quantity for SPP per Operating Day – The total MWh DCPL payment distribution allocation determinant for SPP on a system-wide basis. The value described under Sections 4.5.4.1(5), 4.5.12(1)(b.5),

DaDevCapbltyHrlyQty a, s, h MW Hour Day-Ahead Variable Energy Resource output capability per AO per Settlement Location per Dispatch hour per Transaction – The value described under Sections 4.5.4.1(5), 4.5.12(1)(b.5), and wind resource output forecast as described under Section 4.1.2.2.

RtDevCapblty5minQty a, s, i MW Dispatch Interval Real-Time Variable Energy Resource output capability per AO per Settlement Location per Dispatch Interval per Transaction – The value described under Sections 4.5.4.1(5), 4.5.12(1)(b.5), and wind resource output forecast as described under Section 4.1.2.2.

a none none An Asset Owner. s none none A Resource Settlement Location.

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Variable

Unit

Settlement Interval

Definition

h none none An Hour. i none none A Dispatch Interval. t none none A single tagged Interchange Transaction, a single virtual

energy transaction, a single Bilateral Settlement Schedule, a single contracted Operating Reserve transaction, a single TCR instrument, a single ARR award or a single Reserve Sharing Event transaction.

f none none A flowgate identified in the applicable JOA. d none none An Operating Day. rnu none none A flag which instructs the settlement system to include the

amount in Revenue Neutrality Uplift calculations (1 = Y, 0 = N).

m none none A Market Participant.

….


All Variable Energy Resources must register as a Dispatchable Variable Energy Resource except for (i) Wind powered Variable Energy Resources with an interconnection agreement executed on or prior to May 21, 2011 and that commenced Commercial Operation before October 15, 2012 or (ii) a Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility, or (iii) Non-wind Variable Energy Resources registered on or prior to January 1, 2017 and with an interconnection agreement executed on or prior to January 1, 2017. VERs included in (i) and (iii) above may register as Dispatchable Variable Energy Resources if they are capable of being incrementally dispatched by the Transmission Provider. A Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility may register as a Dispatchable Variable Energy Resource if it is capable of being incrementally dispatched by the Transmission Provider and will be subject to the DVER market rules including Uninstructed Resource Deviation Charges. Any Resource that has previously registered as a Dispatchable Variable Energy Resource shall not subsequently register as a Non-Dispatchable Variable Energy Resources.

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

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

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

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

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


Variable Energy Resources that qualify may register as a Non-Dispatchable Variable Energy Resource. The Market Participant registering a Non-Dispatchable Variable Energy Resource must provide documentation to SPP verifying that it meets one or more of the exceptions in Section 6.1.7.1. Otherwise, the Resource must be registered as a Dispatchable Variable Energy Resource. NDVERs are committed and dispatched the same as any other Resource in the Day-Ahead Market. For the RUC and RTBM, special commitment and dispatch rules apply as defined under Section 4.2.2.5.6. Non-Dispatchable Variable Energy Resource data submittal requirements are defined in the SPP Criteria.

6.1.10 Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load (NDVER-DCPL)

Market Participants managing Non-Dispatchable Variable Energy Resource (NDVER) resources may also register as a type Demand Response Resource called a NDVER-DCPL.. The NDVER-DCPL will be registered as a type of DRR, at a separate but electrically equivalent “common bus” settlement location, connected to a NDVER resource settlement location. The NDVER-DCPL represents curtailable NDVER output for SPP economic/reliability dispatch. For the network model, the NDVER-DCPL which represents generation curtailment from an NDVER somewhat like a DRR represents curtail of load at a load settlement location.

The NDVER must first be upgraded by the owner and Market Participant (MP) in order to have the capability to accept 5-minute SPP economic/reliability dispatch instructions. The MP is required to set up and send to SPP a 5-minute NDVER Available MW capability input variable “NDVERDCPL_AMW”. Once the upgrade is completed, the MP can register a NDVER-DCPL settlement location which will indicate to SPP the NDVER is ready for SPP dispatch. The MP will then submit offer curves for both the

1) NDVER-DCPLk curtailment settlement location is linked by a Common Bus to its host

2) NDVERk

The NDVER-DCPL clearing price is formulated simply by negating the NDVER LMP or MCP price. The negating of the NDVER LMP MCP prices can at times reasonably reflect to LMP MCP price of load on constrained side of binding constraints for which the NDVER contributes to congestion.

SPP can then dispatch this type of NDVER registration by sending the resource an economic/reliability Actual dispatch instruction level through “NDVERDCPL_EMW” and will pay the MP registered NDVER-DCPL for economic/reliability curtailments based on the following calculation.

The following provides an simple example how the NDVER-DCPL A and NDVER A works together to

represent a NDVER curtailment and SPP payment when there is NDVER curtailment.

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Exhibit 6.1.10a Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load (NDVER-DCPL) Simple Example








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Exhibit 6.1.10b Simple Example layout







output terminals

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Exhibit 6.1.10c Simple Example for SPP Dispatch

NDVER-DCPL The NDVER must also submit 5-minute NDVER output MW capabilities. SPP will then be able to dispatch the NDVER on 5-minute intervals, resulting in SPP NDVER-DCPL 5-minute interval settlement payment when cleared by SPP for curtailment/deployment and $ 0.0 when not curtailed/deployed. Registering a NDVER-DCPL is strictly voluntary on the part of a NDVER owner who must upgrade to dispatchable controls like DVER registration requirements.

SPP SCED will treat the NDVER and associated DCPLs as mutually exclusive dispatch generation and load, each located at applicable NDVER output terminal settlement locations. The DCPL is dispatched against negation of the NDVER LMP. During periods in which SPP SCED deploys NDVER-DCPL, SPP will

1st) send a follow dispatch flag set to the NDVER and then

2nd) send an NDVER dispatch signal equal to the NDVER 5-minute curtailed output instruction (e.g. net of NDVER actual capability minus DCPL curtailed output).

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SPP can curtail this type of NDVER economically in SCED through DCPL deployment without having to issue NDVER OOME instruction. SPP shall not clear any NDVER-DCPL if self-curtailed or clear amounts beyond/below the SPP dispatch instruction. The following special modeling rules apply to a DCPL Resource.

(1) A NDVER-DCPL is a special type of Resource created to model registered curtailment settlement location linked with a host upgraded/dispatchable NDVER;

(2) A NDVER-DCPL is modeled in the Commercial Model with a separately defined Settlement Location from a NDVER that has been upgraded to be dispatchable. Thus, the NDVER-DCPL will have separate PNode or APNodes at an electrically equivalent location to the associated NDVER PNode or APNode location;

(3) A NDVER-DCPL is also included in the SPP Network Model as a load addition representing offered price of curtailment of the associate NDVER generation output;

(4) A NDVER-DCPL must have a corresponding NDVER at an electrically equivalent location;

(5) The NDVER must have telemetering installed as with DVER registration in which curtailment MW volumes can be measured by SPP settlement;

(6) The Market Participant must submit the real-time actual base NDVER output capability to SPP via SCADA on a 10-second basis

(7) The Market Participant must submit the real-time achieved curtailment of the SPP deployed NDVER-DCPL value to SPP via SCADA on a 10-second basis.

(8) SPP will issue a follow dispatch flag to all NDVERs that have deployed NDVER-DCPL curtailments. The SPP NDVER dispatch instruction will consist of the actual NDVER cleared curtailed output target during for the interval or the actual NDVER output capability during intervals in which the resource is not curtailed.

(9) For each interval, SPP will settle deployed NDVER-DCPL cleared curtailment load resulting from the SCED economic curtailment of an NDVER, if any, and will clear 0.0 MW for the NDVER-DCPL if not curtailed.

(10) The NDVER-DCPL is settled at a common bus electrically equivalent settlement locations with the NDVER LMP and MCP negated. NDVER-DCPLs can be deployed during emergency events or to avoid Regulation scarcity pricing.

Exhibit 4-9: Calculated NDVER and NDVER-DCPL Output and settlements

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6.1.10 11 Resources External to the SPP BA

6.1.1011.1 External Dynamic Resources

A Market Participant registers an EDR for the purposes of accounting for importing of Operating Reserve that is sourced external to the SPP BA. An External Dynamic Resource that is modeled in the Eastern Interconnection may either represent a single Resource or a fleet of Resources and is not subject to Energy dispatch, only clearing and deployment of the Operating Reserve products that the EDR is qualified to provide, except that an associated Dynamic Schedule for Energy may be used for the purposes of providing Regulation-Down Service which must be specified at registration. An EDR that is associated with a DC tie-line is modeled as a single Resource and may be available for Energy dispatch and/or Operating Reserve clearing which must be specified at registration. See Section 4.2.2.5.7 for specific modeling details.

…

Appendix G Mitigated Offer Development Guidelines … G.8 Demand Response Guidelines A Demand Response Resource is a special type of Resource created to model demand reduction associated with controllable load and/or a behind the meter Resource that is dispatchable either on a 5-minute basis or an hourly basis;

G.8.1 Demand Response Resource (DRR) Cost for Behind the Meter Generation

Market Participants using behind the meter Resource as a DDR Resource should refer to the appropriate unit type defined in this manual to develop incremental cost,

G.8.2 DRR Cost for Demand Reduction

Demand Reduction is the actual reduction of load at the direction of SPP through the commitment and dispatch of as associated DRR. This could include the cycling of air conditioners or the shutdown of an industrial production process in order to reduce the load at a site. Incremental costs can include quantifiable opportunity costs associated with the reduction, net of related offsetting increases in usage. Typically, demand reduction would be registered as a Block Demand Response Resource but an industrial site that can control its load consumption on a real-time basis could register as a Dispatchable Demand Response Resource.

G.8.3 DRR Start-Up Cost

DRR Start-Up cost is the cost to shut down or curtail a load for a given period, which does not vary with output, or the start cost of a behind the meter Resource. Start costs for DRRs represented by behind the meter Resources are defined by unit type in this manual. Start-Up costs for DRRs representing load curtailment are not specifically defined but will be evaluated on a case by case basis when submitted as part of a Market Participants fuel cost policy for reasonableness.

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G.8.4 DRR Cost to Provide Spinning and/or Supplemental Reserves

Spinning Reserves from Demand Response Resources must be provided by equipment electrically synchronized to the system, and able to be fully deployed for the cleared amount within ten minutes upon request by SPP. The costs of spinning reserves from a DRR are the quantifiable incremental costs to reduce load by the offered amount within ten minutes. Incremental costs include shut down costs and opportunity costs.

G.8.5 DRR Cost to Provide Regulation

Regulation-Up and/or Regulation-Down from Dispatchable Demand Response Resources must be provided by equipment electrically synchronized to the system and able qualify for provision of regulation services. The costs of regulation from DDR Resources are the quantifiable incremental costs to reduce load by the offered amount within five minutes. Incremental costs include shut down costs and opportunity costs.

G.9 Non-Dispatchable Variable Energy Resource – Dispatch Curtailment Pseudo Load (NDVER-DCPL) NDVER-DCPL- NDVER curtailment load amount which is settled at the negated NDVER LMP or MCP price and is offered at a price at which the NDVER Market Participant is willing to accept economic curtailment of their NDVER.

G.9.1 NDVER-DCPL: SPP NDVER dispatch Curtailment Energy Cost Exposure

NDVER with unexpired Federal Government Production Tax Credits (PTCs) or unexpired Purchase Power Agreement (PPA) purchase contracts may include lost PTC revenue exposure or PPA buyer cost obligations associated with NDVERs within a registered NDVER-DCPL pseudo curtailment load mitigated energy or reserve offer. Lost revenues can include, but is not necessarily limited to, PTC lost revenue exposure or contractual PPA buyer cost obligations triggered by economic/reliability SPP dispatch.

NDVER Conversions to Dispatchable and Market Benefits:

The SPP MMU has made frequent claims there are significant benefits from NDVERs becoming dispatchable. Thus, for NDVERs that both register and offer NDVER-DCPL curtailments for the at least 95% of NDVER capacity, the MMU shall allow reasonable PTC revenue and contractual PPA seller/buyer cost obligations for any SPP economic/reliability dispatch.

Market Participant Release from Burden of Proof:

If the parties to NDVER PPA contract dispute the contractual terms for cost obligations when SPP economically/reliability dispatches an NDVER-DCPL, within reason, the MMU will allow such cost exposure into mitigated offers so that nether the owners/sellers/buyers placed with burden of proof for disputed contractual terms.

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NDVER-DCPLs do not have start costs.


NDVER-DCPLs do not have No-Load costs.

G.9.4 VOM

NDVER-DCPLs should reflect their short-run incremental VOM costs for incrementing or decrementing of NDVER output by using the most current data available. This could include the previous actual short-run incremental cost where available. For wind units, VOM dollars from the previous years should be divided by MWh generated in the same period.



G.9 10 Wind Guidelines

Wind Units- Generating unit in which wind spins the turbine Resource to produce electricity. G.109.1 Fuel Cost

Wind Units may include applicable costs that vary by MWh output.


Wind Units do not have start costs.


Wind Units do not have No-Load costs.

G.9.4 VOM

Wind units should reflect their short-run incremental VOM costs by using the most current data available. This could include the previous actual short-run incremental cost where available. For wind units, VOM dollars from the previous years should be divided by MWh generated in the same period.



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SPP Tariff (OATT)

ATTACHMENT AE

INTEGRATED MARKETPLACE


1.1 Definitions D

....

Common Bus

A single bus to which two or more Resources owned by the same Asset Owner are connected in an electrically

equivalent manner where such Resources may be treated as interchangeable for certain compliance monitoring

purposes.

....


A registered measurable load that is capable of being reduced at the instruction of the Transmission Provider

and subsequently may be increased at the instruction of the Transmission Provider.

Demand Response Resource

A Dispatchable Demand Response Resource or a Block Demand Response Resource.

Dispatch Instruction

The communicated Resource target Energy Megawatt output level at the end of the Dispatch Interval.

Dispatchable Demand Response Load Settlement Location

A registered load Settlement Location that contains the Demand Response Load associated with a Dispatchable

Demand Response Resource.

Dispatchable Demand Response Resource

A Resource created to model Demand Response Load reduction associated with controllable load or a Behind-

The-Meter generator that is dispatchable on a five (5) minute basis.

…

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A Variable Energy Resource that is not capable of being incrementally dispatched by the Transmission Provider.

Non-Dispatchable Variable Energy Resource – Dispatch Curtailment Pseudo Load (NDVER-DCPL)

After a Market Participant (MP) has upgraded a Non-Dipatchable Variable Energy Resource (NDVER) to

accept 5-minute economic/reliability dispatch instructions from SPP, the MP may register a Dispatch

Curtailment Pseudo Load NDVER-DCPL so the MP can be paid by SPP for NDVER curtailments without SPP

having to issue an OOME instruction. The NDVER-DCPL will represent a MP capacity/price offer for SPP to

using in clearing curtailment NDVER MWs.. During emergencies or reliability issues which SCED can’t

solve, SPP shall continue to issue OOME instructions to NDVERs.

SPP shall clear NDVER-DCPL curtailment MWs for the NDVER using the negated NDVER LMPi.. SPP shall

settle the NDVER-DCPL based NDVER curtailed MWs at a negated NDVER LMPi or negated NDVER MCP

price based upon the NDVER-DCPL offer curves. Self or curtailment more than SPP dispatch instructions will

not be cleared by SPP.

…

4.1 Offer Submittal

…

4.1.2.5 Non-Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Non-Dispatchable Variable

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

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

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

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

output at the start of the Dispatch Interval and the Resources must operate as non-

dispatchable;

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

calculating production costs relating to RUC make whole payments and cost allocation

thereof under Sections 8.6.5 and 8.6.7 of this Attachment AE;

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(5) An OOME may be issued to a Non-Dispatchable Variable Energy Resource. In addition,

the Transmission Provider will issue the dispatch instruction to the Resource in accordance

with Section 6.2.4 of this Attachment AE; and

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

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

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

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

maximum operating limits shall be equal to those submitted in the Resource Offer;

(a) Non-Dispatchable Variable Energy Resources for which the Transmission Provider

is calculating an output forecast are not eligible to receive RUC make whole

payments as described under Section 8.6.5 of this Attachment AE.

4.1.2.6 Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load (NDVER-DCPL)

Market Participants managing Non-Dispatchable Variable Energy Resource (NDVER) resources may

also register a type of Demand Response Resource (DRR) called a Dispatch Curtailment Pseudo Load –

(NDVER-DCPL) so the MP can be paid by SPP for NDVER curtailments without SPP having to issue

an OOME instruction to the NDVER. The NDVER-DCPL will be modeled on a Common Bus to the

NDVER at a separate settlement location. The NDVER-DCPL represents SPP economic/reliability

curtailment of NDVER output referred here as 5-minute dispatchable. SPP will clear the NDVER-

DCPL based on MP submitted curtailment dispatch curves and a negated NDVER LMPi. If there is no

curtailment of the NDVER the NDVER-DCPL will have 0.0 cleared MWs based on the following

formula.

NDVER-DCPLk LMPi = (NDVERk LMP i ) ( -1 )

Additionally, MCP will be cleared by SPP in the same manner.

.NDVER-DCPLk MCP = (NDVERk MCP ) ( -1 )

NDVER-DCPLk curtailment loads are always linked with a host NDVERk representing the curtailment

Registering a NDVER-DCPL is strictly a voluntary for NDVER owners and MPs. However, the

NDVER must upgraded to dispatchable controls so the NDVER can accept a 5-minute dispatch

instruction from SPP, prior to registering the NDVER-DCPL. The following provides a simple example

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how the NDVER-DCPL A and NDVER A works together to represent a NDVER curtailment and SPP

payment when there is NDVER curtailment.

Exhibit 4.1.2.6a Non-Dispatchable Variable Energy Resource - Dispatch Curtailment Pseudo Load (NDVER-DCPL) Simple Example








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Exhibit 4.1.2.6b Simple Example layout

SPP can curtail this type of NDVER economically in SCED through DCPL deployment without having to issue

NDVER OOME instruction. SPP shall not clear any NDVER-DCPL if self-curtailed or clear amounts

beyond/below the SPP dispatch instruction. See example below.

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Exhibit 4.1.2.6c Simple Example for SPP Dispatch







output terminals

4.1.2.67 External Dynamic Resource

Each Market Participant may submit Resource Offers for External Dynamic Resources

(“EDR”) using the same Offer parameters available to any other Resource, except that:

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(1) A Market Participant may only submit a commitment status as defined in Section

4.1(10)(a) or (d) of this Attachment AE;

(2) For an EDR in the Eastern Interconnection, a Market Participant must submit a dispatch

status indicating that the EDR is not available for energy dispatch as described under

Section 4.1(11)(a) of this Attachment AE;

(3) For an EDR in the Eastern Interconnection, Resource Offer parameters are limited to:

Regulation-Up and Regulation-Down Offers, Spinning and Supplemental Reserve Offers,

Regulation Ramp Rate, Contingency Reserve Ramp Rate and Resource Status. All other

Resource Offer parameters as listed in Section 4.1(9) of this Attachment AE shall not apply

to EDRs in the Eastern Interconnection.

(4) For an EDR that is not in the Eastern Interconnection, Resource Offer parameters are

limited to: Energy Offer Curve, Ramp-Rate-Up, Ramp-Rate-Down, Regulation-Up and

Regulation-Down Offers, Spinning and Supplemental Reserve Offers, Regulation Ramp

Rate, Contingency Reserve Ramp Rate and Resource Status. All other Resource Offer

parameters as listed in Section 4.1(9) of this Attachment AE shall not apply to EDRs that

are not in the Eastern Interconnection.

…

8.8 Revenue Neutrality Uplift Distribution Amount

The Transmission Provider shall perform the following calculation for each hour of the Operating Day for each

Asset Owner and Settlement Location to ensure that the Transmission Provider is revenue neutral in each hour

of the Operating Day. The Transmission Provider shall calculate hourly summations to each Market Participant

for all Asset Owners it represents and shall calculate daily summations as specified in the Market Protocols. The

calculations below can result in residual amounts due to rounding. The Transmission Provider will sum up those

residual amounts per Operating Day on an annual basis and will uplift the annual residual amounts to all of the

Asset Owners as specified in the Market Protocols.

Revenue Neutrality Uplift Distribution Amount =

Daily RNU Distribution Rate * RNU Distribution Volume * (-1)

(1) The Daily RNU Distribution Rate is equal to the Daily RNU Distribution Amount divided by the Daily

RNU Distribution Volume.

(a) The Daily RNU Distribution Amount is equal to:

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(i) The sum of all Asset Owners’ charges and payments calculated under Section 8.5, excluding

payments under Sections 8.5.13, 8.5.14 and 8.5.15, for the Operating Day; plus

(ii) The sum of all Asset Owners’ charges and payments calculated under Section 8.6 for the

Operating Day; plus

(iii) The sum of all Asset Owners’ charges and payments calculated under Section 8.7, excluding

payments under Sections 8.7.4, 8.7.5 and 8.7.6; plus

(iv) The sum of all charges and payments for emergency purchases and sales entered into by the

Transmission Provider in its Balancing Authority role in order to alleviate a capacity shortage

inside the Effective Date: 3/1/2014 - Docket #: ER14-1653-001 - Page 445

SPP Balancing Authority Area or to assist an external Balancing Authority in alleviating a

capacity shortage; plus

(v) Any other charges and credits not accounted for in subsections (i) through (iv) above; minus

(vi) The Excess Congestion Fund Daily Amount calculated under Section 8.5.13(3)(a) for the

Operating Day; minus

(vii) The Excess TCR Revenue Fund Daily Amount calculated under Section 8.7.4(3)(a) for the

Operating Day,

(viii) SPP Payment obligations for cleared Non-Dispatchable Variable Energy Resource -

Dispatch Curtailment Pseudo Load – (NDVER-DCPL) described under Section 4.1.2.(6).

(b) The Daily RNU Distribution Volume is equal to the sum of all Asset Owners’ RNU Distribution

Volumes for the Operating Day.

(2) An Asset Owner’s RNU Distribution Volume at a Settlement Location for an hour is equal to the sum of:

(a) The absolute value of actual metered generation or load in the hour; and

(b) The absolute value of scheduled Interchange Transactions in the hour; and

(c) The absolute value of cleared Virtual Energy Offers and Bids in the hour.

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SPP Balancing Authority Area or to assist an external Balancing Authority in alleviating a capacity shortage; plus (v) Any other charges and credits not accounted for in subsections (i) through (iv) above; minus (vi) The Excess Congestion Fund Daily Amount calculated under Section 8.5.13(3)(a) for the Operating Day; minus (vii) The Excess TCR Revenue Fund Daily Amount calculated under Section 8.7.4(3)(a) for the Operating Day. (b) The Daily RNU Distribution Volume is equal to the sum of all Asset Owners’ RNU Distribution Volumes for the Operating Day. (2) An Asset Owner’s RNU Distribution Volume at a Settlement Location for an hour is equal to the sum of: (a) The absolute value of actual metered generation or load in the hour; and (b) The absolute value of scheduled Interchange Transactions in the hour; and (c) The absolute value of cleared Virtual Energy Offers and Bids in the hour.

….

ATTACHMENT AF MARKET POWER MITIGATION PLAN

…

3.2 Mitigation Measures for Energy Offer Curves

Mitigated Energy Offer Curves shall be submitted on a daily basis by the Market Participant in

accordance with the mitigated offer development guidelines in the Market Protocols. For Multi-

Configuration Resources (“MCR”), as defined in Attachment AE, for which a single configuration

allows physical units to be swapped (e.g., Combustion Turbine 2 for Combustion Turbine 1), the

costs used in the mitigated offer development for that configuration shall be those of the least cost

physical unit that is available and can be swapped in such configuration. The mitigated Energy

Offer Curve may be updated up to the close of the Day-Ahead Market as defined in Section 5.1 of

Attachment AE of this Tariff for use in the Day-Ahead Market. In the case a Resource is not

committed by the Day-Ahead Market, the mitigated Energy Offer Curve may be updated until the

Day-Ahead RUC begins. For Resources committed by the Day-Ahead Market, the mitigated

Energy Offer Curve submitted as of the close of the Day-Ahead Market will apply to the Day-

Ahead Market on the day before the Operating Day and the RTBM on the Operating Day; for all

other Resources the mitigated Energy Offer Curve submitted at the time the Day-Ahead RUC

begins will apply to the Day-Ahead RUC on the day before the Operating Day, and the Intra-Day

RUC processes and the RTBM on the Operating Day.

A. The Energy Offer Curve conduct thresholds are as follows:

(1) For Resources committed to address a Local Reliability Issue, the conduct threshold

is a 10% increase above the mitigated Energy Offer Curve;

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(2) For Resources located in a Frequently Constrained Area and not subject to Section

3.2(A)(1), the conduct threshold is a 17.5% increase above the mitigated Energy

Offer Curve;

(3) For all other Resources the conduct threshold is a 25% increase above the mitigated

Energy Offer Curve.

B. The Transmission Provider shall apply mitigation measures by replacing the Energy Offer

Curve with the mitigated Energy Offer Curve if:

(1) The Resource’s Energy Offer Curve exceeds the mitigated Energy Offer Curve by

the applicable conduct threshold; and

(2) The Resource has local market power as determined in Section 3.1; and

(3) The Resource either:

(a) Fails the Market Impact Test as described in Section 3.7, or

(b) Is manually committed by the Transmission Provider or by a local

transmission operator.

An Energy Offer below $25/MWh will not be subject to mitigation measures for economic

withholding.

C. The mitigated energy offer shall be the Resource’s short-run marginal cost of producing

energy as determined by the unit’s heat rate; fuel costs and the costs related to fuel usage,

such as transportation and emissions costs (“total fuel related costs”); and Energy Offer

Curve (“EOC”) variable operations and maintenance costs (“VOM”) as detailed in the

Market Protocols.

D. Opportunity cost shall be an estimate of the Energy and Operating Reserve Markets

revenues net of short run marginal costs for the marginal forgone run time during the

timeframe when the Resource experiences the run-time restrictions as detailed in the

Market Protocols. The run-time restrictions shall be updated as specified in the Market

Protocols, with more frequent updating to occur the fewer hours that remain available,

consistent with the Market Protocols. The Market Participant may include in the

calculation of its mitigated Energy Offer Curve an amount reflecting the resource-specific

opportunity costs expected to be incurred under the following circumstances:

(1) Externally imposed environmental run-hour restrictions; or

(2) Physical equipment limitations on the number of starts or run-hours, as verified by

the Market Monitoring Unit and determined by reference to the manufacturer’s

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recommendation or bulletin, or a documented restriction imposed by the applicable

insurance carrier; or

(3) Fuel Supply Limitations.

Resource specific opportunity costs are calculated by forecasting Locational Marginal

Prices based on futures contract prices for natural gas and the historical relationship

between the SPP system marginal Energy component of LMP and the price of natural gas,

as determined by the SPP Market Monitoring Unit. The formulas and instructions in the

price forecast model shall be determined by the SPP Market Monitoring Unit and published

in the Market Protocols as part of the Mitigated Offer Development Guidelines, updated,

as needed, by the SPP Market Monitoring Unit. Such forecasts of LMPs shall take into

account historical variability, and basis differentials affecting the Settlement Location at

which the Resource is located for the three-year period immediately preceding the period

of time in which the Resource is bound by the referenced restrictions, and shall subtract

therefrom the forecasted costs to generate energy at the Settlement Location at which the

Resource is located, as specified in more detail in Appendix G of the Market Protocols. If

the difference between the forecasted Locational Marginal Prices and forecasted costs to

generate energy is negative, the resulting opportunity cost shall be zero. The Market

Monitoring Unit will verify all Market Participants’ opportunity cost calculations for

consistency and accuracy. When the Market Monitoring Unit determines that the market

price for any period was not competitive, it will adjust the LMP forecasting process used

in the opportunity cost calculations to ensure that forecasted LMPs do not reflect non-

competitive market conditions.

The following formula shall apply to all mitigated Energy Offer Curves:

Mitigated Energy Offer ($/MWh) = HeatRate (mmBtu/MWh) *

Performance Factor * Total Fuel Related Costs ($/mmBtu) + EOC VOM ($/MWh) + Opportunity

Costs ($/MWh)

The Market Participant shall submit heat rate curves, descriptions of how spot fuel prices and/or

contract prices are used to calculate fuel costs, variable fuel transportation and handling

costs, emissions costs, and VOM to the Market Monitoring Unit. All cost data and cost

calculation descriptions are subject to the review and approval of the SPP Market

Monitoring Unit to ensure reasonableness and consistency across Market Participants. The

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information will be sufficient for replication of the mitigated Energy Offer Curve and shall

include, among other data, the following information:

(1) For fuel costs, Market Participants shall provide the Market Monitoring Unit with

an explanation of the Market Participants’ fuel cost policy, indicating whether fuel

purchases are subject to a fixed contract price and/or spot pricing and specifying

the contract price and/or referenced spot market prices. Any included fuel

transportation and handling costs must be short-run marginal costs only, exclusive

of fixed costs.

(2) For emissions costs, Market Participants shall report the emissions rate of each of

their units and indicate the applicable emissions allowance cost.

(3) For VOM costs, Market Participants shall submit VOM costs, calculated in

adherence with the Appendix G of the Market Protocols, reflecting short-run

marginal costs, exclusive of fixed costs.

Further details associated with the development, validation, and updating of these costs are

included in Appendix G of the Market Protocols.

For Demand Response Resources utilizing Behind-The-Meter Generation, the mitigated

Energy Offer Curve shall be developed in the same manner as any other generating

Resource as described above. For Demand Response Resources utilizing load reduction,

the mitigated Energy Offer Curve shall reflect the quantifiable opportunity costs associated

with the reduction, net of related offsetting increases in usage.

For Dispatchable Variable Energy Resources, the mitigated Energy Offer Curve may

include, but shall not exceed, any quantifiable costs that vary by MWh output, including

short-run incremental VOM. Mitigation will not apply to Non-Dispatchable Variable

Energy Resources in the Real-Time Balancing Market; monitoring of Energy Offers for

Non-Dispatchable Variable Energy Resources will occur.

E. Intra-day changes to the mitigated Energy Offer Curve are allowed under the following

conditions:

1) In the event that the Transmission Provider requests that a Resource remain online

past their commitment period by the Day-Ahead Market or a RUC process, the

Market Participant may submit an updated mitigated energy offer curve that reflects

the procurement of higher cost fuel;

2) A Resource must switch fuels due to unforeseen operating conditions; or

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3) A Market Participant employing the Quick-Start Resource logic as described in the

Market Protocols may update its mitigated Energy Offer Curve after the Day-Ahead

RUC clears on the day before the Operating Day, as described in Appendix G of


Intra-day changes to the mitigated energy offer curve must follow the mitigated offer

development guidelines in Appendix G of the Market Protocols. Any such changes will be

validated by the Market Monitor.

F. In all cases under this Section 3.2, cost data submitted for the development of mitigated

offers, including opportunity cost data, shall be subject to the confidentiality provisions set

forth in Section 11 of Attachment AE of this Tariff.

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RR #: 274 Date: 1/16/2018

RR Title: NDVER to DVER Conversion Through URD System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes


Name: Chandler Brown Company: Sunflower Electric Power Corporation












Correction

Clarification

Design Enhancement








Reliability/Operations: Currently NDVERs that are following price prevent SPP from being able to accurately forecast short term generation leading to potential shortage events and de-rating of flowgates.

Financial: Derating of flowgates, potential shortage events, and unplanned variations in generation, can lead to extreme price spikes in both directions resulting in sub-optimal market clearings and excessive regulation requirements. SPP Documents Requiring Revision: Please select your primary intended document(s) as well as all others known that could be impacted by the requested revision (e.g. a change to a protocol that would necessitate a criteria or business practice revision).

Market Protocols Section(s): 4.4.4.1, 4.5.8.14, 4.5.9.10 Protocol Version: Operating Criteria Section(s): Criteria Date: Planning Criteria Section(s): Criteria Date: Tariff (OATT) Section(s): Attachment AE – 6.4.1, 8.5.11

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Business Practice Business Practice Number: Integrated Planning Model (ITP Manual) Section(s): Revision Request Process Section(s): Minimum Transmission Design





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SPP has shown that NDVERs chasing price signals can result in significant costs to the market, can create reliability concerns, and has stated that more dispatchable units would improve market efficiency. Therefore, SPP has proposed 100 percent conversion of NDVERs to DVERs. Sunflower does not oppose this approach and believes that in the majority of cases conversion is good for both the market and the market participant. However, Sunflower is sympathetic to the fact that in certain cases, there is little benefit of conversion to the market or the market participant. Examples of these cases may include smaller Type I or Type II units that would require substantial $/MW to convert, or farms located in areas that rarely see negative prices (and therefore would rarely be subject to curtailment). A full conversion requirement would potentially result in an MP wasting money on a needless conversion or the MP requesting an exemption from FERC. If the exemption were granted, the concern of exempted NDVERs chasing price would still exist. This RR is not mutually exclusive to the SPP proposal since it would fix the concern of exempted NDVERs chasing price.


This RR would: Strongly discourage NDVERs from chasing price signals (or at least encourage slow output changes) which would increase market efficiency and reliability. Not require any subjective monitoring or threat of FERC referral since “price chasing” is not specifically prohibited. Allow MPs to make the decision to convert from NDVER to DVER based on business case and financial analysis. Encourage conversion of NDVERs to DVERs where it provides the most benefit to the market and the MP.

Basic design

This RR proposes using the existing URD logic (or slight derivation thereof) in the settlements system to impose substantial penalties on NDVERs whose output varies more than 5 percent (subject to the same 20MW cap and 5MW floor values currently applicable to URDs) from “setpoint”. The “setpoint” would be equal to the previous dispatch interval average output or (optionally) the current dispatch intervals average real-time capability sent to SPP via ICCP. There would be no change to existing OOME and/or Reliability Curtailments.

If the deviation from “setpoint” exceeds 5 percent, the charge for each 5 minute interval would be equal to the deviation MW * $1000, where the deviation is defined as the lessor of The Absolute Value of (The Previous 5 minute interval average output – The Current 5 minute interval average output) or The Absolute Value of (The Current 5 minute interval average real-time capability – The Current 5 minute interval average output). Penalties collected are credited to TCR funding.

NdverUrd5MinQty = MIN ( ABS (RtBillMtr5MinQtya,s,i-1 - RtBillMtr5MinQtya,s,i),

ABS (RtCap5MinQtya,s,i - RtBillMtr5MinQtya,s,i ) ) Examples

o MP chooses NOT to convert to DVER and DOES NOT send real-time capability to SPP via ICCP. This option requires no change or investment for the MP, and may make sense if the MP never plans to curtail the unit and isn’t concerned about some exposure to inadvertent penalties due to abrupt changes in wind speed or direction.

If the output of the NDVER does not change by more than 5 percent from 1 interval to the next, there will be no penalty and should have minimal negative impact on the market.

• This should happen most of the time that the NDVER is strictly following the wind.

• This would also happen if the NDVER is manually curtailed at a rate less than 1percent/min. This gives the NDVER the ability to follow price to some degree without penalty at a rate that should be manageable by SPP.

If the output of the NDVER does change by more than 5 percent from 1 interval to the next, a penalty will be assessed as defined above due to the potential for significant negative impact on the market.

• This would also happen if the NDVER is manually curtailed at a rate greater than 1percent/min. This still allows the NDVER the ability to follow price as quickly as desired, though penalties for doing so could be substantial, especially if the NDVER is cycling up and down.

• This could happen when the NDVER is strictly following the wind and the wind speed or direction changes abruptly (which may happen when a weather front moves through for example).

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o MP chooses NOT to convert to DVER and DOES send real-time capability to SPP via ICCP. This option requires some (likely minimal) investment for the MP to send the real-time capability signal to SPP. This may make sense if MP never plans to curtail the unit and wants protection against inadvertent penalties.

If the output of the NDVER does not change by more than 5 percent from 1 interval to the next OR does not deviate by more than 5percent from the real-time capability for the current interval, there will be no penalty and should have minimal negative impact on the market.

• This should happen all of the time that the NDVER was strictly following the wind. Sudden changes in wind speed or direction should be reflected in the real-time capability, and no penalty would be assessed.

• This would also happen if the NDVER is manually curtailed at a rate less than 1 percent/min. This gives the NDVER the ability to follow price to some degree without penalty at a rate that would be manageable by SPP.

If the output of the NDVER does change by more than 5 percent from 1 interval to the next AND deviates by more than 5 percent from the real-time capability for the current interval, a penalty will be assessed as defined above due to the potential for significant negative impact on the market.

• This should only happen if the NDVER is manually curtailed at a rate greater than 1 percent/min. This allows the NDVER the ability to follow price as quickly as desired, though penalties for doing so could be substantial, especially if the NDVER is cycling up and down..

o MP chooses to convert NDVER to DVER. This option would require some (which could vary widely from one wind farm to another) investment to receive and follow a setpoint from SPP. This would make sense if the wind farm were located in an area that frequently saw negative LMPs and the cost to convert was not astronomical.

None of the penalties described in this RR would apply. Unit would be subject to penalties that currently apply to existing DVERs.

SPP would economically dispatch the unit resulting in maximum benefits to the market and MPs.

REVISIONS TO SPP DOCUMENTS

In the appropriate sections below, please provide the language from the current document(s) for which you are requesting revision(s), with all edits redlined.

Market Protocols

4.4.4.1 Uninstructed Resource Deviation

The following rules apply to the calculation of Uninstructed Resource Deviation (URD).

(1) URD is the difference between a Resource’s actual average MW output over the Dispatch Interval and the Resource’s average ramped MW Setpoint Instruction over a Dispatch Interval. For the purposes of determining URD exemptions for Resources that are part of a Common Bus as described under Section 4.4.4.1.1(6), each Asset Owner’s Resources’ combined average ramped MW Setpoint Instruction and combined actual average MW output at the Common Bus will be used to calculate URD at the Common Bus for the Dispatch Interval for each Asset Owner;

(2)(1) A Resource’s URD is allocated a portion of the RUC Make Whole Payment costs in any Dispatch Interval where Resource’s URD is outside of its Operating Tolerance unless that Resource has been exempted from URD under Section 4.4.4.1.1.

Field Code Changed

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(a) A generating unit Resource’s Operating Tolerance in each Dispatch Interval is equal to the Resource’s Maximum Emergency Capacity Operating Limit multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.

(b) A Dispatchable Demand Response Resource’s Operating Tolerance in each Dispatch Interval is equal to the Resource’s Maximum Emergency Capacity Operating Limit multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.

(c) A Block Demand Response Resource’s Operating Tolerance in each Dispatch Interval is equal to the Resource’s Maximum Economic Capacity Operating Limit multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.

(d) The Common Bus Operating Tolerance for each Asset Owner registered at a Common Bus is equal to the sum of that Asset Owner’s Resources’ Maximum Emergency Capacity Operating Limits for Resources that are on-line multiplied by 5%, subject to a minimum of 5 MW and a maximum of 20 MW.

(e) A non-NDVER Resource’s URD is allocated a portion of the RUC Make Whole Payment costs in any Dispatch Interval where Resource’s URD is outside of its Operating Tolerance unless that Resource has been exempted from URD under Section 4.4.4.1.1.

(a) If the absolute value of a non-NDVER Resource’s URD is greater than the Resource’s Operating Tolerance in any Dispatch Interval, the Resource URD / 12 is included in the hourly allocation of RUC Make Whole Payment cost allocation. The hourly URD amount is calculated as the sum of Dispatch Interval URD for the hour. See Section 4.5.9.10 for calculation details. Additionally, if that Resource was eligible to receive a RUC Make Whole Payment, the payment may be reduced. See Section 4.5.9.8 for calculation details.

(3)(2) A NDVER Resources URD is assessed a penalty that is allocated to TCR funding in any Dispatch Interval where Resource’s URD is outside of its Operating Tolerance unless that Resource has been exempted from URD under Section 4.4.4.1.1

(a) If the absolute value of a NDVER Resources URD is greater than the Resource’s Operating Tolerance in any Dispatch Interval, the Resource will be assessed the Resources URD * NDVER Penalty.

i. The NDVER Resources URD shall be defined to be the lesser of the absolute value of: Previous Dispatch Interval MW Output – Current Dispatch Interval MW Output; or Actual SCADA Current Dispatch Interval Average Capability – Current Dispatch Interval MW Output. See Section 4.5.9.14 for calculation details.

ii. The NDVER Penalty amount shall be decided by the MWG and reviewed annually or more often if needed.

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4.5.8.14 Transmission Congestion Rights Funding Amount

(1) The Transmission Congestion Rights Funding Amount can be either a credit or charge to an Asset Owner and is calculated for each TCR instrument held by the Asset Owner and NDVER URD Penalty. TCR instruments will be fully funded in each hour. The amount to each Asset Owner (AO) for each TCR instrument for a given hour of the Operating Day is calculated as follows:

#TcrFundHrlyAmt a, h =

∑t

(TcrHrlyQty a, h, t * (DaMccHrlyPrc source, h - DaMccHrlyPrc sink, h ) ) +

∑t

( NdverUrd5MinQty a, s ,i ) * NdverPenalty

(a) Where: NdverUrd5MinQty = MIN ( ABS (RtBillMtr5MinQtya,s,i-1 - RtBillMtr5MinQtya,s,i), ABS (RtCap5MinQtya,s,i - RtBillMtr5MinQtya,s,i ) )


TcrFundAoAmt a, m, d = ∑h

TcrFundHrlyAmt a, h


TcrFundMpAmt m, d = ∑a

TcrFundAoAmt a, m, d

4.5.9.10 RUC Make Whole Payment Distribution Amount

(1)(a.8) In any Dispatch Interval in which a non-NDVER Resource operates outside of its Operating Tolerance and the Resource has not been exempted from URD per Section 4.4.4.1, one-twelfth of the Absolute Value of the Resource’s Uninstructed Resource Deviation is included as a deviation. An Asset Owner’s URD deviation is calculated as follows.

SPP Tariff (OATT) Attachment AE

Field Code Changed

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6.4.1 Uninstructed Resource Deviation

The following rules apply to the calculation of Uninstructed Resource Deviation (“URD”).

(1) For the purposes of determining URD exemptions for Resources that are part of a Common Bus

as described under Section 6.4.1.1(6) of this Attachment AE, each Asset Owner’s Resources’

combined average ramped MW Setpoint Instruction and combined actual average MW output at

the Common Bus will be used to calculate URD at the Common Bus for the Dispatch Interval for

each Asset Owner.

(2) A Resource’s URD is allocated a portion of the RUC make whole payment costs, as described

under Section 8.6.7 of this Attachment AE, in any Dispatch Interval where Resource’s URD is

outside of its Operating Tolerance unless that Resource has been exempted from URD.

(a) A generating unit Resource’s Operating Tolerance in each Dispatch Interval is equal to the

Resource’s Maximum Emergency Capacity Operating Limit multiplied by five percent

(5%), subject to a minimum of five (5) MW and a maximum of twenty (20) MW.

(b) A Dispatchable Demand Response Resource’s Operating Tolerance in each Dispatch

Interval is equal to the resource’s Maximum Emergency Capacity Operating Limit

multiplied by five percent (5%), subject to a minimum of five (5) MW and a maximum of

twenty (20) MW.

(c) A Block Demand Response Resource’s Operating Tolerance in each Dispatch Interval is

equal to the resource’s Maximum Economic Capacity Operating Limit multiplied by five

percent (5%), subject to a minimum of five (5) MW and a maximum of twenty (20) MW.

(d) The Common Bus Operating Tolerance for each Market Participant registered at a

Common Bus is equal to the sum of that Market Participant’s Resources’ Maximum

Emergency Capacity Operating Limits for Resources that are on-line multiplied by five

percent (5%), subject to a minimum of five (5) MW and a maximum of twenty (20) MW.

(2) A non-NDVER Resource’s URD is allocated a portion of the RUC make whole payment costs, as

described under Section 8.6.7 of this Attachment AE, in any Dispatch Interval where Resource’s

URD is outside of its Operating Tolerance unless that Resource has been exempted from URD.

(ea) If the absolute value of a Resource’s URD is greater than the Resource’s Operating

Tolerance in any Dispatch Interval, the Resource URD / 12 is included in the hourly

allocation of RUC make whole payment cost allocation. The Hourly URD amount is

calculated as the sum of Dispatch Interval URD for the hour. Additionally, if that Resource

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was eligible to receive a RUC make whole payment, the payment may be reduced in

accordance with Section 8.6.5 of this Attachment AE.

(3) A NDVER Resources URD is assessed a penalty that is applied to TCR funding in any Dispatch Interval where Resource’s URD is outside of its Operating Tolerance unless that Resource has been exempted from URD under Section 4.4.4.1.1

(b) If the absolute value of a NDVER Resources URD is greater than the Resource’s Operating Tolerance in any Dispatch Interval, the Resource will be assessed the Resources URD * NDVER Penalty.

i. The NDVER Resources URD shall be defined to be the lesser of the absolute value of: Previous Dispatch Interval MW Output – Current Dispatch Interval MW Output; or Actual SCADA Current Dispatch Interval Average Capability – Current Dispatch Interval MW Output.

ii. The NDVER Penalty amount shall be decided by the MWG and reviewed annually or more often if needed.

8.5.11 Transmission Congestion Rights Funding Amount

The TCR funding amount can be either a charge or a payment to an Asset Owner and is calculated

for each TCR instrument held by the Asset Owner and NDVER Penalty. The TCR instruments funding

amount is calculated for each hour as follows:

TCR Hourly Funding Amount =

TCR Hourly Quantity * [(Day-Ahead MCC at the source) – (Day-Ahead MCC at the sink)] +

NDVER Penalty Hourly Quantity

(1) Day Ahead MCC is as defined under Section 1 of this Attachment AE.

(2) TCR Hourly Quantity is the amount TCR MWs held on a particular source to sink path as awarded

to that Asset Owner in the annual TCR auction, monthly TCR auctions or secondary market as

described under Section 7 of the Attachment AE.

(3)_ NDVER Penalty calculations are defined in the Integrated Market Protocols.

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RR #: 274 Date: 2/1/2018

RR Title: NDVER to DVER Conversion Through URD


Name: Ronald Thompson Jr. Company: NPPD








Basic design









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COMMENTS

NPPD discussion items for RR274:

- What about other units that are outside the Resources URD thresholds? Shouldn’t they face the same penalty? NPPD believes all Units should be treated equally.

- Resources at times cannot stay within URD thresholds. This could be due to many different events or issues outside their control. This RR would have an NDVER get penalty costs for an event while other units would not for events outside their control. Renewables can change quickly at times due to Mother Nature and to subject them to penalties seems unreasonable.

- Some sites may not have the ability or will have costs to get real-time capability to SPP via ICCP from some resources.

- The RR states there is a benefit to the market to convert NDVERs to DVERs. If there are costs of converting from an NDVER to a DVER for that Resource there should be a way to mitigate the costs for that resource by the SPP IM Market.

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RR #: 274 Date: 1/30/2018

RR Title: NDVER to DVER Conversion Through URD


Name: Michael Mazowita Company: Olympus Power, LLC








Basic design










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COMMENTS Provide the objective language from the revision request for which you are submitting comments. … the fact that in certain cases, there is little benefit of conversion to the market or the market participant. Examples of these cases may include smaller Type I or Type II units that would require substantial $/MW to convert, or farms located in areas that rarely see negative prices (and therefore would rarely be subject to curtailment). A full conversion requirement would potentially result in an MP wasting money on a needless conversion or the MP requesting an exemption from FERC.

Olympus Power, LLC owns an existing wind farm located in a SPP area that routinely experiences negative pricing. Our wind farm consists of 80 – 1.0 MW, Mitsubishi MWT-100-61 machines (Type I generator) and has been operational since December 2001 with a long term PPA that expired on December 31, 2016. We have reviewed RR #274 and found it to be very restrictive given the age of our equipment and existing support systems. According to our wind consultants, the economic cost to comply with the proposed setpoint and curtailment standards (along with the extremely high deviation penalties) would entail costly upgrades to the SCADA system, programing changes and even the installation of an energy storage device(s) (Estimated to be $45M). Given that our windfarm is subject to the SPP open market pricing, ANY of the above changes would cause serious economic burden, when we are receiving very low around the clock pricing and not generating any PTC’s. Further, the true cause of any negative pricing scenarios is the proliferation of new Type-III and Type IV wind farms in our area, that are producing PTC’s. This needs to be addressed first.

Once again, foisting this change of 100 percent conversion of NDVERs to DVERs onto us and similar (age of the farm and equipment) wind farms is not economically feasible to a long standing/existing SPP power supplier.

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Finally Type-I and Type-II wind farms should have an exception in the Protocols of RR#274, which avoids having to file an exception with FERC (very costly process).

Multi-Day Minimum Run Time Gaming Issue (Options 1 & 2)Market Working Group (MWG)

February 6-7, 2018

Debbie James

[email protected]

Background• Potential gaming issue Resource with minimum run time greater than 24 hours can

increase energy offers at minimum and/or no-load offers Resource would not be decommitted and could receive make

whole payments (MWPs) to higher offers

• Staff presented potential options at October and November 2017 MWG meetings Option 1 (No MWP after 24 Hours) Option 2 (Binding Offer at Min. Energy for Min. Run Time) Option 3 (Offer Validation Cap) Option 4 (Mitigated Offer used for MWP after Initial

Commitment)

• MWG furthered reviewed Options 1 and 2, as well as a new option proposed by OGE at January meeting MMU identified a concern with the OGE option

2

OGE Option: MWP after 24 Hours becomes lesser of Mitigated Offer or Energy Offer for balance of Minimum Run Time• Resource receives commitment for entirety of its minimum run

time

• “As-Committed” start-up, no-load and energy offers used for DAMKT MWP for first 24 hours MWPs after first 24 hours of minimum run time will revert to

lesser of Mitigated Offer or Energy Offer for balance of minimum run time.

• “As-Committed” start up, no-load and energy at minimum offers will be used for RUC MWPs for first 24 hours. MWPs after first 24 hours of minimum run time will revert to

lesser of Mitigated Offer or Energy Offer for balance of minimum run time.

• All parameters of MWP remain same only change is to use mitigated cost or below cost energy offers as opposed to energy offers above a resource’s cost.

• Gaming opportunity for price changing after commitment is removed because resource is at best made whole to cost after initial 24 hour commitment.

3

MMU Concern with OGE Option• This option trades one loophole for another Uneconomical Resources that are normally self-committed

could change commit status to ‘market’ MPs could submit a below cost Resource offer in order to

appear economic and receive a market commitment On the first day, they would be a price-taker just like they

were when they self-committed On subsequent days, they would be eligible for MWPs at their

mitigated offer

• MWPs are based on costs that are different than the costs used during the commitment decision This is a similar, but different, form of gaming that we are

currently trying to stop Allows for guaranteed cost recovery for any Resource, with

the exception of the first day

4

Option 1: No MWP After 24 Hours

• MPs do not receive MWPs after 24 hours for duration of minimum run time MPs can submit a minimum run time greater than 24 hours MWP for start up, no-load, energy and OR allowed for first 24

hours

• “As-committed” start-up, no-load and energy offers will be used for DAMKT for first 24 hours

• “As-committed” start up, no-load and energy at minimum will be used for RUC MWPs for first 24 hours

• Medium cost to implement

5

Option 1: MMU Concerns

• Option could lead to suppressed real-time prices MPs are incentivized to offer untrue offer parameters to

attempt to receive MWPs for each day MPs could attempt to get a market commitment each day by

submitting 24 min runtime or less in the DAMKT, regardless of their actual min runtime

If not committed in the DAMKT, they could self-commit in the DARUC to meet their real physical parameters

Leads to over-commitment in real-time which suppresses prices

6

Option 2: Binding Offer at Minimum Energy for Minimum Run Time

• Resource receives commitment for entirety of its minimum run time

• “As-Committed” start-up, no-load and energy offers used for DAMKT MWPs MWPs based on lower of “as-committed” or effective offer

for duration of minimum run time

• “As-Committed” start up, no-load and energy at minimum offers will be used for RUC MWPs MWPs based on lower of “as-committed or effective offer for

duration of minimum run time

• Submitted resource offers will be used for dispatch and clearing

• If MP changes minimum economic operating limit after commitment, they will not receive a MWP

• High/Medium cost to implement 7

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RR #: 270 Date: 01/08/2018

RR Title: OCRTF Revisions to Operating Criteria Appendices System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes


Name: Neil Robertson (On Behalf of OCRTF) Company: Southwest Power Pool

Email: [email protected] Phone: 501-915-2234 Only Qualified Entities may submit Revision Requests.











Correction

Clarification

Design Enhancement










Market Protocols Section(s): Protocol Version: Operating Criteria Section(s): OP-2 Criteria Date: 12/11/2017 Planning Criteria Section(s): Criteria Date: Tariff (OATT) Section(s): Business Practice Business Practice Number: Integrated Planning Model (ITP Manual) Section(s):

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Revision Request Process Section(s): Minimum Transmission Design






The Operating Criteria Review Task Force is a joint effort between ORWG and RCWG to perform a wholesale review of SPP Operating Criteria with an emphasis on removing antiquated language and modernizing remaining language. In many cases, the current SPP Operating Criteria contains many redundancies with NERC Reliability Standards. Some portions of SPP Operating Criteria were written approximately two decades ago resulting in a need to modernize the language.

This Revision Request represents the culmination of the OCRTF’s efforts in revising SPP Operating Criteria Appendices. This Revision Request also proposes the creation of the stand-alone ‘SPP Reliability Coordinator Outage Coordination Methodology’ using the current content of Appendix OP-2 as the basis.


By removing antiquated language and modernizing remaining language, the efforts of the OCRTF will result in SPP Operating Criteria that most accurately represents the requirements needed for SPP to perform the Reliability Coordinator, Balancing Authority, Transmission Service Provider, and Reserve Sharing Group.

The creation of the stand-alone ‘SPP Reliability Coordinator Outage Coordination Methodology’ will further ensure consistency in using stand-alone documents where necessary to meet certain requirements in NERC Reliability Standards.


SPP Operating Criteria

Appendix OP-2: Outage Coordination Methodology Change History:

8/16/2011 Initial version approved by ORWG 8/30/2011 Corrected typo on Generator Planned Outages Min Lead Time – corrected to “2 Days”

from “None”. 9/22/2011 Added clarification on Reserve Shutdown submittals and created “Opportunity”

outage Priority for Generators. 2/21/2013 Added clarification on business rules of outage priorities detailing which priorities are

allowed to be entered in CROW with start times either in the future or in the past. Replaced “members” with Transmission Operators and Generator Operators. Added more language describing SPP’s outage request evaluation process. Added further language describing Reserve Shutdown resources.

6/26/2013 Added “Info” Informational Outage Request Type as an available type for Generation Outages.

12/18/2013 Added “Operational” priority and “Upcoming Model Change” as outage reason, misc clarification changes.

12/1/2015 Added language to comply with IRO-017-1. Updated planned lead time requirements.

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4/1/2016 Added modifications contained in approved Revision Request 98

4/27/2017 Added modifications contained in approved Revision Request 134

Purpose

The purpose of this methodology is to provide technical requirements and criteria to Transmission Operators, Generator

Operators and SPP Staff related to submission of Transmission and Generation outages to the SPP Reliability Coordinator

and SPP Balancing Authority via the SPP CROW tool. Outage submissions will be shared with other Reliability

Coordinators, Transmission Operators, and Balancing Authorities via the NERC System Data Exchange (SDX) and will be

used for assessing real-time and future reliability of the Bulk Electric System. Transmission and generation operators are

responsible for submitting all outages through the CROW tool. All other transmission operators will be able to view and

identify all outages that are submitted through CROW. SPP reserves the right to approve, deny, or reschedule any

outage deemed necessary to ensure system reliability on a case by case basis regardless of date of submission.

1. Transmission Outages and Operations

For the purpose of identifying applicable facilities, the nominal kV level of the facility will be used. For transformers,

use the low side voltage class. Example: A 161/69kV transformer shall be classified as a 69kV facility for the

purposes of this methodology.

a. Forced Transmission Outage Submission Requirements

Forced outages of all transmission facilities greater than 60kV that are modeled in the SPP regional models

and have been modeled in the CROW tool should be submitted within 30 minutes or as soon as practical

after the outage. Each outage submission must be accompanied by a Planned End Time, Forced Outage

Priority, an associated Outage Request Type, and an Outage Cause. Forced Outage Priory outages will be

considered Non-Recallable. At the time of submission, forced outage reasons may not be known so a reason

of Unknown may be selected. It is recognized that the duration of a forced outage will typically not be

known at the time of the initial submission. The Planned End Time should be the best estimate for the

return of the outaged facility. Any known updates to the Planned End Time and/or reason for the outage

shall be submitted promptly to the CROW tool.

b. Scheduled Transmission Outage Submission Requirements

Scheduled outages of all BES elements must be submitted to the CROW tool and approved by the Reliability

Coordinator prior to implementing the outage. Scheduled outages of all other transmission elements

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greater than 60kV that are modeled in the SPP regional models must be submitted to the Reliability

Coordinator’s CROW tool for coordination and review. Each outage submission must be accompanied by a

Planned Outage Start Time and Planned End Time, Outage Priority, Outage Request Type, and Outage Cause.

Each outage request must also be designated as Non-Recallable, or provide an expected Recall time if

directed. Sufficient notation in the outage scheduler “Requestor Notes” comment field should include a

description or explanation for the outage. An incomplete outage request of any missing data could result in

the outage being denied. Once the actual outage takes place, the Actual Start Time of the outage must be

submitted to the CROW tool. When the outage has ended, the Actual End Time of the outage must be

updated.

c. Transmission Outage Priority and Timing Requirements

Each Transmission Outage submitted must include one of the following Outage Priorities. Forced outages of

equipment must be submitted with a Priority of Forced as defined below. The CROW Outage Scheduler will

enforce the lead time requirements of each Outage Priority. Outages that are not planned will have a lower

priority and may not be approved by the RC. Outages not submitted as planned will be reviewed and

approved by SPP on a case-by-case basis. The risk of imminent equipment failure will have priority over

other outages including planned. If sufficient time is not available to analyze the request then the outage

will be denied.

Priority Definition Minimum

Lead Time

Maximum

Lead Time

Planned Equipment is known to be operable with little risk of leading to a forced

outage. As required for preventive maintenance, troubleshooting, repairs that

are not viewed as urgent, system improvements such as capacity upgrades, the

installation of additional facilities, or the replacement of equipment due to

obsolescence.

14 Calendar

Days

None

Discretionary Equipment is known to be operable with little risk of leading to a forced

outage; however the timeline for submission of Planned outage priority has

passed. Discretionary outages are required to be submitted at least 2 calendar

days in advance. Due to the shorter lead time, this outage priority has

increased risk of being denied based upon higher priority outage requests.

2 Days 14

Calendar

Days

Opportunity Lead time may be very short or zero. An outage that can be taken due to

changed system conditions (ie Generator suddenly offline for forced outage

allows transmission work to be done).

None 7 Days

Operational Equipment is removed from service for operational reasons such as voltage

control, constraint mitigation as identified in an operating procedure, etc.

None None

Urgent Equipment is known to be operable, yet carries an increased risk of a forced

outage or equipment loss. The equipment remains in service until

maintenance crews are ready to perform the work.

2 Hours 48 Hours

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Emergency Equipment is to be removed from service by operator as soon as possible

because of safety concerns or increased risk to grid security.

None 2 Hours

Forced Equipment is out of service at the time of the request. None 1 Hour

d. Transmission Outage Equipment Request Types

Each Transmission outage (scheduled and forced) request submitted must include one of the following

Outage Request Types.

Outage Request Type Definition Modeling Assumptions

Out of Service (OOS) Equipment is out of service. SDX = Open

EMS = Open

Normally Open (NO) Equipment is normally out of service and is identified as normally open in

the SPP regional models. Normally Open request type is used to close

(place in service) a normally open facility.

SDX = Closed

EMS = Closed

Informational (INF) Used for outage events that are not covered by one of the other Outage

Equipment Request Types. Not an out of service event.

None – Informational Only

Hot Line Work (HLW) Work is being performed on live or energized equipment. None – Informational Only

General System

Protection (GSP)

Work is being performed on protection systems. Requestor shall

specifically identify protection systems out of service and any

modification to operation or behavior of system contingencies.


e. Transmission Outage Request Reasons/Causes

Each Transmission Outage Request must be submitted with one of the following reasons for the outage.

Reason/Cause Definition

Maintenance & Construction Outages to facilitate repair, maintain, or upgrade of facility related equipment. This includes

clearances to perform vegetation management. Does not include outages to support Maintenance &

Construction of other facilities. Those should be submitted as Voltage or SOL Mitigation.

Third Party Request Non-transmission facility related requests for clearance or work such as highway construction.

Voltage Mitigation Operation of facilities to preserve or correct Bulk Electric System voltage.

SOL Mitigation (Thermal) Operation of facilities to preserve or correct Bulk Electric System thermal loading issues.

Weather/Environmental/Fire

(excluding Lightning)

Outages caused by wind, ice, snow, fire, flood, etc. All weather or environmental causes excluding

lightning strikes.

Lightning Outages caused by direct or indirect Lightning strikes.

Foreign Interference (including

contamination)

Outages caused by blown debris, bird droppings, kites, falling conductors, airplanes, etc.

Vandalism/Terrorism/Malicious Acts Outages resulting from known or suspected vandalism, terrorism, or other malicious acts.

Equipment Failure Outages resulting from failure of facility related equipment.

Imminent Equipment Failure Operation of facilities due to expected imminent facility rated equipment failure.

Protection System Failure including

Undesired Operations

Operation of facilities due to failure or undesired operation of the facility protection systems.

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Vegetation Outages resulting from contact with vegetation. This does not include outages due to clearances

required to perform vegetation management which should be submitted as Maintenance &

Construction. This does not include vegetation blown into rights of way or into contact with facilities

which should be submitted as Foreign Interference.

BES Condition (Stability, Loading) Outages resulting from Bulk Electric System conditions such as islanding, cascading outages, sudden

thermal loading due to other contingencies, transient stability conditions, etc.

Unknown Operation of facilities due to an unknown reason. Most forced outages will be submitted with an

initial reason of Unknown. Once the actual reason for the operation is known, the outage requestor

should update the outage request. SPP Staff will follow up after some time to determine the actual

outage reason for any outages which still have a reason of Unknown submitted.

Upcoming Model Change Outages created for the purpose of correcting system topology related to pending model changes.

This cause should only be used by SPP operations personnel.

Other Operation of facilities due to a reason not listed here.

f. Generation Outages/Derate Submission Requirements

All generating resources within the SPP Reliability Coordinator Area or Balancing Authority Area meeting one

or more of the criteria listed below (regardless of voltage connection) shall report in CROW all Outages and

Derates if the gross reduction in capability is greater than or equal to 25 MW. Changes to the reported

capability shall be reported in 25 MW increments from the last reported Derate level regardless of system

capability/conditions.

• Generating resource(s) with gross individual nameplate rating greater than 20 MVA or gross

plant/facility aggregate nameplate rating greater than 25 MVA; or

• Blackstart Resources identified in a Transmission Operator’s restoration plan; or

• Dispersed power producing resources with aggregate capacity greater than 25 MVA (gross aggregate

nameplate rating) utilizing a system designed primarily for aggregating capacity.

If SPP requires generating resources that do not meet the criteria above to report their Outages and/or

Derates in CROW, then SPP shall send a written notice to the responsible entity stating their obligations and

identifying the specific generating resources.

For the generating resources under the functional control of a Generator Operator (GOP) registered with

NERC, the GOP shall be the responsible entity for reporting Outages and Derates in CROW. For all other

generating resources not under the functional control of a registered GOP, the resource owner shall be the

responsible entity for reporting Outages and Derates in CROW.

g. Forced Generation Outages/Derate Submission Requirements

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Forced outages or capability limitations in the form of Derates should be submitted within 30 minutes or as

soon as practical after the outage or capability limitation occurs. Forced Generation Outages and Derates

are required to be accompanied by a reason for the outage or limitation. Each Outage or Derate submission

must be accompanied by a Planned End Time, a Forced Outage Priority, Outage Request Type, and an

Outage Cause. Forced Outage Priority requests will be assumed to be Non-Recallable. At the time of

submission, forced outage reasons may not be known so a reason of Unknown may be selected. The

Planned Start Time of the outage should reflect the best known time of the actual outage. The CROW tool

will ensure that the Actual Start Time and Planned Start Time are equal. Any known updates to the Planned

End Time and/or reason for the outage shall be submitted promptly to the CROW tool. This outage

submission shall be in addition to any other notifications made to SPP such as through a Reserve Sharing

event, or Resource Plan submission. SPP shall accept each forced outage within 30 minutes of submission.

h. Scheduled Generation Outages/Derate Submission Requirements

Scheduled Outages or capability limitations in the form of Derates should be submitted as soon as possible

and to the extent possible on an annual rolling basis. Planned Generation Outages are required to be

accompanied by a reason for the outage or limitation. Each Outage or Derate submission must be

accompanied by a Planned Outage Start Time and Planned End Time, an associated Outage Priority, an

associated Outage Request Type, and an Outage Cause. Each outage request must also be designated as

Non-Recallable, or provide an expected Recall time if directed. Once the actual outage takes place, the

Actual Start Time of the outage must be submitted to the CROW tool. SPP shall respond to all scheduled

outages or capacity limitation changes in the CROW system within 30 minutes from the time of submission

for changes that are effective within the next 48 hours. When the outage has ended, the Actual End Time of

the outage must be updated. This outage submission shall be in addition to any other notifications made to

SPP such as through a Reserve Sharing event or Resource Plan submission.

1. Reserve Shutdown

Resources in SPP are considered to be in a Reserve Shutdown outage status when SPP has approved an

outage request via the CROW tool, making the Resource unavailable for SPP commitment and dispatch

due to reasons other than to perform maintenance or to repair equipment. These resources will be

reflected in Planned Outage for a reason of Excess Capacity/Economic.

Resources that are offline for economic or excess capacity reasons and can be recalled, started, and

synchronized to pick up load within 7 days are not required to request an outage via the CROW tool.

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However, these Resources may request and be shown in Reserve Shutdown outage status if the outage

is approved by SPP.

i. Generation Outage/Derate Priority and Timing Requirements

Each Generation Outage or Derate submitted must include one of the following Outage Priorities. Forced

outages of equipment must be submitted with a Priority of Forced as defined below. The CROW tool will

enforce the lead time requirements of each Outage Priority.

Priority Definition Minimum Lead

Time

Maximum Lead

Time


outage. As required for preventive maintenance, troubleshooting, repairs

that are not viewed as urgent, system improvements such as capacity

upgrades, the installation of additional facilities, or the replacement of

equipment due to obsolescence.

14 Calendar

Days

None


changed system conditions (ie Loading conditions allow planned work to

occur with short lead time).

None 14 Calendar

Days

Operational Equipment is removed from service for operational reasons. This could

include outages or derates due to reliability directives or other

operational concerns not necessarily related to the generating equipment

or capability, and outages entered to correct system topology in

operating models.

None None

Urgent Equipment is known to be operable, yet carries an increased risk of a

forced outage or equipment loss. The equipment remains in service until


24 Hours 48 Hours



None 24 Hours


j. Generation Outage/Derate Request Type

Each Generation outage or Derate request submitted must include one of the following Outage Request

Types.

Request Type Definition Modeling Assumption

Out of Service Generator or Resource is out of service. SDX = offline

EMS = offline

Derate Generator or Resource maximum capability is lowered from

normal operation. A new maximum capability is required to be

submitted with each Outage Request Type of Derate.

SDX = online, with new lower PMAX

EMS = online, with new lower PMAX

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Informational

(INF)

Used for communicating and documenting information to SPP

regarding the resource. This status is not interpreted as a loss of

capability or capacity. This status may be used to communicate

anticipated fuel delivery issues.


k. Generation Outage/Derate Request Reasons/Causes

Each Generation Outage or Derate Request must be submitted with one of the following reasons for the

outage.

Reason/Cause Definition

Equipment Failure Failure in station generation, prime mover, or other equipment has occurred. Does not include failure

of GSU transformers or interconnection facilities. Does include equipment related to fuel delivery

considered a part of the resource (such as a coal mill).

Imminent Equipment Failure Expected failure in station generation, prime mover, or other equipment. Does not include failure of

GSU transformers or interconnection facilities. Does include equipment related to fuel delivery


BES Reliability Removal from service or limitation to preserve or correct Bulk Electric System reliability issues either

through action of a Special Protection System, runback scheme, or as mitigation of another reliability

event.

Loss of Interconnection Failure in interconnection equipment such as GSU transformers or other interconnection facilities.

Does not include loss of synchronization due to stability or islanding type events.

BES Stability Removal from service or limitation due to Bulk Electric System stability issues. Includes loss of

synchronization due to transient stability and/or islanding issues.

Fuel Supply Removal from service or limitation due to fuel supply interruption. Does not include local equipment

failures related to fuel supply. Includes loss of gas pressure due to offsite issue, coal supply exhaustion,

lack of headwater issues for hydro, etc.

Regulatory/Safety/Environm

ental

Removal from service or limitation due to Regulatory/Safety/Environmental restrictions such as

emission limits, OSHA, NRC, or other regulatory body limitations. Includes damage caused by weather

including but not limited to lightning, flood, earthquake, etc. This may also include limitations to hydro

due to low dissolved oxygen in tailwater or to control downstream flooding.

Unknown The default Forced Outage/Derate reason will be pre-populated with Unknown at the time of

submittal. Either during the initial outage submittal or at a later time, the Unknown reason must be

changed to reflect the actual experienced issue.

Routine Generator

Maintenance

Removal from service or limitation in order to perform repair or inspection of generation equipment.

Supporting Transmission

Outage

Removal from service or limitation in order to support a scheduled transmission outage.

Excess Capacity/Economic Removal from service or limitation due to seasonal or system capacity need. This includes peaker units

not expected to be used during winter months.

Upcoming Model Change Outages created for the purpose of correcting system topology related to pending model changes. This

cause should only be used by SPP operations personnel.

2. Outage Review / Approval Process

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All outages submitted will be studied to determine if any potential reliability conflicts are found. The general study

method employed by SPP staff involves building representative models of the study time period and implementing

all outage requests submitted for that time period. The resulting modeled system is then studied to determine if

any reliability issues can be identified. If issues are identified, various mitigation steps are then studied including but

not limited to, generation redispatch, system reconfiguration, rescheduling of lower priority outages, and facility

rating reviews. If mitigations are unsuccessful in resolving the conflict, an outage request may need to be

rescheduled or denied. Priority of outage requests is reviewed based upon initial submission time, outage priority

category, reason for the outage, and impact to reliability. To the extent possible, higher priority category requests

will be given preference, but ultimately it is up to the SPP RC to resolve any scheduling conflicts.

In the event that a conflict occurs with another Reliability Coordinator’s outage, a priority of the outages will be

determined based on submitted time, reason for outage, and impact to reliability. The determination will be

reviewed and agreed upon by each Reliability Coordinator. The outage that is deemed a higher priority will be

approved.

An outage that has been studied will receive a status change to one of the following statuses: Approved, Denied, or

Pre-Approved. Pre-Approval will be provided in certain cases where an outage has been submitted, but for various

reasons SPP is unable to adequately study the outage or determine that no reliability conflicts exist. The Pre-

Approval may also be dependent upon a specific operating condition that may need to be met but cannot be

guaranteed at the time the Pre-Approval is issued such as but not limited to a load forecast threshold, simultaneous

outage, new facilities in-service, etc. When the outage request can be adequately studied to determine that no

reliability conflict exists, the status will be changed to Approved.

All outages submitted within the appropriate advance timeframe will be reviewed as soon as possible by SPP

Operations Staff. The review timelines for SPP are as follows:

a. Transmission

1. For all BES outage requests submitted 30 days or more prior to scheduled start time, Pre-approval or

denial will be provided within 5 business days.

2. For all BES outage requests submitted 14 days or more but less than 30 days prior to the scheduled

start time, pre-approval or denial will be provided within 3 business days.

3. For all BES outage requests submitted 14 days or less prior to scheduled start time, pre-approval or

denial will be provided within 2 business days.

b. Generators

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1. For all Generator outage requests submitted 30 days or more prior to scheduled start time, Pre-

approval or denial will be provided within 5 business days.

2. For all Generator outage requests submitted 14 days or more but less than 30 days prior to the

scheduled start time, Approval, Pre-approval or denial will be provided within 3 business days.

3. For all Generator outage requests submitted 14 days or less prior to scheduled start time, Approval,

Pre-approval or denial will be provided within 2 business days.

4. SPP will provide their best effort for outages submitted within 2 business days.

3. Outage Status Changes

All outages submitted will reside in one of several status types throughout the life cycle of the outage. These status

types and their associated definition are:

Status Definition

Proposed The outage request has been saved in the CROW tool and remains under the full revision control until the outage is

entered into a Submitted state by the requestor. If the requestor does not move a proposed request to the

submitted status within 30 days of the planned start date, the outage is automatically Withdrawn. Proposed

outage request status dates DO NOT qualify for outage queuing in conflict resolution. Proposed outage requests

are not provided to external systems such as NERC SDX/IDC or SPP’s EMS.

Submitted The outage request has been submitted into the CROW tool and is ready for review by SPP. The outage requestor

does not possess revision control of the outage in this status. A revision request may be submitted to SPP regarding

an outage in Submitted status. Outage requests in this state are provided to external systems such as NERC

SDX/IDC or SPP’s EMS.

Study SPP will change the status type to Study once the active study process begins. Outage requests in this state are

provided to external systems such as NERC SDX/IDC or SPP’s EMS.

Preliminary

Approved

Outage requests with Preliminary Approved status have been approved based on long lead studies and may need

additional analysis closer to the planned start date or finalization of an Operating Guide. Once the restudy is

complete or final opguide posted, the outage status is changed to Approved. Outage requests in this state are


Approved Approved state indicates SPP has completed the study process and the outage request is ready for implementation.

Outage requests in this state are provided to external systems such as NERC SDX/IDC or SPP’s EMS.

Implemented Once the outage request actual start time has been entered, signifying that the outage has begun, the outage

status is changed to Implemented. Outage requests in this state are provided to external systems such as NERC


Completed Once the outage request actual end time has been entered, signifying that the outage has ended, the outage status

is changed to Completed. Outage requests in this state are NO LONGER provided to external systems such as NERC


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Certain outage requests may result in a need by the outage requestor to withdraw or cancel the outage request.

SPP’s study results and coordination may also result in status changes to an outage reflecting the inability of the

outage request to be approved or implemented. These status types are:

Status Definition

Withdrawn The outage requestor can withdraw an outage request while it is still in Proposed status. Once in Study or Approved

status, the request must be Cancelled. Outage requests in this state are NOT provided to external systems such as

NERC SDX/IDC or SPP’s EMS.

Cancelled The outage requestor can cancel a Submitted or Approved outage. Cancelled outages can be reinstated by the

requestor, provided the planned start of the outage falls within the business rules for lead time submission. Outage

requests in this state are NOT provided to external systems such as NERC SDX/IDC or SPP’s EMS.

Denied An outage request that is in Submitted or Study status can be Denied. If SPP denies the request, the status changes

to Denied. This state indicates the outage request was not approved for implementation. Outage requests in this

state are NOT provided to external systems such as NERC SDX/IDC or SPP’s EMS.

Revoked Once an outage request has been Approved, it can be Revoked at an time (ie, before or during the outage). Outage


4. Using CROW to Submit Other Types of Information to SPP

CROW can be used as a mechanism to submit information to SPP other than outage and or status information on

lines, transformers, and generators. All other types of information exchange made using CROW not previously

described in this Appendix 12 will follow the guidelines below.

For Reactor, Capacitor, Circuit Breaker, Disconnect, and Protection Scheme (Special Protection System) Equipment

Types

- All CROW submissions for these equipment types will be made in accordance with Appendix 12 Sections 1d,

1e, and 1f

- Appendix 12 Section 3 Outage Review / Approval Process will not apply to these equipment types

- These equipment types will not progress through the various states described in Appendix 12 Section 4

Outage Status Changes

For Generator Automatic Voltage Regulator (AVR) and Power System Stabilizers Equipment Types

- All CROW submissions for this equipment type will be made in accordance with Appendix 12 Sections 2c, 2d,

and 2e

- Appendix 12 Section 3 Outage Review / Approval Process will not apply to these equipment types

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- These equipment types will not progress through the various statuses described in Appendix 12 Section 4

Outage Status Changes

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Appendix OP-13: Voltage Stability Assessment and Monitoring Methodology

Change History: 4/27/2017 Initial Version

Purpose

The purpose of this methodology is to provide technical requirements and criteria to Transmission Operators, Generator Operators and SPP Staff related to the voltage stability assessment and monitoring of pre- and post-contingency (single and multiple) operating conditions. Monitored scenarios will be identified using available reliability studies, real-time system information, outage schedules, and other relevant sources. During the different Operating Horizons, the pre- and post-contingency operating conditions being studied may require adjustment. The SPP RC and TOPs must determine and coordinate which Multiple Contingencies within the TOP areas are credible to be utilized for study in the operating horizon. If the TOP or the SPP RC determine that changes are required for a pre- or post-contingency operating condition, such changes shall be communicated to the affected entities. The SPP RC will coordinate with all applicable impacted TOPs or neighboring RCs. The use of proxy flowgate limits for voltage stability will be communicated in the same manner as other flowgate limits and information. 1. Study Models

1. SPP utilizes both the EMS model and the approved Planning Base Cases for establishing, calculating and monitoring SOLs/IROLs in the operating horizons. These cases are updated periodically to reflect expected system topology changes based on reported facility outages or upgrades.

2. Real Time and Post Contingent Voltage Stability Limits

1. The SPP RC will perform a voltage stability assessment for identified areas and paths that have a reasonable potential to cause real-time and post-contingency voltage instability.

2. The SPP RC may identify and establish voltage stability limits based on the voltage stability assessment results and will coordinate the voltage stability limits with the affected TOPs. Voltage stability limits may require development of new temporary flowgates.

3. Voltage stability real-time and single-contingency limits will include a 5% MW margin.

4. Voltage stability multiple-contingency limits will include a 2.5 % MW margin.

5. A voltage stability limit more restrictive than an existing SOL will be identified as the revised SOL and communicated to affected entities prior to implementation in congestion management procedures.

6. If system conditions in conjunction with real-time voltage stability assessments are determined to be stable, conditions within the 5% MW margin of the voltage stability limit than was previously defined, then the SPP RC may adjust the limit after coordinating an agreement with the affected TOPs.

7. The RC will coordinate with the impacted TOPs to establish necessary mitigations and operating plans.

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SPP RC Outage Coordination Methodology (Initial Creation)

Appendix OP-2:Southwest Power Pool

Reliability Coordinator Outage Coordination Methodology Purpose

The purpose of this methodology is to provide technical requirements and criteria to Transmission Operators,

Generator Operators and SPP Staff related to submission of Transmission and Generation outages to the SPP

Reliability Coordinator and SPP Balancing Authority via the SPP CROW tool. Outage submissions will be shared

with other Reliability Coordinators, Transmission Operators, and Balancing Authorities via the NERC System

Data Exchange (SDX) and will be used for assessing real-time and future reliability of the Bulk Electric System.

Transmission and Ggeneratorion Ooperators are responsible for submitting all outages through the CROW

tool. All other Ttransmission Ooperators will be able to view and identify all outages that are submitted

through the CROW tool. SPP reserves the right to approve, deny, or reschedule any outage deemed necessary

to ensure system reliability on a case by case basis regardless of date of submission.

Use of Capitalized Terms

For the purposes of this document, the following rules should be used concerning the use of capitalized terms.

Non-italicized capitalized terms are defined by the NERC Glossary of Terms. Italicized capitalized terms

indicate terms used in the CROW tool itself. Further description of many of these italicized capitalized terms

can be found in the CROW Outage Scheduler Web GUI Tutorial.

5.1. Transmission Outages and Operations

For the purpose of identifying applicable facilities, the nominal kV level of the facility will be used. For

transformers, use the low side voltage class. Example: A 161/69kV transformer shall be classified as a

69kV facility for the purposes of this methodology.

a. Forced Transmission Outage Submission Requirements

Forced outages of all transmission facilities greater than 60kV that are modeled in the SPP regional

models and have been modeled in the CROW tool should be submitted within 30 minutes or as

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soon as practical after the outage. Each outage submission must be accompanied by a Planned End

Time, Forced Outage Priority, an associated Outage Request Type, and an Outage Cause. Forced

Outage Priory outages will be considered Non-Recallable. At the time of submission, forced outage

reasons may not be known so a reason of Unknown may be selected. It is recognized that the

duration of a forced outage will typically not be known at the time of the initial submission. The

Planned End Time should be the best estimate for the return of the outaged facility. Any known

updates to the Planned End Time and/or reason for the outage shall be submitted promptly to the

CROW tool.

b. Scheduled Transmission Outage Submission Requirements

Scheduled outages of all BES elements must be submitted to the CROW tool and approved by the

Reliability Coordinator prior to implementing the outage. Scheduled outages of all other

transmission elements greater than 60kV that are modeled in the SPP regional models must be

submitted to the Reliability Coordinator’s CROW tool for coordination and review. Each outage

submission must be accompanied by a Planned Outage Start Time and Planned End Time, Outage

Priority, Outage Request Type, and Outage Cause. Each outage request must also be designated as

Non-Recallable, or provide an expected Recall Ttime if directed. Sufficient notation in the outage

scheduler “Requestor Notes” comment field should include a description or explanation for the

outage. An incomplete outage request of any missing data could result in the outage being denied.

Once the actual outage takes place, the Actual Start Time of the outage must be submitted to the

CROW tool. When the outage has ended, the Actual End Time of the outage must be updated.

c. Transmission Outage Priority and Timing Requirements

Each Transmission Outage submitted must include one of the following Outage Priorities. Forced

Ooutages of equipment must be submitted with an Outage Priority of Forced as defined below.

The CROW Outage Schedulertool will enforce the lead time requirements of each Outage Priority.

Outages that are not planned will have a lower priority and may not be approved by the RC.

Outages not submitted as planned will be reviewed and approved by SPP on a case-by-case basis.

The risk of imminent equipment failure will have priority over other outages including planned. If

sufficient time is not available to analyze the request then the outage will be denied.

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Priority Definition Minimum

Lead Time

Maximum

Lead Time


outage. As required for preventive maintenance, troubleshooting, repairs that

are not viewed as urgent, system improvements such as capacity upgrades, the

installation of additional facilities, or the replacement of equipment due to

obsolescence.

14 Calendar

Days

None

Discretionary Equipment is known to be operable with little risk of leading to a forced

outage; however the timeline for submission of Planned outage priority has

passed. Discretionary outages are required to be submitted at least 12 calendar

days in advance. Due to the shorter lead time, this outage priority has

increased risk of being denied based upon higher priority outage requests.

12 Days 14

Calendar

Days


changed system conditions (ie Generator suddenly offline for forced outage

allows transmission work to be done).

None 7 Days

Operational Equipment is removed from service for operational reasons such as voltage

control, constraint mitigation as identified in an operating procedure, etc.

None None

Urgent Equipment is known to be operable, yet carries an increased risk of a forced

outage or equipment loss. The equipment remains in service until


2 Hours 48 Hours14

Days



None 2 Hours


d. Transmission Outage Equipment Request Types

Each Transmission outage (scheduled and forced) request submitted must include one of the

following Outage Request Types.

Outage Request Type Definition Modeling Assumptions

Out of Service (OOS) Equipment is out of service. SDX = Open

EMS = Open

Normally Open (NO) Equipment is normally out of service and is identified as normally open in

the SPP regional models. Normally Open request type is used to close

(place in service) a normally open facility.

SDX = Closed

EMS = Closed

Informational (INF) Used for outage events that are not covered by one of the other Outage

Equipment Request Types. Not an out of service event.


Hot Line Work (HLW) Work is being performed on live or energized equipment. None – Informational Only

General System

Protection (GSP)

Work is being performed on protection systems. Requestor shall

specifically identify protection systems out of service and any

modification to operation or behavior of system contingencies.


e. Transmission Outage Request Reasons/Causes

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Each Transmission Outage Request must be submitted with one of the following reasons for the

outage. Reason/Cause Definition

Maintenance & Construction Outages to facilitate repair, maintain, or upgrade of facility related equipment. This includes

clearances to perform vegetation management. Does not include outages to support Maintenance &

Construction of other facilities. Those should be submitted as Voltage or SOL Mitigation.

Third Party Request Non-transmission facility related requests for clearance or work such as highway construction.

Voltage Mitigation Operation of facilities to preserve or correct Bulk Electric System voltage.

SOL Mitigation (Thermal) Operation of facilities to preserve or correct Bulk Electric System thermal loading issues.

Weather/Environmental/Fire

(excluding Lightning)

Outages caused by wind, ice, snow, fire, flood, etc. All weather or environmental causes excluding

lightning strikes.

Lightning Outages caused by direct or indirect Lightning strikes.

Foreign Interference (including

contamination)

Outages caused by blown debris, bird droppings, kites, falling conductors, airplanes, etc.

Vandalism/Terrorism/Malicious Acts Outages resulting from known or suspected vandalism, terrorism, or other malicious acts.

Equipment Failure Outages resulting from failure of facility related equipment.

Imminent Equipment Failure Operation of facilities due to expected imminent facility rated equipment failure.

Protection System Failure including

Undesired Operations

Operation of facilities due to failure or undesired operation of the facility protection systems.

Vegetation Outages resulting from contact with vegetation. This does not include outages due to clearances

required to perform vegetation management which should be submitted as Maintenance &

Construction. This does not include vegetation blown into rights of way or into contact with facilities

which should be submitted as Foreign Interference.

BES Condition (Stability, Loading) Outages resulting from Bulk Electric System conditions such as islanding, cascading outages, sudden

thermal loading due to other contingencies, transient stability conditions, etc.

Unknown Operation of facilities due to an unknown reason. Most forced outages will be submitted with an

initial reason of Unknown. Once the actual reason for the operation is known, the outage requestor

should update the outage request. SPP Staff will follow up after some time to determine the actual

outage reason for any outages which still have a reason of Unknown submitted.

Upcoming Model Change Outages created for the purpose of correcting system topology related to pending model changes.

This cause should only be used by SPP operations personnel.

Other Operation of facilities due to a reason not listed here.

6.2. Generation Outages/Derates

a. Generation Outages/Derate Submission Requirements

All generating resources within the SPP Reliability Coordinator Area or Balancing Authority Area

meeting one or more of the criteria listed below (regardless of voltage connection) shall report in

the CROW tool all Outages and Derates if the gross reduction in capability is greater than or equal

to 25 MW. Changes to the reported capability shall be reported in 25 MW increments from the last

reported Derate level regardless of system capability/conditions.

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1. Generating resource(s) with gross individual nameplate rating greater than 20 MVA or gross

plant/facility aggregate nameplate rating greater than 25 MVA; or

2. Blackstart Resources identified in a Transmission Operator’s restoration plan; or

3. Dispersed power producing resources with aggregate capacity greater than 25 MVA (gross

aggregate nameplate rating) utilizing a system designed primarily for aggregating capacity.

If SPP requires generating resources that do not meet the criteria above to report their Outages

and/or Derates in the CROW tool, then SPP shall send a written notice to the responsible entity

stating their obligations and identifying the specific generating resources.

For the generating resources under the functional control of a Generator Operator (GOP)

registered with NERC, the GOP shall be the responsible entity for reporting Outages and Derates in

the CROW tool. For all other generating resources not under the functional control of a registered

GOP, the resource owner shall be the responsible entity for reporting Outages and Derates in the

CROW tool.

b. Forced Generation Outages/Derate Submission Requirements

Forced outages or capability limitations in the form of Derates should be submitted within 30

minutes or as soon as practical after the outage or capability limitation occurs. Forced Generation

Outages and Derates are required to be accompanied by a reason for the outage or limitation.

Each Outage or Derate submission must be accompanied by a Planned End Time, a Forced Outage

Priority, Outage Request Type, and an Outage Cause. Forced Outage Priority requests will be

assumed to be Non-Recallable. At the time of submission, forced outage reasons may not be

known so a reason of Unknown may be selected. The Planned Start Time of the outage should

reflect the best known time of the actual outage. The CROW tool will ensure that the Actual Start

Time and Planned Start Time are equal. Any known updates to the Planned End Time and/or

reason for the outage shall be submitted promptly to the CROW tool. This outage submission shall

be in addition to any other notifications made to SPP such as through a rReserve sSharing event, or

rResource pPlan submission. SPP shall accept each forced outage within 30 minutes of submission.

c. Scheduled Generation Outages/Derate Submission Requirements

Scheduled Outages or capability limitations in the form of Derates should be submitted as soon as

possible and to the extent possible on an annual rolling basis. Planned Generation Outages are

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required to be accompanied by a reason for the outage or limitation. Each Outage or Derate

submission must be accompanied by a Planned Outage Start Time and Planned End Time, an

associated Outage Priority, an associated Outage Request Type, and an Outage Cause. Each outage

request must also be designated as Non-Recallable, or provide an expected Recall Ttime if directed.

Once the actual outage takes place, the Actual Start Time of the outage must be submitted to the

CROW tool. SPP shall respond to all scheduled outages or capacity limitation changes in the CROW

system tool within 30 minutes from the time of submission for changes that are effective within the

next 48 hours. When the outage has ended, the Actual End Time of the outage must be updated.

This outage submission shall be in addition to any other notifications made to SPP such as through

a rReserve sSharing event or rResource pPlan submission.

2.1. Reserve Shutdown

Resources in SPP are considered to be in a Reserve Shutdown outage status when SPP has

approved an outage request via the CROW tool, making the rResource unavailable for SPP

commitment and dispatch due to reasons other than to perform maintenance or to repair

equipment. These resources will be reflected in Planned Outage for a reason of Excess

Capacity/Economic.

Resources that are offline for economic or excess capacity reasons and can be recalled, started,

and synchronized to pick up load within 7 days are not required to request an outage via the

CROW tool. However, these rResources may request and be shown in Reserve Shutdown

outage status if the outage is approved by SPP.

d. Generation Outage/Derate Priority and Timing Requirements

Each Generation Outage or Derate submitted must include one of the following Outage Priorities.

Forced outages of equipment must be submitted with a Priority of Forced as defined below. The

CROW tool will enforce the lead time requirements of each Outage Priority.

Priority Definition Minimum Lead

Time

Maximum Lead

Time


outage. As required for preventive maintenance, troubleshooting, repairs

that are not viewed as urgent, system improvements such as capacity

upgrades, the installation of additional facilities, or the replacement of

equipment due to obsolescence.

14 Calendar

Days

None

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changed system conditions (ie Loading conditions allow planned work to

occur with short lead time).

None 14 Calendar

Days

Operational Equipment is removed from service for operational reasons. This could

include outages or derates due to reliability directives or other

operational concerns not necessarily related to the generating equipment

or capability, and outages entered to correct system topology in

operating models.

None None

Urgent Equipment is known to be operable, yet carries an increased risk of a

forced outage or equipment loss. The equipment remains in service until


24 Hours 48 Hours



None 24 Hours


e. Generation Outage/Derate Request Type

Each Generation Ooutage or Derate request submitted must include one of the following Outage

Request Types. Request Type Definition Modeling Assumption

Out of Service Generator or Resource is out of service. SDX = offline

EMS = offline

Derate Generator or Resource maximum capability is lowered from

normal operation. A new maximum capability is required to be

submitted with each Outage Request Type of Derate.

SDX = online, with new lower PMAX

EMS = online, with new lower PMAX

Informational

(INF)

Used for communicating and documenting information to SPP

regarding the resource. This status is not interpreted as a loss of

capability or capacity. This status may be used to communicate

anticipated fuel delivery issues.


f. Generation Outage/Derate Request Reasons/Causes

Each Generation Outage or Derate Request must be submitted with one of the following reasons

for the outage. Reason/Cause Definition

Equipment Failure Failure in station generation, prime mover, or other equipment has occurred. Does not include failure

of GSU transformers or interconnection facilities. Does include equipment related to fuel delivery


Imminent Equipment Failure Expected failure in station generation, prime mover, or other equipment. Does not include failure of

GSU transformers or interconnection facilities. Does include equipment related to fuel delivery


BES Reliability Removal from service or limitation to preserve or correct Bulk Electric System reliability issues either

through action of a Special Protection System, runback scheme, or as mitigation of another reliability

event.

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Loss of Interconnection Failure in interconnection equipment such as GSU transformers or other interconnection facilities.

Does not include loss of synchronization due to stability or islanding type events.

BES Stability Removal from service or limitation due to Bulk Electric System stability issues. Includes loss of

synchronization due to transient stability and/or islanding issues.

Fuel Supply Removal from service or limitation due to fuel supply interruption. Does not include local equipment

failures related to fuel supply. Includes loss of gas pressure due to offsite issue, coal supply exhaustion,

lack of headwater issues for hydro, etc.

Regulatory/Safety/Environm

ental

Removal from service or limitation due to Regulatory/Safety/Environmental restrictions such as

emission limits, OSHA, NRC, or other regulatory body limitations. Includes damage caused by weather

including but not limited to lightning, flood, earthquake, etc. This may also include limitations to hydro

due to low dissolved oxygen in tailwater or to control downstream flooding.

Unknown The default Forced Outage/Derate reason will be pre-populated with Unknown at the time of

submittal. Either during the initial outage submittal or at a later time, the Unknown reason must be

changed to reflect the actual experienced issue.

Routine Generator

Maintenance

Removal from service or limitation in order to perform repair or inspection of generation equipment.

Supporting Transmission

Outage

Removal from service or limitation in order to support a scheduled transmission outage.

Excess Capacity/Economic Removal from service or limitation due to seasonal or system capacity need. This includes peaker units

not expected to be used during winter months.

Upcoming Model Change Outages created for the purpose of correcting system topology related to pending model changes. This

cause should only be used by SPP operations personnel.

7.3. Outage Review / Approval Process

All outages submitted will be studied to determine if any potential reliability conflicts are found. The

general study method employed by SPP staff involves building representative models of the study time

period and implementing all outage requests submitted for that time period. The resulting modeled

system is then studied to determine if any reliability issues can be identified. If issues are identified,

various mitigation steps are then studied including but not limited to, generation redispatch, system

reconfiguration, rescheduling of lower priority outages, and facility rating reviews. If mitigations are

unsuccessful in resolving the conflict, an outage request may need to be rescheduled or denied. Priority of

outage requests is reviewed based upon initial submission time, outage priority category, reason for the

outage, and impact to reliability. To the extent possible, higher priority category requests will be given

preference, but ultimately it is up to the SPP RC to resolve any scheduling conflicts.

In the event that a conflict occurs with another Reliability Coordinator’s outage, a priority of the outages

will be determined based on submitted time, reason for outage, and impact to reliability. The

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determination will be reviewed and agreed upon by each Reliability Coordinator. The outage that is

deemed a higher priority will be approved.

An outage that has been studied will receive a status change to one of the following statuses: Approved,

Denied, or Pre-Approved. Pre-Approval will be provided in certain cases where an outage has been

submitted, but for various reasons SPP is unable to adequately study the outage or determine that no

reliability conflicts exist. The Pre-Approval may also be dependent upon a specific operating condition that

may need to be met but cannot be guaranteed at the time the Pre-Approval is issued such as but not

limited to a load forecast threshold, simultaneous outage, new facilities in-service, etc. When the outage

request can be adequately studied to determine that no reliability conflict exists, the status will be

changed to Approved.

All outages submitted within the appropriate advance timeframe will be reviewed as soon as possible by

SPP Operations sStaff. The review timelines for SPP are as follows:

a. Transmission

1. For all BES outage requests submitted 30 days or more prior to scheduled start time,

Pre-Aapproval or Ddenial will be provided within 5 business days.

2. For all BES outage requests submitted 14 days or more but less than 30 days prior to the

scheduled start time, Ppre-Aapproval or Ddenial will be provided within 3 business days.

3. For all BES outage requests submitted 14 days or less prior to scheduled start time,

Ppre-Aapproval or Ddenial will be provided within 2 business days.

b. Generators

1. For all Generator Ooutage Rrequests submitted 30 days or more prior to scheduled start

time, Pre-Aapproval or Ddenial will be provided within 5 business days.

2. For all Generator Ooutage Rrequests submitted 14 days or more but less than 30 days

prior to the scheduled start time, Approval, Pre-Aapproval or Ddenial will be provided

within 3 business days.

3. For all Generator outage requests submitted 14 days or less prior to scheduled start

time, Approval, Pre-Aapproval or Ddenial will be provided within 2 business days.

4. SPP will provide their best effort for Ooutages Ssubmitted within 2 business days.

8.4. Outage Status Changes

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All outages submitted will reside in one of several status types throughout the life cycle of the outage.

These status types and their associated definition are: Status Definition

Proposed The outage request has been saved in the CROW tool and remains under the full revision control until the outage is

entered into a Submitted state by the requestor. If the requestor does not move a proposed request to the

submitted status within 30 days of the planned start date, the outage is automatically Withdrawn. Proposed

outage request status dates DO NOT qualify for outage queuing in conflict resolution. Proposed outage requests

are not provided to external systems such as NERC SDX/IDC or SPP’s EMS.

Submitted The outage request has been submitted into the CROW tool and is ready for review by SPP. The outage requestor

does not possess revision control of the outage in this status. A revision request may be submitted to SPP regarding

an outage in Submitted status. Outage requests in this state are provided to external systems such as NERC


Study SPP will change the status type to Study once the active study process begins. Outage requests in this state are


Preliminary

Approved

Outage requests with Preliminary Approved status have been approved based on long lead studies and may need

additional analysis closer to the planned start date or finalization of an Operating Guide. Once the restudy is

complete or final opguide posted, the outage status is changed to Approved. Outage requests in this state are


Approved Approved state indicates SPP has completed the study process and the outage request is ready for implementation.

Outage requests in this state are provided to external systems such as NERC SDX/IDC or SPP’s EMS.

Implemented Once the outage request actual start time has been entered, signifying that the outage has begun, the outage

status is changed to Implemented. Outage requests in this state are provided to external systems such as NERC


Completed Once the outage request actual end time has been entered, signifying that the outage has ended, the outage status

is changed to Completed. Outage requests in this state are NO LONGER provided to external systems such as NERC


Certain outage requests may result in a need by the outage requestor to withdraw or cancel the outage

request. SPP’s study results and coordination may also result in status changes to an outage reflecting the

inability of the Ooutage Rrequest to be Aapproved or Iimplemented. These status types are:

Status Definition

Withdrawn The outage requestor can withdraw an outage request while it is still in Proposed status. Once in Study or Approved

status, the request must be Cancelled. Outage requests in this state are NOT provided to external systems such as

NERC SDX/IDC or SPP’s EMS.

Cancelled The outage requestor can cancel a Submitted or Approved outage. Cancelled outages can be reinstated by the

requestor, provided the planned start of the outage falls within the business rules for lead time submission. Outage


Denied An outage request that is in Submitted or Study status can be Denied. If SPP denies the request, the status changes

to Denied. This state indicates the outage request was not approved for implementation. Outage requests in this

state are NOT provided to external systems such as NERC SDX/IDC or SPP’s EMS.

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Revoked Once an outage request has been Approved, it can be Revoked at an time (ie, before or during the outage). Outage


9.5. Using CROW to Submit Other Types of Information to SPP

The CROW tool can be used as a mechanism to submit information to SPP other than outage and or status

information on lines, transformers, and generators. All other types of information exchange made using

the CROW tool not previously described in this Appendix 12 OP-2SPP RC Outage Coordination

Methodology will follow the guidelines below.

For Reactor, Capacitor, Circuit Breaker, Disconnect, and Protection Scheme (Special Protection System)

Equipment Types,

1. All CROW tool submissions for these equipment types will be made in accordance with SPP RC Outage

Coordination Methodology Appendix 12 OP-2 Sections 1d, 1e, and 1f

2. SPP RC Outage Coordination Methodology Appendix 12 OP-2 Section 3 Outage Review / Approval Process

will not apply to these equipment types

3. These equipment types will not progress through the various states described in SPP RC Outage

Coordination MethodologyAppendix 12 OP-2 Section 4 Outage Status Changes

For Generator Automatic Voltage Regulator (AVR) and Power System Stabilizers Equipment Types

1. All CROW tool submissions for this equipment type will be made in accordance with SPP RC Outage

Coordination MethodologyAppendix 12 OP-2 Sections 2c, 2d, and 2e

2. SPP RC Outage Coordination Methodology Appendix 12 OP-2 Section 3 Outage Review / Approval Process

will not apply to these equipment types

3. These equipment types will not progress through the various statuses described in SPP RC Outage

Coordination MethodologyAppendix 12 OP-2 Section 4 Outage Status Changes

Modeling Knowledge SessionFuture Effective Load Ownership

February 6th, 2018

2

Goals• Discuss modeling practice update

• Identify different types of load changes

• Walk through scenarios

• Review timeline and required documentation for load transfers

3

4

Reason for Practice Awareness• Congestion Hedging process for the

current month uses previous month’s model

• Loads with an effective date after TCR model build will not be included in the Congestion Hedging process

• Load transfers involve coordination between multiple entities Asset Owning MPs only

Load Changes• New Load Does not exist in Network or Commercial

Model

• Load Transfer Full Transfer Entire delivery point changes ownership to

new MP/AO No Network Model changes needed

Partial Transfer Part of delivery point changes ownership to

new MP/AO Requires Network Model change

5

New Load• Existing MP Make load effective in Network/Commercial

Model one month ahead of commercial start date Not same as future effective

MP will submit 0MW meter data until load comes online

MP may need existing transmission service at effective date Potential for unreserved use

• Not available for New/Future Effective MPs MP does not exist ahead of commercial start date

6

Future Effective Ownership Change• New Owner submits change information at least 75

days prior to requested effective date

• Only for load transfers

• Only allowed one month in advance

• Allows for: Full delivery point transfers Partial delivery point transfers (requires EMS modeling

one month in advance) Transfers to new MP/AO

• Does not allow: Loads changing Settlement Area

7

Questions?What questions do you have before we move on to some examples?

8

Full Transfer Example• One delivery point

• Currently served by MP DREW

• Moving to MP CHRIS

• Commercial Model Changes only

Future Effective 5/1/2018 pushed with 4/1/2018 Model

9

4/1/2018 MAS

Partial Transfer Example• Partial Transfer of Load Two delivery points, one new Currently served by MP DREW Moving to MP CHRIS Network Model changes

Network has to model a new delivery point (breakout) one month in advance

Commercial Model changes Ties new PNode/ENode breakout to original Settlement

Location Incremental project ties new PNode/ENode to new

Settlement Location (future effective ownership change)

• Example on next slide

10

11

3/1/2018 MAS (pre breakout)

4/1/2018 MAS (breakout under existing MP)

Future Effective 5/1/2018 pushed with 4/1/2018 Model

Documentation• MCST Project

Corresponding projects from both parties involved in transfer Both parties must have corresponding weight factors Zero change items submitted in project by MP if only bus level transfer

• MCST User Guide Appendix B** Transferor

Settlement Location Meter Data Submittal Location PNode name Weight factor that is transferring New weight factor (If partial transfer)

Transferee Settlement Location Meter Data Submittal Location Weight factor Transfer Letter One-line diagram (showing point of interconnect)

12** Minimum data needed. Assumes Settlement Location already exists.

Timeline ExampleAccurate Documentation and MCST project must be submitted and approved by the submission deadline

13

Effective Date

Submission Deadline

1-Jan 15-Oct

1-Feb 15-Nov

1-Mar 15-Dec

1-Apr 15-Jan

1-May 15-Feb

1-Jun 15-Mar

1-Jul 15-Apr

1-Aug 15-May

1-Sep 15-Jun

1-Oct 15-Jul

1-Nov 15-Aug

1-Dec 15-Sep

Protocol Language• Section 6.6 “The dates provided for the TCR Update Duration

are for Day-Ahead data updates. Due to the Commercial Model update being monthly and the TCR updates being monthly, the model update requests and related information for updates to be included in the monthly TCR Auction (optional) must be provided at least 75 days prior to the requested effective date of the pertinent monthly TCR Auction in production. “

14

Questions?What questions do you have on the required documentation or the project deadlines?

15

of 2


RR #: 252 Date: 1/26/18

RR Title: OOME Enhancement


Estimated Duration: 6 Months ROM based on information available at the time of the estimate

Primary Working Group Score/Priority: Medium

SUMMARY OF SYSTEM IMPACTS This RR will impact the following systems: Markets, and Market Settlements. The changes needed will be reflected in changes to User Interface (UI), database schemas and system logic. There will be modifications to current charge types required for this RR. Training materials will need to be created once the system design changes are complete.

IMPACTED SYSTEMS

Member Impacting

(Y/N)

List all impacted systems. Provide a brief explanation of the expected impact to each.

1. Y

2. Y

3. Y

1. Training

2. Markets

3. Markets Settlements

1. Course material and Job Aid edits

2. UI, System and Database changes

3. System and Database changes


N/A


N/A


N/A


of 2

A need has been identified for SPP to have the option to assign an Out-of-Merit Energy (OOME) cap and/or floor, in addition to the current ability to assign a fixed dispatch MW. This change will allow Resources operating under an OOME cap and/or floor to be economically dispatched up to and including the OOME limits. Under the current method of assigning a fixed OOME MW, Resources are not able to be dispatched economically by SCED (even when being dispatched would help the situation for which an OOME has been issued). If SPP needs a positively impacting Resource to remain above a certain output, SPP currently must assign a fixed OOME MW value to keep the Resource at a specific level. This RR would allow SPP to manually set a floor for the dispatch and allow SCED to dispatch the Resource up and/or down to this OOME floor. The same would apply to a Resource negatively affecting a flowgate. SPP needs the Resource to remain below a certain value. This RR would allow SPP to manually set a cap for the dispatch and allow SCED to economically dispatch the Resource down and/or up to the OOME cap. Language is added to 4.4.2.5 to define SPP’s ability to place an OOME maximum and/or minimum MW on a Resource during an OOME event. Language is also added to 4.5.9.9 to include the OOME cap and floor in the MWP considerations for Resources that are issued an OOME.

Benefits that will be realized from this revision:

This change will allow Resources operating under an OOME cap and/or floor to be economically dispatched up to and including the newly defined OOME limits.

SPP COMMENTS

SPP recommends a ranking of Medium

Revision Request Recommendation Report

RR #: 252 Date: 11/14/2017

RR Title: OOME Enhancement


Submitter Name: Ryan Kirk Company: AEP


EXECUTIVE SUMMARY AND RECOMMENDATION FOR MOPC AND BOD ACTION



A need has been identified for SPP to have the option to assign an Out-of-Merit Energy (OOME) cap and/or floor, in addition to the current ability to assign a fixed dispatch MW. This change will allow Resources operating under an OOME cap and/or floor to be economically dispatched up to and including the OOME limits. Under the current method of assigning a fixed OOME MW, Resources are not able to be dispatched economically by SCED (even when being dispatched would help the situation for which an OOME has been issued). If SPP needs a positively impacting Resource to remain above a certain output, SPP currently must assign a fixed OOME MW value to keep the Resource at a specific level. This RR would allow SPP to manually set a floor for the dispatch and allow SCED to dispatch the Resource up and/or down to this OOME floor. The same would apply to a Resource negatively affecting a flowgate. SPP needs the Resource to remain below a certain value. This RR would allow SPP to manually set a cap for the dispatch and allow SCED to economically dispatch the Resource down and/or up to the OOME cap. Language is added to 4.4.2.5 to define SPP’s ability to place an OOME maximum and/or minimum MW on a Resource during an OOME event. Language is also added to 4.5.9.9 to include the OOME cap and floor in the MWP considerations for Resources that are issued an OOME.


This change will allow Resources operating under an OOME cap and/or floor to be economically dispatched up to and including the newly defined OOME limits.

SPP STAFF ASSESSMENT

IMPACT

Will the revision result in system changes No Yes

Summarize changes:

Will the revision result in process changes? No Yes

Summarize changes:

Is an Impact Assessment required? No Yes

If no, explain:

Estimated Cost: $ Estimated Duration: months

Primary Working Group Score/Priority:

SPP DOCUMENTS IMPACTED

Market Protocols Protocol Section(s): 4.4.2.5, 4.4.2.5.1 (new), 4.4.2.5.2 (new), 4.4.2.5.3 (new), 4.5.9.9

Protocol Version: 50a

Operating Criteria Criteria Section(s): Criteria Date: Planning Criteria Criteria Section(s): Criteria Date: Tariff Tariff Section(s): Attachment AE – 6.2.4 Business Practice Business Practice Number: Integrated Planning Model (ITP Manual) Section(s): Revision Request Process Section(s): Minimum Transmission Design



SPP Communications Protocols Section(s): WORKING GROUP REVIEWS AND RECOMMENDATIONS

List Primary and any Secondary/Impacted WG Recommendations as appropriate

Primary Working Group: MWG

Date: 11/14/2017

Action Taken: Approved

Abstained: WR

Date: 1/8/2018

Action Taken: Approved SPP Comments as modified by the MWG

Secondary Working Group: ORWG

Date: 3/1/2018

Action Taken:

Abstained:

Opposed:


Secondary Working Group: RTWG

Date: 3/8/2018

Action Taken:

Abstained:

Opposed:


Secondary Working Group: RCWG

Date: 3/12/2018

Action Taken:

Abstained:

Opposed:


MOPC

Date: 4/10/2018

Action Taken:

Abstained:

Opposed:


BOD/Member Committee

Date: 4/24/2018

Action Taken:

Abstained:

Opposed:


COMMENTS

Comment Author: MWG


Description of Comments: MWG approved RR252 with modifications to Protocols and Tariff that clarified that the OOME may specify either the fixed MW level or an OOME cap and/or floor.

Status: Approved and incorporated language.

COMMENTS

Comment Author: Ron Gunderson on behalf of NPPD


Description of Comments: Proposed additional clarifying changes to section 4.4.2.5 that did not change the intent of the RR.

Status: Reviewed and not incorporated by the MWG on 1/8/2018

COMMENTS

Comment Author: John Luallen on behalf of SPP


Description of Comments: SPP staff added necessary settlement changes in Section 4.5.9.9 (Real-Time Out-of-Merit Amount), to reflect the proposed OOME cap and/or OOME floor. Staff also added enhanced clarity in Section 4.5.9 (Real-Time Settlements Amount) located in the Protocols and Section 8.6.6 (Real-Time Out-of-Merit Amount) located in Attachment AE of the SPP Tariff. Staff also addressed NPPD’s concerns with the language in 4.4.2.5.1(1)(c)(i) that describes how the current systems work today.

Status: Approved and incorporated by the MWG on 1/8/2018

COMMENTS

Comment Author: MWG


Description of Comments:

The MWG made modifications to the SPP comments submitted on 1/4/2018 during the January 8-9, 2018 meeting.

The MWG modified Section 4.4.2.5.2 of the Protocols to add clarification to the language specific to Dispatch Instruction notification, and Emergency Minimum and Maximum limits. The adjustment in AE Section 6.2.4, aligns the Tariff with the Protocols related to when a local transmission operator issues an OOME.

Status: Approved and incorporated by the MWG on 1/8/2018

PROPOSED REVISION(S) TO SPP DOCUMENTS

Market Protocols

4.4.2.5 Out-of-Merit Energy (OOME) Dispatch

SPP may issue an OOME to any Resource not on outage. An OOME will specify either the a fixed MW level or an OOME cap and/or OOME floor MW level the Resource is expected to produce until such time as the issue can be resolved. When an OOME contains a fixed OOME MW, the Resource is instructed to generate equal to the specified fixed OOME MW. When an OOME contains an OOME cap MW and/or OOME floor MW, the resource is instructed to generate below the OOME cap MW and/or above the OOME floor MW respectively. Such MW levels may include (i) dispatch below a Resource’s Minimum Economic Capacity Operating Limit down to Minimum Normal Capacity Operating Limit or Minimum Emergency Capacity Operating Limit as system conditions warrant or (ii) dispatch above a Resource’s Maximum Economic Capacity Operating Limit up to Maximum Normal Capacity Operating Limit or Maximum Emergency

Capacity Operating Limit as system conditions warrant. During the period of time an OOME is imposed, the Resource will not be eligible to clear Operating Reserves. SPP will make every effort to define and activate the appropriate constraint(s). A Qualifying Facility exercising its rights under PURPA to deliver its net output to its host utility may be issued OOMEs only during an Emergency Condition or a reliability issue equivalent to a TLR 5 or greater. A local transmission operator may 1) request the Transmission Provider to issue an OOME, or 2) issue an OOME directly to the Resource(s). If the local transmission operator determines there is an adequate amount of time prior to issuing the OOME directly to the Resource, the transmission operator will coordinate with SPP to ensure the OOME is provided by SPP. If the initial OOME is issued by the local transmission operator, the local transmission operator shall coordinate with SPP to ensure subsequent OOMEs are provided by SPP. An OOME issued directly by the local transmission operator may also specify either a fixed MW level or an OOME cap and/or OOME floor MW level.

4.4.2.5.1 Fixed OOME

(1) During the period of time when a fixedan OOME is imposed, SPP will ensure that the following occurs:

(a) A notification is immediately issued containing a Dispatch Instruction equal to the fixed MW level the Resource is instructed to produce and the OOME flag is set equal to “True”;

(b) Setpoint Instructions and Economic/Emergency Minimum and Economic/Emergency Maximum Limits for the current Dispatch Interval are immediately adjusted to the fixed MW level the Resource is instructed to produce;

(i) For VERs, the Economic/Emergency Minimum and Economic/Emergency Maximum Limits for the current Dispatch Interval are immediately adjusted to the fixed MW level the Resource is instructed to produce and the Setpoint Instructions will be immediately adjusted to the lesser of the fixed MW level the Resource is instructed to produce or the echo of the actual SCADA;

(c) Setpoint Instructions for future intervals and Economic/Emergency Minimum and Economic/Emergency Maximum limits not yet dispatched will be set to the fixed MW level the resource is instructed to produce;

(i) For VERs, the Economic/Emergency Minimum and Economic/Emergency Maximum limits not yet dispatched will be set to the MW level the Resource is instructed to produce and the Setpoint Instructions will be set to the lesser

of the fixed MW level the Resource is instructed to produce or the echo of actual SCADA output; and

(d) SPP systematically notifies the Market Participant when the OOME has ended.;

4.4.2.5.2 OOME Cap and OOME Floor

(1) During the period of time when an OOME contains an OOME cap and/or OOME floor, SPP will ensure that the following occurs:

(a) A notification is immediately issued containing a Dispatch Instruction as defined in (i) to (iii) below and the OOME flag is set equal to “True”; (i) If the current Dispatch Instruction is greater than the OOME cap MW, the

Dispatch Instruction will be adjusted to the OOME cap MW; (ii) If the current Dispatch Instruction is less than the OOME floor MW, the

Dispatch Instruction will be adjusted to the OOME floor MW; (iii) If the current Dispatch Instruction is less than or equal to the OOME cap

MW and/or greater than or equal to the OOME floor MW, the Dispatch Instruction will not be adjusted;

(b) Setpoint Instructions for the current Dispatch Interval are immediately adjusted; (i) If the current Setpoint Instruction is greater than the OOME cap MW, the

Setpoint Instruction will be adjusted to the OOME cap MW; (ii) If the current Setpoint Instruction is less than the OOME floor MW, the

Setpoint Instruction will be adjusted to the OOME floor MW; (iii) If the current Setpoint Instruction is less than or equal to the OOME cap

MW and/or greater than or equal to the OOME floor MW, the Setpoint Instructions will not be adjusted;

(c) Economic/Emergency Minimum Limits for the current Dispatch Interval are immediately adjusted to the OOME floor MW. Economic/Emergency Maximum Limits for the current Dispatch Interval are immediately adjusted to the OOME cap MW;

(a)(d) For future intervals not yet dispatched the Economic/Emergency Maximum Limits will be set equal to the OOME cap MW. For future intervals not yet dispatched the Economic/Emergency Minimum Limits will be set equal to the OOME floor MW;

(e) The resource will be dispatchable in RTBM SCED; and (f) SPP systematically notifies the Market Participant when the OOME has ended;

(2) To the extent that the OOME was initiated directly by a local transmission operator, Market Participants shall be compensated for the period of time the OOME was imposed in accordance with Section 4.5.9.9 as if they had been issued an OOME by SPP; except that if the Market Monitor determines that the Resource selected pursuant to Section 4.4.2.5 was selected by the local transmission operator in a discriminatory manner and the Resource was affiliated with the local transmission operator, such Resource shall not be eligible for compensation under Section 4.5.9.9. Such determination shall be made using the same standards and procedures prescribed for Resource selection in the Intra-Day Reliability Unit Commitment process, as set forth in Section 6.1.2.1 of Attachment AE to the Tariff. Recovery of any compensation shall be collected locally as described under Section 4.5.9.9.

(3) To the extent that the OOME was initiated by SPP at the request of a local transmission operator, such Resources issued OOMEs shall be selected by SPP in a non-discriminatory manner, which will be verified by the Market Monitor through the process described under Section 6.1.2.1 of Attachment AE to the Tariff. In such event, Market Participants shall be compensated for the period of time the OOME was imposed in accordance with Section 4.5.9.9. The recovery of the compensation paid by SPP shall be collected by SPP locally as described under Section 4.5.9.9.

(4) To the extent that the OOME was initiated by SPP, such Resources issued OOMEs shall be selected by SPP in a non-discriminatory manner, which will be verified by the Market Monitor through the process described under Section 6.1.2.1 of Attachment AE to the Tariff. Recovery of compensation for Resources directly issued OOMEs by SPP that are received under Section 4.5.9.9 shall be collected regionally under Section 4.5.12.

(5) SPP, the local transmission operator, and affected Resource owners shall develop operating guides to be applied to OOMEs made to relieve known and recurring reliability issues or to relieve known and recurring Emergency Conditions. Such Resources will be compensated in the same manner as any other Resource that is issued an OOME. The recovery of the compensation paid by SPP under Section 4.5.9.9 shall be collected by SPP locally as described under Section 4.5.9.9.

4.4.2.5.1 3 Out-of-Merit Energy During Emergency Conditions

If the OOME is issued to resolve an Emergency Condition, SPP will do the following in addition to the items listed in 4.4.2.5(1):

1) Declare the Emergency Condition as soon as possible by posting it on the SPP OASIS;

2) Communicate the OOME via a phone call; and

3) Displace the OOME with a market solution as soon as possible, consistent with system safety and reliability.

4.5.9 Real-Time Balancing Market Settlement

…

(9) In addition, Resources may receive a Make Whole Payment related to an OOME as described under Section 4.5.9.9, subject to certain eligibility requirements, as follows:

(a) If the Resource is issued an fixed MW level or an OOME cap and/or OOME floor by SPP in any hour that creates Out-of-Merit Energy (OOME) MW in excess of the Resource’s Dispatch Instruction and the Resource Offer costs associated with the OOME MW are greater than the Energy revenue received for the OOME MW, the Resource will receive the difference between the Energy Offer Curve costs associated with the OOME MW and the OOME MW Energy revenue. The OOME MW is calculated as Max (0, or the difference between (i) the (lesser of actual Resource output or the Resource’s floor or fixed OOME MW) and (ii) the Resource’s Desired Dispatch);

(b) If the OOME is for Energy in the down direction and the RTBM LMP is greater than the DA Market LMP, the Asset Owner will receive a credit for the difference multiplied by the OOME MW cap or fixed. The OOME MW is calculated as Max (0, the difference between (i) the Resource’s DA Market cleared Energy MW and (ii) the (greater of actual Resource output or the Resource’s OOME cap or fixed MW)); and

(c) If during the period of time when an OOME is imposed, the RTBM cleared amount of an Operating Reserve product is less than the DA Market cleared amount of the corresponding Operating Reserve product and the RTBM MCP is greater than the DA Market MCP, the Asset Owner will receive a credit for the difference multiplied by the OOMOR MW. The OOMOR MW is calculated as Max (0, the difference between the Resource’s DA Market cleared Operating Reserve MW and the Resource’s RTBM cleared Operating Reserve MW).

Make Whole Payments associated with OOME are collected as part of revenue neutrality uplift as described under Section 4.5.12.

4.5.9.9 Real-Time Out-Of-Merit Amount

(1) An RTBM credit or charge1 will be made to each Market Participant with a Resource that passes a primary Contingency Reserve deployment test as described under Section 6.1.11.1(3)(b)(i) and/or otherwise receives an OOME from SPP or a local transmission operator that creates a cost to the Asset Owner or that adversely impacts the Asset Owner’s DA Market position and/or if a Market Participant must buy back its DA Market position for any Operating Reserve product at a RTBM MCP that is greater than that product’s DA Market MCP. Resources issued OOMEs by or at the request of a local transmission operator in order to solve a Local Emergency Condition or a Local Reliability Issue are eligible for out-of-merit credits as defined in this Section unless selection of the Resource by the local transmission operator was performed in a discriminatory manner as determined by the MMU and the Resource was an affiliated Resource; however, a manual process is employed for the calculation of the out-of-merit credits and they will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The cost allocation of out-of-merit credits associated with OOMEs issued by or at the request of a local transmission operator will be determined hourly by multiplying an Asset Owner’s RTBM actual load in the impacted Settlement Area by a rate determined by dividing the daily sum of all out-of-merit credits applicable to the impacted Settlement Area by the daily sum of all Asset Owners’ RTBM actual load in the impacted Settlement Area. A manual process is also employed for these calculations and the charges will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. Out-of-merit credits associated with OOMEs issued directly by SPP to address a reliability issue other than a Local Reliability Issue will be recovered under Section 4.5.12. The amount will be calculated on a Dispatch Interval basis under the following conditions:

(a) If the OOME is for Energy in the up direction and the Energy Offer Curve cost associated with the Out-of-Merit Energy (OOME) floor or fixed MW is greater than the RTBM LMP, the Asset Owner will receive a credit equal to the difference multiplied by the OOME floor or fixed MW. The OOME MW is calculated as Max (0, or the difference between (i) (lesser of the absolute value of the actual Resource output or the Resource’s OOME floor or fixed MW) and (ii) the Resource’s Desired Dispatch);


(b) If the OOME is for Energy in the down direction, including a Resource de-commitment or movement of a DA Market committed MCR to a configuration with a lower applicable maximum capacity operating limit and the RTBM LMP is greater than the DA Market LMP, the Asset Owner will receive a credit for the difference multiplied by the OOME MW cap or fixed. The OOME MW is calculated as Max (0, or the difference between (i) the absolute value of the Resource’s DA Market cleared Energy MW and (ii) the (greater of the absolute value of the actual Resource output or the Resource’s OOME cap or fixed MW)); and/or

(c) If an OOME for Energy or Operating Reserve, or a Resource de-commitment instruction or movement of a DA Market committed MCR to a configuration with a lower applicable maximum capacity operating limit, causes the RTBM cleared amount of an Operating Reserve product to be less than the DA Market cleared amount of the corresponding Operating Reserve product and the RTBM MCP is greater than the DA Market MCP, the Asset Owner will receive a credit for the difference multiplied by the Out-Of-Merit-Operating Reserve (OOMOR) MW. The OOMOR MW is calculated as Max (0, or the difference between the Resource’s DA Market cleared Operating Reserve MW and the Resource’s RTBM cleared Operating Reserve MW).

To the extent that additional costs are incurred as a direct result of an OOME through the compensation mechanisms described above, Market Participants may request additional compensation through submittal of actual cost documentation to SPP. SPP will review the submitted documentation and confirm that the submitted information is sufficient to document actual costs and that all or a portion of the actual costs are eligible for recovery.

The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for each Dispatch Interval is calculated as follows:

IF RtOom5minFlg a, s, i = 1 OR ResDeCommit5minFlg a, s, i = 1 OR RtReprice5minFlg a, s, i = 1 OR ConfigDeCommit5minFlg a, s, i, t = 1

THEN

#RtOom5minAmt a, s, i = ( RtOomeIncr5minAmt a, s, i + RtOomeDecr5minAmt a, s, i

+ RtOomor5minAmt a, s, i ) * (-1)

ELSE IF RtDeSelectOr5minFlg a, s, i = 1

THEN

#RtOom5minAmt a, s, i = RtOomor5minAmt a, s, i * (-1)

ELSE

#RtOom5minAmt a, s, i = 0

Where,

(a) RtOomeIncr5minAmt a, s, i =

Max ( 0, Max ( 0, RtOomeIncrEn5minAmt a, s, i – RtOomeDesiredEn5minAmt a, s, i ) -

Max (0, Min (Min (0, RtBillMtr5minQty a, s, i ) * (-1),

Min (RtOomeFloor5minQty a, s, i , RtAvgSetpoint5minQty a, s, i ) ) - RtOomeDesiredEn5minQty a, s, i )

* Max( 0, RtLmp5minPrc s, i ) ) / 12

(a.1) #RtOomeIncrEn5minAmt a, s, i =

∫y

x

CurveOffer Energy Dispatched As RTBM

Where:

X = 0

Y = Min ( Min ( 0, RtBillMtr5minQty a, s, i ) * (-1),

Min (RtOomeFloor5minQty a, s, i , RtAvgSetpoint5minQty a, s, i ) )

(a.2) #RtOomeDesiredEn5minAmt a, s, i =

∫y

x

CurveOffer Energy Dispatched As RTBM

Where:

X = 0

Y = RtOomeDesiredEn5minQtya, s, i

(b) RtOomeDecr5minAmt a, s, i =

Max (0, (-1) * Max (Min ( 0, RtBillMtr5minQty a, s, i ) * (-1),

Max (RtAvgSetpoint5minQty a, s, i, RtOomeCap5minQty a, s, i ) ) - DaClrdHrlyQty a, s, h )

* Max ( 0, RtLmp5minPrc s, i - DaLmpHrlyPrc s, h ) / 12

(c) IF RtOom5minFlg a, s, i = 1 OR ResDeCommit5minFlg a, s, i = 1 OR RtReprice5minFlg a, s, i = 1 OR ConfigDeCommit5minFlg a, s, i, t = 1

THEN

RtOomor5minAmt a, s, i =

∑z

[ ( Max (0, ∑z

DaRegUpHrlyQty a, z, s, h - RtRegUp5minQty a, z, s, i )

* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h ) )

+ ( Max (0, ∑z

DaRegDnHrlyQty a, z, s, h - RtRegDn5minQty a, z, s, i )

* Max ( 0, RtRegDnMcp5minPrc z, i - DaRegDnMcpHrlyPrc z, h ) )

+ ( Max (0, ∑z

DaSpinHrlyQty a, z, s, h - RtSpin5minQty a, z, s, i )

* Max ( 0, RtSpinMcp5minPrc z, i - DaSpinMcpHrlyPrc z, h ) )

+ ( Max (0, ∑z

DaSuppHrlyQty a, z, s, h - RtSupp5minQty a, z, s, i )

* Max ( 0, RtSuppMcp5minPrc z, i - DaSuppMcpHrlyPrc z, h ) ) ] / 12

ELSE IF RtDeSelectOr5minFlg a, s, i = 1

THEN

RtOomor5minAmt a, s, i =

∑z

[ (( Max (0, ∑z

DaRegUpHrlyQty a, z, s, h - RtRegUp5minQty a, z, s, i )

* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h ) )

* RtDeSelectRegUp5minFlg a, s, i )

+ (( Max (0, ∑z

DaRegDnHrlyQty a, z, s, h - RtRegDn5minQty a, z, s, i )

* Max ( 0, RtRegDnMcp5minPrc z, i - DaRegDnMcpHrlyPrc z, h ) )

* RtDeSelectRegDn5minFlg a, s, i )

+ (( Max (0, ∑z

DaSpinHrlyQty a, z, s, h - RtSpin5minQty a, z, s, i )

* Max ( 0, RtSpinMcp5minPrc z, i - DaSpinMcpHrlyPrc z, h ) )

* RtDeSelectSpin5minFlg a, s, i )

+ (( Max (0, ∑z

DaSuppHrlyQty a, z, s, h - RtSupp5minQty a, z, s, i )

* Max ( 0, RtSuppMcp5minPrc z, i - DaSuppMcpHrlyPrc z, h ) )

* RtDeSelectSupp5minFlg a, s, i )] / 12

(2) For each Asset Owner, an hourly amount is calculated at each Settlement Location. The hourly amount is calculated as follows:

RtOomHrlyAmt a, s, h = ∑i

RtOom5minAmt a, s, i

(3) For each Asset Owner, a daily amount is calculated at each Settlement Location. The daily credit amount is calculated as follows:

RtOomDlyAmt a, s, d = ∑h

RtOomHrlyAmt a, s, h


RtOomAoAmt a, m, d = ∑s

RtOomDlyAmt a, s, d


RtOomMpAmt m, d = ∑a

RtOomAoAmt a, m, d

(6) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates Real-Time Out-of-Merit Energy and Operating Reserve $ per Dispatch Interval for each Asset Owner as follows:

(a) #EqrRtOom5minPrc a, s, i = (-1) * RtOom5minAmt a, s, i

(b) IF #EqrRtOom5minPrc a, s, i > 0

THEN #EqrRtOom5minQty a, s, i = 1

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The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

RtOom5minAmt a, s, i $ Dispatch Interval

Real-Time Out-Of-Merit Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval - The amount to AO a for eligible Resource Settlement Location s in Dispatch Interval i for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

RtOomeIncr5minAmt a, s, i $ Dispatch Interval

Real-Time Out-Of-Merit Incremental Energy Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval - The portion of AO a’s RtOome5minAmt a, s, i amount for eligible Resource Settlement Location s in Dispatch Interval i for Out-of-Merit Energy resulting from an OOME in the up direction.

RtOomeDecr5minAmt a, s, i $ Dispatch Interval

Real-Time Out-Of-Merit Decremental Energy Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval - The portion of AO a’s RtOome5minAmt a, s, i amount for eligible Resource Settlement Location s in Dispatch Interval i for Out-of-Merit Energy resulting from an OOME in the down direction.

ResDeCommit5minFlg a, s, i None Dispatch Interval

Resource De-Commitment Flag per AO per Dispatch Interval per Settlement Location – The value as described under Section 4.5.9.10.

ConfigDeCommit5minFlg a, s, i, c, t None Dispatch Interval

MCR Configuration De-Commitment Flag per AO per Dispatch Interval per Settlement Location per RUC Make-Whole Payment Eligibility Period per Transition Event – The flag set to 1 by SPP indicating that AO a’s MCR configuration has been de-committed by SPP to a configuration with a lower applicable maximum capacity operating limit than the configuration committed in the DA Market, at MCR Settlement Location s in Dispatch Interval i per transition event t.

RtOom5minFlg a, s, i None Dispatch Interval

Real-Time Out-of-Merit Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 when an OOME is issued, otherwise, this flag is set equal to zero.

RtReprice5minFlg a, s, i None Dispatch Interval

Real-Time Repricing Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever there is a price correction event as described under Section 6.6.1, otherwise, this flag is set equal to zero.

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Variable

Unit

Settlement Interval

Definition

RtDeSelectOr5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Operating Reverse Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever an OOME is issued to deselect a Resource for Operating Reserve that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

RtOomor5minAmt a, s, i $ Dispatch Interval

Real-Time Out-Of-Merit Operating Reserve Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval - The portion of AO a’s RtOome5minAmt a, s, i attributable to buying back a DA Market Operating Reserve position in the RTBM at a RTBM MCP that is greater than the corresponding DA Market MCP. This should not be a normal occurrence but could happen as a result of price corrections as described under Section 6.6.1.

RtOomeDesiredEn5minQty a, s, i MW Dispatch Interval

Real-Time OOME Desired Dispatch Quantity per AO per Settlement Location per Dispatch Interval – The Desired Dispatch MW for AO a’s eligible Resource for Dispatch Interval i at RtLmp5minPrc s, i as calculated from the Resource’s As Dispatched Energy Offer Curve using the As-Dispatched Minimum Capacity Limit (Economic or Regulating, as applicable) in place prior to the issuance of the OOME as an output floor and the As-Dispatched Maximum Capacity Limit (Economic or Regulating, as applicable) in place prior to the issuance of the OOME as an output ceiling.

RtOomeIncrEn5minAmt a, s, i $ Dispatch Interval

Real-Time OOME Incremental Energy Cost Amount per AO per Settlement Location per Dispatch Interval - The average incremental energy offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as calculated from the Resource’s As Dispatched Energy Offer Curve from 0 MW to the lesser of the OOME MW or RtBillMtr5minQty a, s, i.

RtOomeDesiredEn5minAmt a, s, i $ Dispatch Interval

Real-Time OOME Energy Cost at Desired Dispatch Quantity per AO per Settlement Location per Dispatch Interval - The average incremental energy offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as calculated from the Resource’s As Dispatched Energy Offer Curve from 0 MW to RtOomeDesiredEn5minQty a, s, i.

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Variable

Unit

Settlement Interval

Definition

RtAvgSetPoint5minQty a, s, i MW Dispatch Interval

Real-Time Average Setpoint Instruction MW per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.8 except that when RtOom5minFlg a, s, i is set to 1, RtAvgSetPoint5minQty a, s, i is set equal to the OOME MW.


Real-Time Actual Meter Quantity per AO per Location per Dispatch Interval - The value defined under Section 4.5.9.1 for Dispatch Interval i.

RtOomeFloor5minQty a, s, i MW Dispatch Interval

Real-Time OOME Floor MW per AO per Settlement Location per Dispatch Interval – The MW floor for an out-of-merit dispatch instruction as defined in section 4.4.2.5.2.

RtOomeCap5minQty a, s, i MW Dispatch Interval

Real-Time OOME Cap MW per AO per Settlement Location per Dispatch Interval – The MW cap for an out-of-merit dispatch instruction as defined in section 4.4.2.5.2.

RtLmp5minPrc s, i $/MW Dispatch Interval

Real-Time LMP - The value defined under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i.

DaClrdHrlyQty a, s, h MWh Hour Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.1.

DaRegUpHrlyQty a, z, s, h MW Hour Day-Ahead Operational Regulation-Up Service Quantity per AO per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.4.

DaRegDnHrlyQty a, z, s, h MW Hour Day-Ahead Regulation-Down Service Quantity per AO per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.5.

DaSpinHrlyQty a, z, s, h MW Hour Day-Ahead Spinning Reserve Quantity per AO per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.6.

DaSuppHrlyQty a, z, s, h MW Hour Day-Ahead Supplemental Reserve Quantity per AO per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.7.

RtRegUp5minQty a, z, s, i MW Dispatch Interval

Real-Time Operational Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.4.

RtRegDn5minQty a, z, s, i MW Dispatch Interval

Real-Time Regulation-Down Service Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.5.

RtSpin5minQty a, z, s, i MW Dispatch Interval

Real-Time Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.6.

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Variable

Unit

Settlement Interval

Definition

RtSupp5minQty a, z, s, i MW Dispatch Interval

Real-Time Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.7.

DaRegUpMcpHrlyPrc z, h $/MW Hour Day-Ahead Regulation-Up Service Market Clearing Price per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.4.

RtDeSelectRegUp5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Regulation-Up Service Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever an OOME is sent to deselect a Resource for Regulation-Up Service that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

DaRegDnMcpHrlyPrc z, h $/MW Hour Day-Ahead Regulation-Down Service Market Clearing Price per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.5.

RtDeSelectRegDn5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Regulation-Down Service Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever an OOME is sent to deselect a Resource for Regulation-Down Service that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

DaSpinMcpHrlyPrc z, h $/MW Hour Day-Ahead Spinning Reserve Market Clearing Price per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.6.

RtDeSelectSpin5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Spinning Reserve Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever an OOME is sent to deselect a Resource for Spinning Reserve that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

DaSuppMcpHrlyPrc z, h $/MW Hour Day-Ahead Supplemental Reserve Market Clearing Price per Settlement Location per Hour in the DA Market– The value described under Section 4.5.8.7.

RtDeSelectSupp5minFlg a, s, i None Dispatch Interval

Real-Time Deselect Supplemental Reverse Flag per AO per Settlement Location per Dispatch Interval – A flag that is set equal to 1 whenever an OOME is sent to deselect a Resource for Supplemental Reserve that was cleared in the Day-Ahead Market, otherwise, this flag is set equal to zero.

RtRegUpMcp5minPrc z, i $/MW Dispatch Interval

Real-Time Regulation-Up Service Market Clearing Price per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.4.

RtRegDnMcp5minPrc z, i $/MW Dispatch Interval

Real-Time Regulation-Down Service Market Clearing Price per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.5.

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Variable

Unit

Settlement Interval

Definition

RtSpinMcp5minPrc z, i $/MW Dispatch Interval

Real-Time Spinning Reserve Market Clearing Price per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.6.

RtSuppMcp5minPrc z, i $/MW Dispatch Interval

Real-Time Supplemental Reserve Market Clearing Price per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.7.

RtOomHrlyAmt a, s, h $ Hour Real-Time Out-Of-Merit Make Whole Payment Amount per AO per Settlement Location per Hour - The amount to AO a for eligible Resource Settlement Location s in Hour h for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

RtOomDlyAmt a, s, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount per AO per Settlement Location per Operating Day - The amount to AO a for eligible Resource Settlement Location s in Operating Day d for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

RtOomAoAmt a, m, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount per AO per Operating Day - The amount to AO a associated with Market Participant m in Operating Day d for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

RtOomMpAmt m, d $ Operating Day

Real-Time Out-Of-Merit Make Whole Payment Amount per MP per Operating Day - The amount to MP m in Operating Day d for Out-of-Merit Energy and Operating Reserve resulting from an OOME.

EqrRtOom5minPrc a, s, i $ Dispatch Interval

Real-Time Electric Quarterly Reporting Out-of-Merit Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval - The Out-of-Merit make-whole amount to AO a for Dispatch Interval i at Resource Settlement Location s for use by AO a in reporting such Make Whole Payments to FERC in accordance with FERC EQR requirements.

EqrRtOom5minQty a, s, i MWh Dispatch Interval

Real-Time Electric Quarterly Reporting Out-of-Merit Make Whole Payment Quantity per AO per Settlement Location per Dispatch Interval – This value is set equal to 1 if EqrRtOom5minPrc a, s, i > 0 for use by AO a in reporting such Make Whole Payments to FERC in accordance with FERC EQR requirements..

a none none An Asset Owner. s none none A Settlement Location. i none none A Dispatch Interval. h none none An Hour. d none none An Operating Day. m none none A Market Participant.

of 23

Variable

Unit

Settlement Interval

Definition

t none none A single tagged Interchange Transaction, virtual energy transaction, Bilateral Settlement Schedule, contracted Operating Reserve transaction, TCR instrument, ARR award, Reserve Sharing Event, Start-Up Event or Transition Event identifier.

SPP Tariff (OATT) Attachment AE

6.2.4 Out-of-Merit Energy Dispatch

The Transmission Provider may issue an OOME to any Resource not on outage. The

Transmission Provider will make every effort to define and activate the appropriate constraints in

RTBM SCED within one (1) hour of the time the OOME is issued.

A local transmission operator may 1) request the Transmission Provider to issue an OOME

or 2) issue an OOME directly to the Resource(s) and will notify the Transmission Provider that it

has done so. If the local transmission operator determines there is an adequate amount of time

prior to issuing the OOME directly to the Resource, the local transmission operator will coordinate

with the Transmission Provider to ensure the OOME is provided by the Transmission Provider. If

the initial OOME is issued by the local transmission operator, the local transmission operator shall

coordinate with the Transmission Provider to ensure subsequent OOMEs are provided by the

Transmission Provider.

During the period of time an OOME is imposed, the Transmission Provider will take the

following actions:

(1) The Transmission Provider will issue an OOME at either the fixed MW level or an OOME

cap and/or OOME floor MW level the Resource is expected to produce until such time as

the constraint can be resolved by SCED through the RTBM.

(2) For the current dispatch interval and all future dispatch intervals during the period of time

an OOME is imposed, a Resource will receive Setpoint Instructions that are adjusted as

specified in the Market Protocols.

(3) The Transmission Provider will notify the Market Participant when the OOME event ends.

of 23

(4) To the extent that the OOME was is initiated directly by a local transmission operator, such

OOME may also specify either the fixed MW level or an OOME cap and/or OOME floor

MW level. Market Participants shall be compensated for such OOME in accordance with

Section 8.6.6 of this Attachment AE as if they had been issued an OOME by the

Transmission Provider; except that if the Market Monitor determines that the Resource

selected pursuant to Section 6.2.4(4) of this Attachment AE was selected by the local

transmission operator in a discriminatory manner and the Resource was affiliated with the

local transmission operator, such Resource shall not be eligible for compensation under

Section 8.6.6 of this Attachment AE. Such determination shall be made using the same

standards and procedures prescribed for Resource selection in the Intra-Day Reliability

Unit Commitment process, as set forth in Section 6.1.2.1 of this Attachment AE. The

recovery of the compensation paid by the Transmission Provider shall be collected by the

Transmission Provider locally as described under Section 8.6.7(B) of this Attachment AE.

(5) To the extent that the OOME was initiated by the Transmission Provider at the request of

a local transmission operator, such Resources issued OOMEs shall be selected by the

Transmission Provider in a non-discriminatory manner, which will be verified by the

Market Monitor through the process described under Section 6.1.2.1 of this Attachment

AE. In such event, Market Participants shall be compensated for such OOMEs in

accordance with Section 8.6.6 of this Attachment AE. The recovery of the compensation

paid by the Transmission Provider shall be collected by the Transmission Provider locally

as described under Section 8.6.7(B) of this Attachment AE.

(6) To the extent that the OOME was initiated by the Transmission Provider, such Resources

issued an OOME shall be selected by the Transmission Provider in a non-discriminatory

manner, which will be verified by the Market Monitor through the process described under

Section 6.1.2.1 of this Attachment AE. Recovery of compensation for Resources directly

issued OOMEs by Transmission Provider that are received under Section 8.6.6 of this

Attachment AE shall be collected regionally under Section 8.8 of this Attachment AE.

(7) The Transmission Provider, local transmission operator, and affected Resource owners

shall develop operating guides to be applied to OOMEs made to relieve known and

recurring reliability issues or to relieve known and recurring Emergency Conditions. Such

Resources will be compensated in the same manner as any other Resource that is issued

OOMEs. The recovery of the compensation paid by the Transmission Provider under

of 23

Section 8.6.6 of this Attachment AE shall be collected by the Transmission Provider locally

as described under Section 8.6.7(B) of this Attachment AE.

In addition to the actions listed above, if an OOME is issued in response to an Emergency

Condition, the Transmission Provider will post the Emergency Condition on OASIS as soon as

possible. The Transmission Provider shall displace the OOME with a market solution as soon as

possible consistent with system safety and reliability.

8.6.6 Real-Time Out-of-Merit Amount

An RTBM OOME payment will be made for each Asset Owner with a Resource that passes

a primary Contingency Reserve deployment test as described in Section 2.10.1 of this Attachment

AE and/or receives an OOME from the Transmission Provider or local transmission operator that

creates a cost to the Asset Owner or that adversely impacts the Asset Owner’s Day-Ahead Market

position for Energy and/or Operating Reserve. Resources issued an OOME by the Transmission

Provider or a local transmission operator that the Market Monitor determines were selected in a

discriminatory manner, as determined pursuant to Section 6.1.2.1 of this Attachment AE, and such

Resources were affiliated with the issuing party are not eligible to receive a RTBM OOME

payment. RTBM OOME payments made to Asset Owners that received an OOME to address a

Local Reliability Issue including Local Emergency Condition shall be recovered locally as

described under Section 8.6.7(B). RTBM OOME payments made to Asset Owners that received

an OOME to address a reliability issue other than a Local Reliability Issue shall be recovered

regionally under Section 8.8. The amount will be calculated on a Dispatch Interval basis as

follows:

(1) If the OOME is for Energy in the up direction and the Energy Offer Curve cost associated

with the Resource’s additional output attributable to its response (“OOME MW”) floor or

fixed is greater than the RTBM LMP, the Asset Owner will receive a payment for the

difference multiplied by the OOME floor or fixed MW. The payment shall be limited to

the amount necessary to compensate the Asset Owner for any under-recovery resulting

from its Resource’s response to the OOME. The OOME MW is calculated as the positive

difference between (i) the lesser of the actual Resource output or the Resource’s OOME

floor or fixed MW and (ii) the Resource’s economic operating point. The Resource’s

of 23

economic operating point is calculated as described under Section 8.6.5(4)(d) of this

Attachment AE;

(2) If the OOME is for Energy in the down direction (including a Resource de-commitment or

movement of an MCR to a configuration with a lower applicable maximum capacity

operating limit) and the RTBM LMP is greater than the Day-Ahead Market LMP, the Asset

Owner will receive a payment equal to the difference multiplied by the Resource’s

reduction in output attributable to its response (“OOME MW”) cap or fixed. The payment

shall be limited to the amount necessary to compensate the Asset Owner for any increase

in net settlement costs resulting from its response to the OOME. The OOME MW is

calculated as the maximum of zero (0) or the difference between the Resource’s Day-

Ahead Market cleared Energy MW and the greater of (i) actual Resource output or (ii) the

Resource’s OOME cap or fixed MW;

(3) If an OOME (including a Resource de-commitment instruction or movement of an MCR

to a configuration with a lower applicable maximum capacity operating limit) causes the

RTBM cleared amount of an Operating Reserve product to be less than the Day-Ahead

Market cleared amount of the corresponding Operating Reserve product and the RTBM

MCP is greater than the Day-Ahead Market MCP, the Asset Owner will receive a payment

for the difference multiplied by the OOME Operating Reserve MW. The OOME Operating

Reserve MW is calculated as the maximum of zero (0) or the difference between the

Resource’s Day-Ahead Market cleared Operating Reserve MW and the Resource’s RTBM

cleared Operating Reserve MW.

(4) To the extent that additional costs are incurred as a direct result of an OOME that are not

addressed through the compensation mechanisms described in (1) through (3) above, Asset

Owners may request additional compensation through submittal of actual cost

documentation to the Transmission Provider. The Transmission Provider will review the

submitted documentation and confirm that the submitted information is sufficient to

document actual costs and that all or a portion of the actual costs are eligible for recovery.


RR #: 196 Date: 10/21/2016

RR Title: Communicating MDRA Forecasted Commitments System Changes No Yes Process Changes? No Yes Impact Analysis Required? No Yes


Name: Jake Langthorn on behalf of GECTF Company: OG&E

Email: [email protected] Phone: 405-553-3409 Only Qualified Entities may submit Revision Requests.






Working Group (GECTF) Transmission Customers or other entities that are parties to





Correction

Clarification

Design Enhancement








Reliability/Operations - MPs have a potential risk of not being able to procure the necessary fuel due to the lack of transparency into potential commitments.


Market Protocols Section(s): 4.2.6.3 Protocol Version: 40 Operating Criteria Section(s): Criteria Date:

tel:4055533409

of 2

Planning Criteria Section(s): Criteria Date: Tariff (OATT) Section(s): Business Practice Business Practice Number:


Members of the Gas-Electric Coordination Task Force have been working together with SPP to address potential issues and risks regarding uncertainty of gas procurement requirements prior to the DA Market and RUC. The Market Participants believe that having a forecasted commitment in the days prior to the DA Market will allow for them to better plan and anticipate what their fuel requirements might be without having to necessarily wait until official commitment instructions from the MDRA, DA Market and RUC.


This Revision Request will provide the forecasted commitment information from the Multi-Day Reliability Assessment. This information will allow Market Participants to assess their potential fuel needs ahead of time and take appropriate action if they deem necessary.


Market Protocols

4.2.6.3 Multi-Day Reliability Assessment Results SPP staff communicates these start-up orders to the affected Market Participants. At the time of this notification, the submitted Offers become binding and the selected Resource(s) Offers are included in the DA Market with a Commitment Status similar to Self-commit. Unlike Self-Committed Resources, however, the Multi-day Reliability Assessment committed Resources will be eligible for DA Market make-whole payment guarantees as described under Section 4.5.8.12

Each day, SPP will electronically communicate the forecasted Resource commitments out of the Multi-day Reliability Assessment. Forecasted commitments for each Market Participant will be visible only to the affected Market Participant. The forecasted commitments will be provided as part of gas-electric coordination efforts and should be considered for informational purposes only. Actual commitment instructions from SPP may differ from the forecasted commitment. SPP is not responsible for any financial implications or other impacts as the results of actions Market Participants may take based on this forecasted information. SPP will make aggregated information publically available, which will include total Resource MWH by fuel type for each interval of the Multi-day Reliability Assessment.

Regulatory Report to MWG for February 2018 Current Filings

Description

FERC Docket No.

Activity Status

Deficiency Letter re: Order 745 Compliance

ER12-1179-024 FERC issued a deficiency letter on February 2, 2018 requesting more information on a filing that SPP made in May 2016 in the Integrated Marketplace docket regarding SPP compliance with Order No. 745 (Demand Response Compensation). Responses are due 30 days from the date of the letter (on or about March 5, 2018).

RR 200 – BSS OCL Design Change

ER18-792 Filing made on February 2, 2018 requesting an effective date of May 1, 2018 but seeking an order by April 17, 2018 to help ensure no interruptions in system changes. Comments are due February 23, 2018.

RR 243 – Mitigated Energy Offer for Regulation Deployment Adjustment

ER18-757 Filing made on January 31, 2018 requesting an effective date of May 1, 2018 but seeking an order in 60 days to help ensure no interruptions in system changes. Comments are due on February 21, 2018.

RR 258 – 2017 FCA Update

ER18-736 Filing made on January 30, 2018 requesting an effective date of April 1, 2018. Comments are due on February 20, 2018.

RR 225 – LTCR/ILTCR Clarification

ER18-571 Filing made on December 29, 2017 requesting an effective date of February 27, 2018. Comments are due on January 19, 2018.

• Three timely doc-less interventions were filed.

Awaiting response from FERC.

Investigation Opened by FERC into SPP’s Fast Start Practices

EL18-35 FERC withdrew the pending NOPR on Fast Start pricing (RM17-3) on December 21, 2017 and opened an investigation into SPP, NYISO and PJM, separately requiring each company to respond to investigation inquiries after finding that current practices on fast start pricing may be unjust and unreasonable because those practices do not allow prices to accurately reflect the marginal cost of serving load. The investigation will examine whether SPP should revise its Tariff to, among other things: (1) modify its dispatch process to respect physical parameters of resources whole minimizing production costs; (2) modify its pricing logic to allow the commitment costs of fast-start resources to be reflected in prices; (3)

Initial Briefs by all parties are due on February 12, 2018.

Regulatory Report to MWG for February 2018 allow all quick-start resources, including block-loaded quick-start resources to set price. This investigation was set up as a “paper hearing” and such any party desiring to participate in the proceeding must file a motion to intervene. The Commission expects to issue a final order in this proceeding by September 30, 2018.

• 47 (including SPP) doc-less interventions were filed.

• Initial Briefs are due on February 12, 2018 and response briefs 30 days later.

RR 229 – Order No. 831 (Offer Cap) Compliance

ER17-1568 Filing made in compliance with Order No. 831 – Offer Caps on May 8, 2017 as directed by FERC in the Order. Comments due on May 30, 2017. Amended filing made by SPP on May 18, 2017. Comments to that filing due on June 8, 2017.

• Nine doc-less interventions (between initial and amended filings). One protest (TDU Intervenors) and one set of supporting comments (SPP MMU). SPP responded to protests on June 15, 2017.

• Received order from FERC on November 9, 2017 accepting SPP’s filing for the effective date of April 1, 2019. Since this is being built to coincide with the implementation of the new settlement system, SPP will request a modified effective date to coincide with that later.

SPP will file with FERC requesting extension of the April 1, 2019 effective date closer to time – when the exact date of the new settlement system is determined.

RR 202 - Network Customers Obligation for Redispatch Costs

ER18-319 Filing made on May 9, 2017 requesting an effective date of July 15, 2017. Comments due on May 30, 2017.

• Twelve doc-less interventions. One set of supporting comments (Xcel) and two protests (Southern Company and Enel Green Power).

• SPP responded to protests on June 20, 2017. Southern Company, et. al. filed a motion to respond and response to SPP’s protest response on June 23, 2017.

• SPP received a letter order accepting the revisions, suspending the filing, subject to refund, and further Commission order, on July 13, 2017. (Standard language of orders without FERC quorum that were protested.)

Received a letter order from FERC on January 31, 2018 accepting the compliance filing made on November 20, 2017 with an effective date of October 19, 2017.

Regulatory Report to MWG for February 2018 • Received orders from FERC in this docket and in the EL16-110 dockets

that rejected the filing in this docket (ER17-1575) and issued compliance requirements in EL16-110 to satisfy the findings in this matter.

• This filing was rejected but a compliance filing on the issues of this docket and a previous attempt to address the issues will be filed by November 20, 2017. That filing was made on November 20, 2017 in Docket No. ER18-319.

RR 198 – Variable Demand Curve

ER17-1092 Filing made on March 2, 2017 requesting a May 11, 2017 effective date. Comments due on March 23, 2017.

• Eight doc-less interventions and one protest (GSEC) and one set of supporting comments (Westar).

• SPP responded to the protest on April 10, 2017.

• SPP received a deficiency letter on May 10, 2017 requiring additional information in 30 days. This caused RR 198 to not become effective on May 11, 2017 as a deficiency letter response by SPP will start the timeline running again.

• Response to deficiency filed on June 9, 2017.

• SPP received a letter order accepting the revisions, suspending the filing, subject to refund, and further Commission order, on August 4, 2017. (Standard language of orders without FERC quorum that were protested.)

• SPP put the revisions into effect per the August 4 Order on August 11 Operating Day.

• Received order from FERC on November 9, 2017 approving the filing with conditions. Compliance filing due 30 days from order date. Compliance filing due on December 11, 2017.

Awaiting order on compliance filing from FERC.

Regulatory Report to MWG for February 2018 Future Filings

RR Title Status/Anticipated Filing Date

116 Quick-Start Real-Time Commitment Filing postponed due to required initial

comments due to Docket No. EL18-35 on February 12, 2018.

142 Quick-Start Multi-Configuration Ineligibility Filing postponed due to required initial


182 Remove Reference to Control Area TBD

203 Adding Round 2 to ARR Monthly Auction Filing on or about May 1, 2018; scheduled effective date August 28, 2018

231 Mitigation of Locally Committed Resources TBD

245 Mitigated Start-Up and No-Load Offer Maintenance Cost TBD

247 Contingency Reserve Clearing During CR Events TBD

250 Market Import Service 1Q2018 filing

253 DVER Regulation Enhancement TBD

256 QSR Correction and Clean-Up Filing postponed due to required initial


Stakeholder Prioritization ProcessTerry Rhoades, PMO Manager


2

Process Overview

3

Portfolio Inputs Processed•Projects, RRs, Enhancements

Portfolio Report

Published

Stakeholders Send

Questions/ Feedback

Quarterly Meeting

with Stakeholders

Portfolio Adjustments

Portfolio Published for MOPC

SPP Stakeholder Portfolio Inputs

4

SPP Stakeholder

Portfolio

Projects*

Revision Requests Enhancements*

Defects*

*Member-facing/impacting

Quarterly Enhancement Process for SPP Stakeholder Prioritization

5

Enhancement Request

submission via RMS, RR submitted

via RR process

Priority scoringPriority Grouping (Current release,

Release+n, Unplanned, Other)

Publish SPP Portfolio Report

Stakeholder Questions/Feed

back via RMS

Quarterly Stakeholder

meeting

Portfolio Report update based

on stakeholder input

Publish updated Portfolio and

MeetingSummary

MOPC written report

Projects via PRPC & Qtrly.

Releases

Quarterly Project Process for SPP Stakeholder Prioritization

6

Enhancement Request

submission via RMS, RR submitted

via RR process

Priority scoringPriority Grouping (Current release,

Release+n, Unplanned, Other)

Publish SPP Portfolio Report

Stakeholder Questions/Feed

back via RMS


meeting

Portfolio Report update based

on stakeholder input

Publish updated Portfolio and

MeetingSummary

MOPC written report

Projects via PRPC & Qtrly.

Releases

Quarterly Schedule

7

Enhancement Request

Submission Deadlines

SPP Portfolio Report

Publication*(3rd week)


Prioritization Meeting

(mid-month)

MOPC Meeting

(mid-month)

Last Sunday in January

February mid-March mid-April

Last Sunday in April May mid-June mid-July

Last Sunday in July August mid-September

mid-October

Last Sunday in October

November mid-December

mid-January

* RRs approved by the primary working group and slated for MOPC/BOD approval are included in the portfolio report.

Process Review

8

Portfolio Inputs Processed•Projects, RRs, Enhancements

Portfolio Report

Published

Stakeholders Send

Questions/ Feedback

Quarterly Meeting

with Stakeholders

Portfolio Adjustments

Portfolio Published for MOPC

9

Additional Information

Additional background material is available on the Stakeholder Prioritization page on SPP.org.

Stakeholder Prioritization Page• Meeting Materials• Process and Training Documents• SPP Portfolio Report

https://www.spp.org/stakeholder-center/stakeholder-prioritization/

10

Questions

General Reference Bus Education & MWTG Reference Bus Design Session1/19/2018

• Yasser Bahbaz – Supervisor, Market Forensics• Ryan Schoppe – Engineer, Market Forensics• Gary Cate – Manager, Market Support & Analysis

2

Topics• Define Reference Bus

• Give examples of necessary market calculations which use the Reference Bus

• Show problems with a single Reference Bus

• Demonstrate SPP’s load Reference Bus

• Explain Reference Bus design for MWTG project

• Show why 1 reference bus for each interconnect must be used

• Answer frequently asked questions related to this subject

3

What is a reference bus?• Sinking point for network calculations such as the

loss-sensitivity & shift-factor

4

Inject 1 MW @ a node on the system

Withdraw 1 MW @ reference bus & observe system changes

Shift Factor Calculation• Impact on line is seen from injecting a MW @ each

pnode (Ex: C) and withdrawing a MW @ reference bus D

• Flow on Line AB is initially 100 MW, but changes to 100.5 MW after an incremental injection (Ex: 1 MW) @ C & withdrawal @ D

• 𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆 𝐹𝐹𝐹𝐹𝐹𝐹𝑆𝑆𝐹𝐹𝐹𝐹𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑤𝑤. 𝐹𝐹. 𝑆𝑆 𝐿𝐿𝑆𝑆𝐿𝐿𝐿𝐿𝐴𝐴𝐴𝐴 = 100.5 −1001

= 0.5 = 50%

5


Withdraw 1 MW @ reference bus & observe system changesA

B

C

D

Observe change on flowgates

Loss Sensitivity Calculation• Impact on SPP’s losses is seen from injecting a MW @

each pnode (Ex: C) and withdrawing a MW @ reference bus D

• SPP’s losses are initially 500 MW, but go up to 500.02 after injecting an incremental MW (Ex: 1 MW) @ C & withdrawing 1 MW @ D

• 𝐿𝐿𝐹𝐹𝐿𝐿𝐿𝐿 𝑆𝑆𝐿𝐿𝐿𝐿𝐿𝐿𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁 𝑁𝑁 = 500.02−5001

= 0.02 = 2%

6


Withdraw 1 MW @ reference bus & observe system changes

C

D

Single Reference Bus Issues• What happens if D is islanded?

The powerflow equations cannot be solved with D as reference due to what is called a singular matrix error

Must switch to new reference bus (Ex: C)

• What is the impact from switching to ref bus C? Sensitivities (Ex: Shift factors) are all done with respect to new

reference, so all values change between runs, causing possible confusion with results even though they are still valid

7

C


Withdraw 1 MW @ reference bus & observe system changesD

Pricing Note• It should be noted that the LMP at each pnode is the

same regardless of which Reference Bus is chosen This is true as long as there is no change to the system state

(different topology due to an outage, flows…etc) This is true because regardless of which reference is chosen,

calculating LMP at a pnode will involve moving the same units (Ex: Unit A goes up 2 MW & Unit B goes down 1 MW)

• The components of LMP (MEC, MLC, & MCC) change along with a reference bus switch, but not the actual LMP itself

• Therefore, the common perception that the reference bus is the best location to be on the network is inaccurate with respect to LMP

8

9

Reference D

$11$10

$10

$14

$25

$10.50

Reference E$11$10

$10

$14

$25

$10.50

• Moving from Reference bus D to Reference bus E has no impact on final LMP values

• Shift Factors and Loss Sensitivities do change

• LMP components (MEC, MLC, MCC) do change

What happens if we switch from Reference D to E with no other changes to the system?

SPP’s Reference Bus• SPP uses a reference bus composed of the market’s internal load

which always exists and changes gradually over time

• This is a fair and consistent approach as islanded equipment (Ex: switching reference bus due to bus outage) has negligible impact on sensitivities

• Below, each green pnode has a load and is thus part of the “distributed load reference” and withdraws a part of the 1 MW injection

10

C


Withdraw 1 MW @ distributed load reference bus & observe system changes

MWTG Reference Bus Design

11

West DC ties

East

MWTG Design Continued• DC ties are controllable devices that essentially separate

the interconnects An injection in an interconnect has no AC sensitivity impact on

losses or congestion in the other interconnect Therefore, Shift factors in the East are 0% with respect to

congestion in the West and vice-versa If you imagine a 1 MW injection in either interconnect, the ties

will still remain at their set-point after the injection, so this makes logical sense

• Two reference buses must be used A distributed load reference in the East, and a distributed load

reference in the West This merely extends what we currently do today into the west Has the least impact on SPP’s internal systems

12

DC Ties on Outage

13

West DC tiesEast

• 2 separate physical islands• 2 separate reference buses needed• MW injection in 1 island cannot

physically reach the other island

DC Ties at Max Capacity

14

West DC tiesEast

• 2 separate islands solution wise• 2 separate reference buses needed• Incremental MW injection in West

cannot reach the East

Current Sensitivity Engine & MCE Architecture

15

Sensitivity Calculation

Engine

Market Clearing Engine

Shift factors and loss sensitivities

• Shift Factor & Loss Sensitivities calculated by the Sensitivity Calculation Engine are fed into the Market Clearing engine which then performs the optimization and dispatch

Single Reference Theoretical Design Option #1

16


Engine



Iterate until convergence reached

• Initial Sensitivities are fed into MCE• MCE rotates sensitivities to where part of the injection in the East (Ex: 70%)

stays in the East and the other 30% goes on the DC ties based on load• The problem is determining which part of that 30% gets on what tie• MCE makes a guess and puts it on one tie and sees what happens, if the

solver wants to put it on other ties, it knows those have a higher sensitivity• Keeps solving until changes reach a minimum

Single Reference Theoretical Design Option #2

17


Engine



DC tie optimal dispatch

• Shift factors and loss sensitivities from the Sensitivity Calculation Engine are fed into MCE• MCE determines optimal tie dispatch (how much flow on each tie) and feeds this back into

the Sensitivity Calculation Engine• Sensitivities are recalculated a second time (based on new info) and fed back into MCE• MCE solves again (with new sensitivities) and feeds tie dispatch back into sensitivity engine• This process continues until a certain convergence threshold is reached

• Iterates until the change in the DC tie dispatch b/t intervals gets below a certain value• Current Sensitivity Engine calculates based on impedance (common to all power systems

software for this problem) and would have to be rewritten to deal with flows!

Iterate until convergence reached

Why can’t we use a single reference?• The AC powerflow problem & sensitivity analysis is done on an island basis and each

interconnect is essentially its own island requiring its own set of equations and solution

• Historical shift factors in the East would change in perhaps a large & unforeseen way if we attempted to use a single reference

• Major changes to: Network Sensitivity Calculation engine

Market Clearing Engine (MCE)

Market Controller

Settlements

• A shift away from the sensitivity calculations used in the standard market design used by other RTO/ISO’s

• In case of an outage across all 4 ties, we would then need to revert to using 2 references This would mean a massive amount of systems duplication as we would have to switch to

a very different system when that event occurs

All sensitivities would look very different before/after the outage

Similar to hitting DC tie capacity and/or ramp limits

• Implementation could introduce iteration into a system in order to determine the incremental response of each tie that doesn’t currently use this method Possible performance and convergence impacts 18

Single Reference (Summary)

• Using a single reference instead of one in each interconnect might be possible, but it would be a long-term R&D effort to find a solution A finalized method isn’t currently available

• Implementing the changes to the market clearing engine, sensitivity engines, and settlements would be very costly

• This would entail roughly 2x the effort and ~10x the risk

19

Other general MWTG design questions• Why does SPP use two SCUCs instead of one SCUC?

One SCUC isn’t something that is currently feasible due to performance with the size of a dual MWTG/SPP model under the current DA timeline

The plan is to use one SCUC for each interconnect and to run 1 single co-optimized SCED on top of it

SPP is open to moving to 1 SCUC in the future if hardware & software advances permit it (if it becomes a robust and viable option)

• Wouldn’t one SCUC be more efficient than two SCUCs?Aren’t you missing some opportunity where an interconnect might have a less efficient unit committed that wasn’t seen by a single SCUC The theoretical missed portion would be tiny (< 1% of peak

generation) This is very similar to the distant past in our market where we

had other congestion related bottlenecks, yet it was still one single market 20

• If the market has 2 different SCUCs, 1 SCED, and 2 different reference buses, is it really a single co-optimized market Yes, the 2 different SCUCs has little impact and is due to the

unique nature of the DA problem in that it is so large and has such a small amount of time to be solved that breaking it into 2 pieces is necessary for now

The 2 different reference buses is expected for an efficient market spanning two interconnects with multiple DC ties

The single SCED has a single objective function which is to minimize the cost of the market (both interconnects together) while optimizing energy and reserves in each interconnect and finding the optimal amount & direction of DC tie dispatch

21

SPP Marketplace Update: January 2018

Jason Bulloch-MMU ([email protected])

February 7th , 2018

Prepared for the February 2018 MWG conference

1

through 10 to be used in the MWG update

(others slides informational only)

2

Topics covered for January:

• Energy Prices

• Congestion

• RNU

• Make-Whole Payments

Notice: Some charts only cover through January

22nd due to Settlement data not being available at

the time this update was created.

Monthly average prices

3

Updated thru January 30th

$0

$2

$4

$-

$5

$10

$15

$20

$25

$30

$35

$40

$/

MM

BT

U

$/

MW

H

SPP NORTH HUB

DA LMP RT LMP DA MEC

RT MEC Panhandle

$0

$2

$4

$-

$5

$10

$15

$20

$25

$30

$35

$40

$/

MM

BT

U

$/

MW

H

SPP SOUTH HUB

DA LMP RT LMP DA MEC

RT MEC Panhandle

Resources on the Margin

4

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

I% O

F IN

TER

VA

LS

DAMKT % Intervals with Fuel on the

Margin

Coal Gas-CC Gas-SC Other Virtual Wind

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

% O

F IN

TER

VA

LS

RTBM % Intervals with Fuel on the

Margin

Coal Gas-CC Gas-SC Other Wind

5

Off-peak LMPs

6

On-peak LMPs

7

Top 10 RT breached bound flowgates

by shadow price

$0

$20

$40

$60

$80

$100

$120

RTBM DAMKT

January 2018M2 M


Flowgate Owner From Area To Area Voltage or Element Created TimeNEORIVNEOBLC SWPP WR EDE NSES-RAM452 161 Not Applicable

TMP151_23193 SWPP EDE EDE LN OAK432 - ATL1091 161 kV 10/19/2017 10:58:53 AM -05:00

TAHH59MUSFTS SWPP GRDA OKGE TAHLQH5-HWY59 161 Not Applicable

TMP228_22196 SWPP SPS SPS LN HALE_CO - TUCO 115 kV 9/30/2016 7:06:08 AM -05:00

TMP118_22847 SWPP OKGE OKGE LN STHRD - ROMAN 138 kV 5/25/2017 12:40:55 AM -05:00

TMP216_23434 SWPP CSWS CSWS XF DIANA 345/138 kV 1/11/2018 11:56:49 PM -06:00

VINHAYPOSKNO SWPP MIDW MIDW VINETAP3-NHAYS 115 Not Applicable

TEMP57_23383 SWPP EDE EDE LN AUR1241 - RDSPG5 161 kV 1/2/2018 10:42:50 PM -06:00

TEMP37_23347 SWPP KCPL KCPL LN CENTNIAL - PAOLA 161 kV 12/19/2017 12:07:28 PM -06:00

TMP168_23377 SWPP AECI AECI LN CLINTON - TRUM_SPA 161 kV 1/2/2018 8:16:38 AM -06:00

Revenue neutrality uplift

8

*This table is based on the latest available settlements data and is subject to change due to resettlement

• Green cell denotes payments to revenue neutrality uplift recipients and clear cells represent cost

• Table in thousands of dollars

Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18

DA Revenue Inadequacy 98$ 26$ 59$ 10$ 102$ (153)$

RT Revenue Inadequacy (55,111)$ (28,664)$ (91,301)$ (45,862)$ (149,485)$ 16,993$

OOME MWP (359,055)$ (601,483)$ (2,412,847)$ (823,109)$ (326,074)$ (974,155)$

RT Regulation Deployment Adj (168,052)$ (256,659)$ (281,245)$ (221,323)$ (261,661)$ (275,775)$

RT JOA 161,291$ 905,928$ 5,845,213$ 5,228,495$ 4,270,207$ 6,001,048$

RT Congestion (3,644,785)$ (5,149,392)$ (11,202,581)$ (10,017,786)$ (7,361,790)$ (16,528,396)$

Sub-Total (4,065,614)$ (5,130,244)$ (8,142,702)$ (5,879,575)$ (3,828,701)$ (11,760,438)$

Less RT Net Inadvertent 476,735$ 277,584$ (351,532)$ (43,904)$ 220,518$ 201,647$

RNU * 4,542,349$ 5,407,828$ 7,791,170$ 5,835,671$ 4,049,219$ 11,962,085$

Updated thru January 22nd

January MWPs and Congestion Rents

9

OPERATING_DATE Total RT MWPS Total DA MWPS RTCongestion

Rents

DA Congestion

Rents

RT MWPS

%

of month

DA MWPS

% of month

RT Congestion

Rents

%

of month

DA

Congestion

Rents

%

of month

1/1/2018 (218,355)$ $ (55,327) $ (325,853) $ 2,617,192 4% 2% 2% 4%

1/2/2018 (694,527)$ $ (222,827) $ (2,016,467) $ 2,809,923 14% 6% 12% 5%

1/3/2018 (554,550)$ $ (122,880) $ (577,277) $ 4,402,444 11% 4% 3% 8%

1/4/2018 (32,889)$ $ (108,966) $ (367,878) $ 2,680,314 1% 3% 2% 5%

1/5/2018 (108,272)$ $ (168,381) $ 33,384 $ 2,348,618 2% 5% 0% 4%

1/6/2018 (91,301)$ $ (174,601) $ (500,753) $ 1,221,910 2% 5% 3% 2%

1/7/2018 (399,405)$ $ (136,318) $ (191,952) $ 1,288,514 8% 4% 1% 2%

1/8/2018 (24,579)$ $ (33,780) $ (54,262) $ 873,081 0% 1% 0% 1%

1/9/2018 (36,378)$ $ (325,598) $ (389,000) $ 2,647,384 1% 9% 2% 5%

1/10/2018 (54,372)$ $ (323,738) $ (656,274) $ 3,804,776 1% 9% 4% 6%

1/11/2018 (21,944)$ $ (127,937) $ (169,185) $ 3,079,730 0% 4% 1% 5%

1/12/2018 (248,713)$ $ (18,876) $ 236,536 $ 1,174,102 5% 1% -1% 2%

1/13/2018 (8,444)$ $ (45,354) $ (13,421) $ 1,181,636 0% 1% 0% 2%

1/14/2018 (55,575)$ $ (228,042) $ (198,205) $ 869,961 1% 7% 1% 1%

1/15/2018 (335,543)$ $ (140,840) $ (1,592,011) $ 2,807,336 7% 4% 9% 5%

1/16/2018 (492,128)$ $ (7,174) $ (1,115,118) $ 2,095,810 10% 0% 7% 4%

1/17/2018 (788,203)$ $ (274,049) $ (3,936,084) $ 4,186,394 15% 8% 23% 7%

1/18/2018 (579,977)$ $ (183,387) $ (4,084,924) $ 5,246,081 11% 5% 24% 9%

1/19/2018 (90,925)$ $ (352,624) $ (835,535) $ 6,224,238 2% 10% 5% 11%

1/20/2018 (60,410)$ $ (115,487) $ (51,429) $ 1,214,227 1% 3% 0% 2%

1/21/2018 (19,777)$ $ (131,501) $ 40,483 $ 1,603,128 0% 4% 0% 3%

1/22/2018 (62,786)$ $ (102,149) $ 236,828 $ 3,303,277 1% 3% -1% 6%

1/23/2018 (109,763)$ $ (71,580) $ (248,829) $ 874,102 2% 2% 1% 1%

January Congestion Rents by product type

10

OPERATING

DATE

RT

TOTAL

CONGESTION

DA

TOTAL

CONGESTION

RT NET

LOAD/GEN

CONG

DA NET

LOAD/GEN

CONG

RT NET

IMPEXP

CONG

DA NET

IMPEXP

CONG

RT

PSEUDO

TIE

CONG

RT Virtual

CONG

DA Virtual

CONGVirtual Profits

Virtual

Profits

from

Congestion

1/1/2018 $ (325,853) $ 2,617,192 $ (117,293) $2,506,830 $ 37,988 $ (8,728) $ (40,005) $ (206,543) $ 119,089 $ (114,163.20) (87,454)$

1/2/2018 $ (2,016,467) $ 2,809,923 $(1,084,952) $2,512,523 $ 174,797 $ 47,393 $ (41,938) $(1,064,374) $ 250,007 $(1,231,073.61) (814,367)$

1/3/2018 $ (577,277) $ 4,402,444 $ (163,185) $3,819,079 $(188,497) $ 70,828 $107,598 $ (333,192) $ 512,537 $ 221,168.55 179,345$

1/4/2018 $ (367,878) $ 2,680,314 $ (224,123) $2,480,978 $ 40,328 $ (6,807) $133,480 $ (317,564) $ 206,143 $ 59,957.45 (111,420)$

1/5/2018 $ 33,384 $ 2,348,618 $ 59,026 $2,156,940 $ 53,308 $ 18,843 $ 86,327 $ (165,278) $ 172,835 $ 92,044.85 7,557$

1/6/2018 $ (500,753) $ 1,221,910 $ (26,593) $ 847,763 $ 39,037 $ 61,684 $ 64,575 $ (577,771) $ 312,464 $ (290,352.68) (265,308)$

1/7/2018 $ (191,952) $ 1,288,514 $ 99,532 $ 728,896 $ 27,738 $ 84,770 $ 43,905 $ (363,127) $ 474,848 $ 54,580.90 111,721$

1/8/2018 $ (54,262) $ 873,081 $ 147,949 $ 624,788 $ 6,630 $ 22,736 $ 28,284 $ (237,125) $ 225,557 $ 61,854.28 (11,568)$

1/9/2018 $ (389,000) $ 2,647,384 $ 450,778 $1,457,883 $ (45) $ 81,452 $123,339 $ (963,072) $1,108,049 $ 313,078.49 144,977$

1/10/2018 $ (656,274) $ 3,804,776 $ 702,209 $2,396,044 $ (15,622) $ 97,832 $154,667 $(1,497,528) $1,310,900 $ (13,295.13) (186,628)$

1/11/2018 $ (169,185) $ 3,079,730 $ 343,140 $2,114,005 $ (4,482) $ 19,963 $ 62,130 $ (569,974) $ 945,761 $ 694,425.52 375,788$

1/12/2018 $ 236,536 $ 1,174,102 $ 289,245 $1,074,545 $ (47,016) $ 3,058 $ 1,910 $ (7,603) $ 96,500 $ 69,590.26 88,896$

1/13/2018 $ (13,421) $ 1,181,636 $ (5,898) $1,038,427 $ 34,577 $ 51,709 $ (4,634) $ (37,465) $ 91,501 $ 368,563.79 54,036$

1/14/2018 $ (198,205) $ 869,961 $ (249,519) $ 685,894 $ 390,998 $ 31,657 $ 84,771 $ (424,455) $ 152,410 $ (279,013.92) (272,045)$

1/15/2018 $ (1,592,011) $ 2,807,336 $ (356,580) $2,352,458 $(210,129) $ 52,189 $268,977 $(1,294,279) $ 402,690 $ (939,785.40) (891,589)$

1/16/2018 $ (1,115,118) $ 2,095,810 $ (176,597) $1,914,438 $ 34,360 $ (26,865) $118,097 $(1,090,977) $ 208,237 $(1,413,155.05) (882,741)$

1/17/2018 $ (3,936,084) $ 4,186,394 $(1,257,948) $3,045,235 $ (17,157) $152,910 $238,265 $(2,899,243) $ 988,249 $(2,422,015.22) (1,910,994)$

1/18/2018 $ (4,084,923) $ 5,246,081 $(1,229,951) $3,655,339 $(218,220) $ 35,445 $535,218 $(3,171,971) $1,555,297 $(2,074,927.40) (1,616,673)$

1/19/2018 $ (835,535) $ 6,224,238 $ 227,143 $4,647,219 $ (12,815) $ 85,032 $171,253 $(1,221,116) $1,491,988 $ 48,304.72 270,872$

1/20/2018 $ (51,429) $ 1,214,227 $ 70,993 $ 750,678 $ (1,142) $ 36,608 $ 8,475 $ (129,755) $ 426,942 $ 257,657.12 297,186$

1/21/2018 $ 40,483 $ 1,603,128 $ 154,037 $1,083,999 $ 2,977 $ 29,502 $ 7,361 $ (123,892) $ 489,627 $ 373,398.85 365,735$

1/22/2018 $ 236,828 $ 3,303,277 $ 481,186 $2,418,450 $ (6,499) $ 42,020 $183,610 $ (421,469) $ 842,806 $ 276,936.31 421,337$

1/23/2018 $ (248,829) $ 874,102 $ (68,560) $ 697,361 $ 11,699 $ 6,008 $144,109 $ (336,078) $ 170,733 $ (230,713.61) (165,345)$

$-

$3.0

$6.0

$9.0

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

2017 2018

Mil

lio

ns

Day-Ahead

Coal Gas-CC Gas-CT Hydro Other Wind

$-

$3.0

$6.0

$9.0


2017 2018

Mil

lio

ns

RUC (Real-Time)

Coal Gas-CC Gas-CT Hydro Other

Make whole payments

11*Only fuel types that have had make whole payments will be present on the legends


Below slides not presented at the Market Working Group update.

Informational only

12

13

Pri

ce (

$/M

Wh)

Average daily energy hub prices

SPPNORTH_HUB - DAMKT SPPNORTH_HUB - RTBM

SPPSOUTH_HUB - DAMKT SPPSOUTH_HUB - RTBM


14

RTBM energy scarcity January 2018

$-

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

0

1

2

3

4

5

6

7

8

Pri

ces

Co

un

t o

f in

terv

als

ENERGY_SCARCITY_INTERVALS REGUP_SCARCITY_INTERVALSREGDN_SCARCITY_INTERVALS OR_SCARCITY_INTERVALSAverage of REGUP_SCARCITY_PRCAverage of REGDN_SCARCITY_PRCAverage of OR_SCARCITY_PRC


15

Pri

ce

($

/M

W)

Daily avg REG UP prices

$-

$5

$10

$15

$20

$25

$30

DAMKT - REGUP RTBM - REGUP


16

Daily avg REG DN prices

0

50

100

150

200

250

300

350

$-

$5

$10

$15

$20

$25

Win

d o

utp

ut

tho

usa

nd

s o

f M

Wh

rs p

er

day

Pri

ce (

$/M

W)

WIND - RTBM REGDN - DAMKT REGDN - RTBM

Monthly average spin/supplemental prices

17

$0

$2

$4

$6

$8

$10

$12

Jan 17 Feb 17 Mar 17 Apr 17 May 17 Jun 17 Jul 17 Aug 17 Sep 17 Oct 17 Nov 17 Dec 17 Jan 18

$/M

Wh

spinning reserves

Spin DA Spin RT


$0.00

$0.50

$1.00

$1.50

$2.00

$2.50


$/M

Wh

supplemental reserves

Supp DA Supp RT

Monthly average regulation prices

18$0

$6

$12

$18

$24


$/M

Wh

Regulation Down

Reg Down RT Reg Down DA Reg Down Mileage RT

$0

$6

$12

$18

$24


$/M

Wh

Regulation Up

Reg Up RT Reg Up DA Reg Up Mileage RT


19

Daily avg SPIN prices

$0

$5

$10

$15

$20

$25

Pri

ce (

$/M

W)

DAMKT RTBM

20

Daily avg SUPP prices

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

Pri

ce (

$/M

W)

DAMKT RTBM

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

101%

102%

Jan-17 Feb-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18

Cleared Demand as a Percent of Reported Load -Off Peak Cleared Demand as a Percent of Reported Load-On Peak

Load participation in DAMKT

21


$(8,500)

$(7,500)

$(6,500)

$(5,500)

$(4,500)

$(3,500)

$(2,500)

$(1,500)

$(500)

$500


2017 2018

Tho

usa

nd

s $

Virtual's net (profit/loss) by location type (negative is profit)

Hub Interface Load Resource

Cleared virtual activity by settlement location type

22


0

500

1000

1500

2000

2500

3000


2017 2018

Tho

usa

nd

s M

Wh

rs

Cleared virtuals MWs by location type (sum of bids and offers)

Hub Interface Load Resource


23

Market-to-market payments by constraintfor January 2018

$5,145,333

$615,390

$207,501 $165,635 $106,834 $83,724 $68,270 $49,763 $13,347 $10,137 $8,989 $7,771

$(483,539)

-$1,000,000

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

(Negative Payments to MISO, Positive to SPP)Flowgates between -$5K and $5K removed


Market-to-market flowgatedescriptions

24

Owner From Area To Area Voltage or Element

Created Time

SWPP WR EDE NSES-RAM452 161

Not Applicable

SWPP NPPD MPS COOPER-ST_JOE 345

Not Applicable

SWPP OKGE OKGE XF FTSMTH 345/161 kV

10/4/2016 4:05:43 PM -

05:00

SWPP MEC OPPD LN RAUN - TEKAMHO 161 kV

12/8/2017 3:59:02 PM -

06:00

SWPP KCPL KCPL NASHUA-NASHUA 345/1

Not Applicable

MISO EES EES LN PERVIL - B_WLSN 500 kV

1/9/2018 4:40:20 PM -

06:00

SWPP OPPD OPPD LN NEBRCTY - SUB3456 345 kV

5/17/2017 10:03:54 PM -

05:00

MISO EES EES LN GRI - MTZ 138 kV

6/4/2017 1:54:14 PM -

05:00

MISO AMRN AMRN LN OVER - CALF 161 kV

11/20/2017 10:43:44 AM -

06:00

SWPP MPS MPS EASTTOWN-EASTTOWN 345/161

Not Applicable

SWPP WR EDE LN NSES - RAM452 161 kV

6/14/2017 9:25:30 AM -

05:00

SWPP NPPD AECI COOPER-FAIRPORT 345

Not Applicable

MISO AMRN AMRN OVER-OVER 345/161

Not Applicable

$(370)

$2,006

$(500)

$-

$500

$1,000

$1,500

$2,000

$2,500

Tho

usa

nd

s

Daily Net+ MISO to SPP / - SPP to MISO

~$6 millionmonthly total

25

Market-to-market payments, by day

Updated thru January

22nd

Flowgate information can be found at

https://www.oasis.oati.com/SWPP/index.html

(look under “Transmission” Folder> “Flowgates”>SWPP_Flowgates.xlsm)

Flowgate descriptions

26

https://www.oasis.oati.com/SWPP/index.html

27

Wind and net virtual participation at

wind locations

0

50

100

150

200

250

300

350

400

GW

hrs

Pe

r d

ay

DaClrdWind DACLRDWIND+NETVIRTS RtBillMtr5minQty(actual output)

0%

5%

10%

15%

20%

25%

30%

35%

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

Jan

Feb

Mar

Ap

r

May Jun

Jul 1

Sep

Oct

No

v

Dec Jan

Feb

Mar

Ap

r

May Jun

Jul 1

Sep

Oct

No

v

Dec Jan

Feb

Mar

Ap

r

May Jun

Jul 1

Sep

Oct

No

v

Dec Jan

2015 2016 2017 2018

GW

/hr

Wind output (GW/hr)

% of Wind/LOAD

28

Monthly wind generation/loadUpdated thru January 22nd

January TCR summary

29

-1

-0.5

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

5.5

6

6.5

7

Millions

DA_REVENUE TCR_FUNDING SURPLUS_SHORTFALL


TCR summary by month

300%

20%

40%

60%

80%

100%

120%

$(20)

$-

$20

$40

$60

$80

$100

Mill

ion

s

DA_REVENUE TCR_FUNDING SURPLUS_SHORTFALL

FUNDING_PERCENT CUMULATIVE_PERCENT


ARR summary by month

31

100%

150%

200%

250%

300%

350%

$-

$5

$10

$15

$20

$25

$30

$35

$40

$45

Mill

ion

s

TCR_REVENUE ARR_FUNDING SURPLUS_SHORTFALL

FUNDING_PERCENT CUMULATIVE_PERCENT

149%Cumulative Funding


32

Mitigated resource starts as a % of

all starts

0

2

4

6

8

10


2017 2018

% o

f R

eso

urc

e ST

AR

TS t

hat

are

Mit

igat

ed

Mitigated Resource Starts as a Percentage of all Starts

DA MANUAL RUC

[email protected]

33

TimestampAre you a voting member of the

MWG?

The agenda reflects the actions to be taken during the meeting.

Meeting materials are provided in a timely manner.

2018/01/10 11:56:01 AM CSTNo 4 4

2018/01/10 12:05:08 PM CST No 4 4

2018/01/10 12:10:01 PM CSTYes 3 2

2018/01/10 12:22:58 PM CSTYes 4 3

2018/01/10 12:54:40 PM CST Yes 4 32018/01/10 1:29:22 PM CST No 4 4

2018/01/10 2:48:47 PM CSTYes 4 4

2018/01/10 3:14:46 PM CST No 4 42018/01/12 9:39:51 AM CST Yes 3 32018/01/24 10:56:30 AM CST Yes 4 4

The information presented in

meetings is clear.

I am engaged during the meeting.

Facilitation is sufficient to

guide discussion.

I depart the meeting with a feeling that we

have accomplished something.

4 4 4 4

3 3 3 3

4 4 4 3

4 4 4 4

4 3 4 34 4 4 4

4 4 4 4

4 4 4 43 3 3 34 4 4 4

Additional Comments

I enjoyed the new meeting space. Although I couldn't hear some from the other side of the room when they were speaking and suggest getting microphones for use in the room.

Enjoyed the new conference room. The Dialog on all subjects was very good and interesting. I always learn from others so enjoy the discussions

Several meeting material updates, including during the meeting. New meeting location is better, but sound in the room may be an issue.?

Jim Flucke did an excellent job as chair of the meeting but because of his tremendous work load he should only be asked to occasionally fill in for Richard.

January RTO UpdateFebruary 2018 MWG

Jeremy Verzosa: [email protected]

Gary Cate: [email protected]

2



Marketplace Update• Regulation Performance

• Congestion Overview

• RUC Update

• Pricing

• Load Forecast accuracy

• Wind forecast accuracy

• DAMKT Update

• Flowgate Appendix

3

Regulation PerformanceSection 1

4

January 2017 Regulation Up Performance

5

0123456789

1011121314151617181920212223242526272829303132

5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Res

ourc

e C

oun

t

Score (%)

Reg Up

January 2017 Regulation Down Performance

6

0123456789

101112131415161718192021222324252627282930313233343536373839404142434445464748

Res

ourc

e C

oun

t

Score (%)

Reg Down

Congestion OverviewSection 2

7

DA vs RT Constraints• Top 10 Congested Constraints in DA

8

Constraint Intervals Binding/Breached

Average Shadow Price

TEXAS_CO_TXPS_TXCO_PHSHFT_PS 743 2.52

TMP151_23193 511 67.29

NEORIVNEOBLC 429 75.55

TEMP37_23347 345 16.75

VINHAYPOSKNO 278 18.86

TMP228_22196 271 51.86

TMP183_23367 209 13.77

TEMP56_23357 207 4.16

VMA_PALO 190 2.85

MRTPANHUTMRT 183 3.33

99

SPS

SECIWR

NPPD

WFEC

EES

KCPL

MPS

EDE

MEC

AECI

AECC/EES

CSWSOKGE

SPA

LESOPPD

Colorado

Wyoming

New Mexico

Texas

Iowa

Arkansas

Missouri

Top 10 Congested Constraints in DA for January

Missouri

SECIWR

TEXAS_CO_TXPS_PHSHFT_PS

NEORIVNEOBLC

TMP228_22196

TEMP37_23347

TEMP56_23357

TMP151_23193

TMP183_23367

MRTPANHUTMRT

VINHAYPOSKNO

DA vs RT Constraints• Top 10 Congested Constraints in RTBM

10

Constraint Intervals Binding/Breached

Average Shadow Price

NEORIVNEOBLC 3375 114.57

TMP175_23386 2322 3.58

PLXSUNTOLYOA 1824 19.63

TMP228_22196 1428 53.18

MRTPANHUTMRT 1366 5.36

TMP151_23193 1299 72.84

VINHAYPOSKNO 1150 36.36

TMP103_22587 1133 14.34

TMP216_23434 1110 33.70

TEMP56_23357 874 6.07

1111

SPS

SECIWR

NPPD

WFEC

EES

KCPL

MPS

EDE

MEC

AECI

AECC/EES

CSWSOKGE

SPA

LESOPPD

Colorado

Wyoming

New Mexico

Texas

Iowa

Arkansas

Missouri

Top 10 Congested Constraints in RTBM for January

Missouri

SECIWRWR

PLXSUNTOLYOA

TMP228_22196

NEORIVNEOBLC

TEMP56_23357

VINHAYPOSKNO

TMP175_23386

TMP103_22587

TMP216_23434

MRTPANHUTMRT

TMP151_23193

RUC UpdateSection 3

12

Commitment Breakdown by MW– January 2018

• The commitment breakdown for the month of January is shown to the right of total commitments by MW made by DAMKT, RUC, SELF, and MANUAL.

• About 97% (22,704,633 MW) of the commitments came from DAMKT, while about 1% were considered manual.

• Of that 1% (258,404 MW) of manual commitments, roughly 139 of those (58,786 MW) were actual new commitments.

13

*SELF commits are post DAMKT

70.0%

80.0%

90.0%

100.0%

November December January '18

DAMKT DA_RUC ID_RUC MANUAL SELF

November December January '18DAMKT 17,584,176.40 20,504,749.10 22,704,632.50 DA_RUC 47,042.00 19,196.00 30,067.20 ID_RUC 40,036.20 60,803.40 108,523.50 MANUAL 227,759.00 151,854.40 258,403.70 SELF 136,205.80 307,194.30 277,070.60

January PricingSection 4

14

15*=more info for anomalies included on next slide

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Hourly Avg LMPDA LMP RT LMP

16

RT LMP Outliers• Highest LMPs (hourly avg)

1/1/2018 04:00 $125.77 RegSpin shortages affected the prices during this hour.

1/12/2018 09:00 $295.08 AS shortages and a CRD Event affected the prices during this hour.

1/16/2018 17:00 $178.64 RegSpin shortages affected the prices during this hour.

1/27/2018 09:00 $218.92 AS shortages affected prices during this hour.

1/27/2018 15:00 $228.34 A CRD Event occurred during this hour which caused shortages that affected the prices

during this hour.

17

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1-Jan 1-Feb 1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov 1-Dec 1-Jan

LMP

DA LMP

RT LMP

Day Ahead 17-Jan 17-Feb 17-Mar 17-Apr 17-May 17-Jun 17-Jul 17-Aug 17-Sep 17-Oct 17-Nov 17-Dec 18-Jan

DA MEC $ 24.50 $ 19.96 $ 20.01 $ 23.32 $ 23.09 $ 25.01 $ 29.17 $ 24.24 $ 22.85 $ 19.56 $ 20.92 $ 22.24 $ 29.57

DA MLC $ (0.12) $ (0.15) $ (0.13) $ (0.17) $ (0.20) $ (0.21) $ (0.18) $ (0.23) $ (0.17) $ (0.18) $ (0.36) $ (0.42) $ (0.63)

DA MCC $ (0.46) $ (0.10) $ (0.42) $ (0.50) $ (0.54) $ (0.49) $ (0.39) $ 0.01 $ (0.55) $ (1.20) $ (0.99) $ (0.99) $ (1.18)

DA LMP $ 23.92 $ 19.72 $ 19.46 $ 22.65 $ 22.36 $ 24.32 $ 28.61 $ 24.03 $ 22.13 $ 18.18 $ 19.57 $ 20.83 $ 27.75

Real Time 17-Dec 17-Feb 17-Mar 17-Apr 17-May 17-Jun 17-Jul 17-Aug 17-Sep 17-Oct 17-Nov 17-Dec 18-Jan

RT MEC $ 23.62 $ 19.62 $ 20.89 $ 22.78 $ 20.70 $ 23.55 $ 28.80 $ 25.05 $ 23.29 $ 18.84 $ 20.22 $ 23.13 $ 28.03

RT MLC $ (0.14) $ (0.11) $ (0.14) $ (0.20) $ (0.22) $ (0.22) $ (0.23) $ (0.16) $ (0.26) $ (0.19) $ (0.35) $ (0.44) $ (0.67)

RT MCC $ (0.13) $ (0.45) $ 0.14 $ 0.18 $ (0.34) $ 0.13 $ 0.41 $ (0.19) $ (0.31) $ (0.57) $ (0.77) $ (0.90) $ (1.04)

RT LMP $ 23.35 $ 19.06 $ 20.89 $ 22.75 $ 20.14 $ 23.47 $ 28.98 $ 24.71 $ 22.72 $ 18.08 $ 19.09 $ 21.79 $ 26.32

Load ForecastSection 5

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20* Load forecast data used from DA-RUC cases

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Short Term Load Forecast

Daily AVG STLF Daily AVG Actual Error Threshold % Forecast Error %

Wind ForecastSection 6

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23* Wind forecast data used from DA-RUC cases* Forecast also includes solar

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Mid Term Wind Forecast

Daily AVG MTWF Daily AVG Actual Error Threshold % Forecast Error %

24* Wind forecast data used from DA-RUC cases

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DAMKT UpdateSection 7

27

DA Obligations vs RUC Obligations - January• DA (Cleared Load + NSI – Virtual Offers – Wind Offers)

• RUC (Load Forecast + NSI – Wind Forecast)

2713000

15000

17000

19000

21000

23000

25000

27000

29000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

RUC

DA

DA Obligations vs RUC Obligations - January• All January days averaged into one “average” day

• Average 300 MW (DA over RUC)

• Differences Virtual Bids Wind offered in DA vs Wind forecast in RUC

28

DA Obligations vs RUC Obligations - January

Average MW Difference by Hour

29-2500

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31000

33000

35000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

MTLF

Demand Bid

Appendix Section 8

31

32

Constraint Elements Reason

TMP151_23193Mon: Oakland N – Joplin Atlas Jnct

161kVCon: Asbury – Purcell SW 161kV

This FG competes with another permanent FG.

PLXSUNTOLYOAMon: Plant X Sub – Sundown 230kV

Con: Tolk Sub – Yoakum 230kVGeneration fluctuation in the area.

TEMP37_23347Mon: Centennial – Paola 161kVCon: W Gardner – Pleasantville

161kVGeneration outage in the area.

VMA_PALO DAMKT constraint driven to its limits by virtual market activity.

TMP183_23367Mon: Johnson lake – Johnson 2 115kV

Con: N Platte – Crooked Creek 230kV

This flowgate competes with another temporary flowgate with wind impacting both.

TEMP56_23357Mon: Sweetwater – Chisolm 230kVCon: Tatonga – Matthewson 345kV

High wind impact on this FG.

TMP228_22196Mon: Hale Co – Tuco 115kVCon: Swisher – Tuco 230kV

Transmission outage in the area.

VINHAYPOSKNOMon: Vinetap – N Hays 115kVCon: Post Rock – Knoll 230kV

High wind impact on this FG.

NEORIVNEOBLCMon: Neosho – Riverton 161kV

Con: Neosho – Blackberry 345kVHigh wind causes congestion on this FG.

33

TEXAS_CO_TXPS_TXCO_PHSHFT_PSThis has always been “activated” and has been showing up in the MDB solution constraint tables since the 1.12 release.

MRTPANHUTMRTMon: Martin – Pantex N 115kV

Con: Martin – Hutchinson 230kVHigh wind impact on this FG.

TMP175_23386Mon: Bushland 230/115kV XFR

Con: Bushland Deafsmith 230kVHigh wind impact on this FG.

TMP103_22587Mon: Kildare – White Eagle 138kV

Con: Hunter – Woodring 345kVHigh wind impact on this FG.

TMP216_23434Mon: Diana 345/138kV XFRCon: Diana 345/138kV XFR

Transmission outage in the area.

Closure Pending MWG Action ItemsKristen Darden

Market Working Group

February 6-7, 2018

[email protected]

1

Closure Pending AI 344

2

Action Item Description Update

344 Congestion Hedging staff to provide detailed examples on how financial rights across DC ties will be handled for MWTG following the December MWG meeting

1/8/18: John Luallen presented education during January 8 - 9 MWGMeeting

Closure Pending AI 346

3

Action Item Description Update

346 SPP staff to bring back an IA for RR266 (JOU Combined Single Resource Modeling post Settlement Share Allocation) to be implemented with the new SPP Settlements system

1/30/18: IA will be provided during the February 6 – 7 MWG meeting

Action Item

Org Group

Date Originated

Action Item Update Summary Status(Not Started, In

Progress, Closure Pending, On Hold,

Closed)

Owner Comments Date Closed

314 MWG/BOD/MOPC

07/25/16 Recommendation from the 2015 ASOM Report (NDVER to DVER Conversion). MOPC AI # 272

8/14/2017: During the September MWG, staff will provide an update on all potential NDVER to DVER conversion options including the pros and cons of each with the expectation that the MWG will chose an option for SPP to further develop with the group. 9/1/2017: More discussion is planned for the NDVER to DVER conversion topic at future MWG meetings, and this discussion may be decoupled from the VER repowering discussion. 9/20/2017: SPP staff will provide an update during the October MWG meeting. 10/16/2017: SPP staff will bring a draft RR NDVER to DVER to the October MWG meeting. 10/24/2017: NDVER to DVER discussion deferred to the November 3rd MWG conference call. 11/3/2017: Deferred to January 8 MWG meeting1/8/2018: The group discussed two options; 1) RR263 NDVER to DVER Conversion through Incentives and 2) RR272 NDVER to DVER Conversion. MWG plans to take action on this topic during the February 6th meeting.2/15/2018: The MWG approved RR272 (NDVER to DVER Conversion) during the February 6th MWG meeting.

In Progress Erin Cathey The MMU recommends SPP continue discussions to transition NDVERs to DVER status and thereby lessen the negative impact of such resources on the market.

317 MWG/SPC/MOPC

01/19/17 ARR/TSR FIRM - Inability to Hedge as Expected

MOPC AI #276

3/17/2017: Charles Cates reviewed TCR/TSR process differences and options for changes at the February 2017 MWG meeting. Additional analysis will be presented at the April 2017 MWG meeting.4/17/2017: Charles Cates reviewed congestion hedging percentage analysis for the 2015-2016 TCR year with the MWG. MWG requested staff update the congestion hedging percentage analysis by asset owner.5/17/2017: Debbie James advised the MWG that staff performed the congestion hedging % analysis by AO, and the results did not represent the original intent of the analysis. Staff will provide the AO results to individual MPs as requested. MWG requested additional analysis be performed on awarded LTCRs and ARRs by path vs. requested for the last 12 months, excluding round 3.5/17/2017: MWG requested that staff perform an analysis on awarded LTCRs and ARRs by path versus requested for the last 12 months excluding round 3. 6/20/2017: SPP Staff will be presenting analysis on awarded LTCRs and ARRs by path versus requested for the last 12 months excluding round 3 in the July meeting. 7/13/2017: SPP Staff will provide an update during the July meeting. 9/1/2017: Charles Cates presented Understanding the Value of Counterflow Education Session, ARR/TCR State of the Market, and Proposed a ARR/TCR Feasibility Study Scope during the August MWG meeting. New action items were recorded (See AI 334 and AI 335). Staff will provide an update on the ARR/TCR Feasibility Study and discuss the possible options to address ARR infeasibility in more detail at the September meeting. 9/20/2017: Ty Mitchell and Chris Davis presented AI 334 Further Develop ARR/TCR Possible Solutions, and part1 (#1 and #2) and part 2 of AI 335 ARR Feasibility Study from August MWG meeting. 10/4/2017: Ty Mitchell will present Capacity Factor Breakpoints at the October MWG meeting. 10/24/2017: Ty Mitchell presented Capacity Factor Breakpoints, and Micha Bailey presented the final portion of the Feasibility Study at the October MWG meeting. AI 335 Feasibility Study has been closed, and two follow-ups were recorded for AI 334 Capacity Factor Breakpoints. 11/29/2017: MWG discussed remaining MWG action items. Staff provided a list of available Congestion Hedging training available via the SPP Learning Center and Richard Ross requested stakeholders complete the training and bring questions and any identified gaps in training to a future MWG meeting. Staff will develop a timeline for completing the training and future discussion and present that to the MWG during the December 13 MWG Net-Conference.1/8/2018: MWG deferred next steps discussion to February.

In Progress Debbie James Today at the Strategic Planning Committee the MWG was tasked to look further into the issues & a potential solution related to infeasible Auction Revenue Rights/Transmission Congestion Rights. As I suspect you are aware some parties have highlighted situations where they have secured long term firm transmission service which, in the past, facilitated/hedge the deliveries of power & energy from congestion on the system. However, today many of those parties find themselves securing & paying for transmission services, but having no hedge against the congestion cost on the system.

MWG was given the task; BUT it will require contributions from the expertise in planning from the Transmission Working Group. I’d like you to consider how we might best facilitate the engagement of the TWG or representatives from the TWG in these discussions.

Although there are many options and I will continue to consider the issue; an option would be to devote a specific period of time on the MWG meeting for this discussion and/or schedule time the day prior to the current MWG meetings. My objective being to focus the discussion so that TWG representatives could more easily attend the discussion in person without being burdened by a full day of MWG fun. I’m just throwing that out on the table & by the end of the day I may not even like it myself….ARR/TCR Firm – Inability to Hedge as Expected – While SPP is operating today per its Rules; the issue is one of Deliverability resulting from the Generation Interconnection process.

The SPC recommended that the MWG/MOPC consider if there is a better mechanism. Paul Malone on behalf of the MOPC and Richard Ross on behalf of the MWG agreed to take up the issue. Related to this issue are two others: Market Design Incentives and Market Implications Costing Cons mers326 MWG 07/18/17 SPP staff to determine if negative price signals are indicative of a

reliability need.9/1/2017: No Update.10/24/2017: No Update. 11/13/2017: No Update.1/8/2018: MWG requested an update for the February meeting.1/30/2018: An update will be provided during the March MWG meeting.

In Progress Erin Cathey

Working Group Action Items

329 MWG 07/18/17 Stored Energy Resource Market Design Next Steps: (a) Invenergy will consider withdrawing RR114 (b) Invenergy will consider proposing a new revision request to implement the desired design changes to facilitate additional SER participation in the Marketplace. Interested parties can contact John Fernandes, [email protected]. (c) Members can submit comments/questions/concerns to RMS about the design proposal presented to MWG on 7/17/2017. (d) MWG will prioritize the further work on the overall discussions on SER, and other MWG priorities, later as part of an overall road map/prioritization for the group.

9/20/2017: No Update.10/24/2017: An update on SER design will be provided later in the fall, likely during the December MWG.12/5/2017: The MWG will discuss the Market Design Initiatives list during the December MWG meeting which includes Stored Energy. This effort may be prioritized along with other initiatives for MWG development for the upcoming 1 - 2 year timeframe. 1/30/2018: Stored Energy market design remains on hold at this time.


339 MWG 07/18/17 SPP Staff to further review the concern and potential solutions to address the mitigated offer sync-to-min and min-to-off time cost recovery issue. SPP will consider extending the definition of Commitment Period to include start to min and min to off.

1/30/2018: No Update In Progress Erin Cathey 7/19/2017: See Attachment 26 "Startup Cost Reevaluation" in the July 2017 MWG minutes.

340 MWG 08/29/17 Per MOPC Action Item 285 - MOPC remanded RR221 back to the MWG for additional Review

9/5/2017: SPP staff will be providing an update at the October MWG meeting. 10/16/2017: Debbie James will be presenting Multi-Day Minimum Run Time possible paths forward during the October MWG meeting. 10/24/2017: Debbie James presented Multi-Day Minimum Run Time options at the October MWG meeting. The discussion will continue at the November MWG meeting. 11/13/2017: SPP staff will work on Options 1: No MWP after 24-Hour Minimum Run Time and Option 2: Binding Offer at Minimum Energy for Minimum Run Time for the January 2018 MWG meeting1/8/2018: The group reviewed additional information provided by staff on Options 1 and 2 (Option 1 - No MWP after 24-hour minimum run time, Option 2 - Binding Offer at Minimum Energy for Minimum Run Time), and an option was also proposed by OGE. An update will be provided during the February 6 MWG meeting.

In Progress Debbie James

347 MWG 01/08/18 SPP staff will provide a more detailed scope for each MWG Market Initiative which will include; 1) time commitment to design, 2) cost and complexity to implement, and 3) benefits to the SPP Market for MWG review during the February MWG meeting.

2/15/2018: SPP staff will bring requested information during the March MWG meeting. In Progress Erin Cathey

348 MWG 02/06/18 SPP staff will determine if a manual solution can be put in place to allow MPs the ability to utilize the Combined JOU logic proposed in RR266 while the systematic logic is developed and implemented. Staff will provide an update during the April MWG meeting.


MARKET WORKING GROUP MEETING Renaissance Tower, 41st floor, AEP – Dallas, TX February 6th, 2018 – 8:15 a.m. – 6:00 p.m. CPT

February 7th, 2018 – 8:15 a.m. – 12:00 p.m. CPT

Motions Agenda Item 2a – Consent Agenda Motion: Michael Massery (AECC) motioned to approve the consent agenda. Jack Madden (ETEC/NTEC) provided the second. Motion carried unanimously. Agenda Item 4a – RR266 JOU Combined Single Resource Modeling post Settlement Share Allocation IA – With Settlement System Motion: Jim Flucke (KCPL) motioned to approve RR266 (JOU Combined Single Resource Modeling post Settlement Share) Option 1 Impact Analysis with a High rank. Cliff Franklin (WR) provided the second. Motioned carried with five oppositions from Kevin Galke (CUS), Valerie Weigel (Basin), Rich Yanovich (OPPD), Shawn McBroom (OGE) and Richard Ross (AEP) and one abstention from Carrie Dixon (Xcel). Agenda Item 5 – RR273 Market Settlements RNU Rounding Motion: Kevin Galke (CUS) motioned to approve RR273 (Market Settlements RNU Rounding). Valerie Weigel (Basin) provided the second. Motion carried unanimously. Agenda Item 8 – NDVER to DVER Conversion Motion: Matt Moore (GSEC) motioned to approve RR272 (NDVER to DVER Conversion), Lee Anderson (LES) provided the second. The motion was tabled. Motion: John Varnell (Tenaska) motioned to table the motion to approve RR272 (NDVER to DVER Conversion), Cliff Franklin (WR) provided the second. Motion carried with three oppositions from Lee Anderson (LES), Richard Ross (AEP), and Matt Moore (GSEC) and three abstentions from Shawn McBroom (OGE), Shawn Geil (KEPCO), and Aaron Rome (Midwest). Motion: Matt More (GSEC) motioned to approve RR272 (NDVER to DVER Conversion) as amended via a Friendly Amendment by Carrie Dixon (Xcel). The Friendly Amendment did not receive any opposition from the group. Lee Anderson (LES) provided the second. Motion carried with seven oppositions from Shawn Geil (KEPCO), Cliff Franklin (WR), Ron Thompson (NPPD), John Varnell (Tenaska), Rick Yanovich (OPPD), Michael Massery (AECC) and Jim Flucke (KCPL), and one abstention from Kevin Galke (CUS). Agenda Item 10 – RR270 OCRTF Revisions to Operating Criteria Appendices Motion: Shawn McBroom (OGE) motioned to approve RR270 (OCRTF Revisions to Operating Criteria Appendices). Ron Thompson (NPPD) provided the second. Motion carried unanimously.

Agenda Item 12 – RR252 OOME Enhancement IA Motion: Kevin Galke (CUS) motioned to approve the Impact Assessment for RR252 (OOME Enhancement) with a Medium rank. John Varnell (Tenaska) provided the second. Motioned carried unanimously.

Action Items Action Item: Staff will determine if a manual solution can be put in place to allow MPs the ability to utilize the Combined JOU logic proposed in RR266 while the systematic logic is developed and implemented. Staff will provide an update during the April MWG meeting.

Future Meetings and Topics MWG Meeting Monday, March 12th, 2018 (1:00 p.m. – 6:00 p.m., CPT) Tuesday, March 13th, 2018 (8:15 a.m. – 6:00 p.m., CPT) Wednesday, March 14th, 2018 (8:15 a.m. – 12:00 p.m., CPT)

• Technical Meter Protocol Revision Update • SPP Market Design Initiatives 2018/2019 • TCR Clean-Up • SPP Comments RR272 NDVER to DVER Conversion • TCR Process Training Plan and Schedule • ARR/TCR Process Discussion • Mountain West Transmission Group Revision Requests

MWG Meeting Monday, April 16, 2018 (1:00 p.m. – 6:00 p.m., CPT) Tuesday, April 17, 2018 (8:15 a.m. – 6:00 p.m., CPT) Wednesday, April 18, 2018 (8:15 a.m. – 12:00 p.m., CPT)

• JOU Path Forward Update • SPP Market Design Initiatives 2018/2019 • ARR/TCR Process Discussion • Mountain West Transmission Group Revision Requests • MMU Annual State of the Market • MDRA Historical Data Follow-Up

MWG Meeting Monday, May 14, 2018 (1:00 p.m. – 6:00 p.m., CPT) Tuesday, May 15, 2018 (8:15 a.m. – 6:00 p.m., CPT) Wednesday, May 16, 2018 (8:15 a.m. – 12:00 p.m., CPT)

• Mountain West Transmission Group Revision Requests Respectfully submitted, Thank you - Erin Cathey, MWG Staff Secretary

Market Working Group Meeting No. 2 February 6

Documents

Transcript of Market Working Group Meeting No. 2 February 6