Southwest Power Pool MARKET WORKING GROUP MEETING October … october 21-22... · 2019-02-08 · Minutes No. [236] Southwest Power Pool MARKET WORKING GROUP MEETING October 21-22,

Southwest Power Pool

MARKET WORKING GROUP MEETING

October 21-22, 2014

AEP Offices – Dallas, TX

• Summary of Motions • Agenda Item 4 – MPRR215 - Product Substitution Cost Calculation Richard Ross (AEP) made a motion and Ron Thompson (NPPD) seconded to approve MPRR215 with direction to SPP Staff to add conforming protocol changes to include the MW quantity bill determinant for DaRegUpforCRSubAvailHrlyAmt and RtRegUpforCRSubAvailHrlyAmt, and to make available all bill determinants related to Operating Reserve offers that are currently listed as not available on the settlement statements. The motion passed with no opposition and one abstention (Westar). Agenda Item 6.e.i. – MPRR199 – Intra-Day Mitigation Measures Clarifications Rick McCord (EDE) made a motion and Ron Thompson (NPPD) seconded to accept the RTWG modifications to MPRR199. The motion passed with no opposition and one abstention (Xcel). Agenda Item 6.e.ii. – MPRR201 – Dispute Clarification Jim Flucke (KCPL) made a motion and Ron Thompson (NPPD) seconded to accept the RTWG modifications to MPRR201. The motion passed with no opposition and no abstentions. Agenda Item 6.e.iii. – MPRR204 – Compliance and Additional Changes FERC Order 755 Jim Flucke (KCPL) made a motion and Ann Scott (Tenaska) seconded to accept the RTWG modifications to MPRR204. The motion passed with no opposition and one abstention (Xcel). Agenda Item 6.e.iv. – MPRR212 – Over-Collected Losses Design Change Bruce Walkup (AECC) made a motion and Ann Scott (Tenaska) seconded to accept the RTWG modifications to MPRR212. The motion passed with no opposition and one abstention (Xcel). Agenda Item 7b – Transitional Allocation Ann Scott (Tenaska) made a motion and Rick McCord (EDE) seconded to direct SPP Staff to draft and submit an MPRR to implement option 2 – Single Round Allocation Only. The motion passed with no opposition and four abstentions (Boston Energy, Xcel, CUS, NPPD). Agenda Item 9 – MPRR196 – SPP Comments Amber Metzker (Xcel) made a motion and Jim Flucke (KCPL) seconded to approve SPP Comments to MPRR196 as submitted. The motion passed with no opposition and no abstentions.

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October 21-22, 2014


• M I N U T E S •

Agenda Item 1 — Call to Order, Proxies, Agenda Discussion Gene Anderson (OMPA) called the meeting to order at 8:15 a.m. The attendance was recorded and proxies were announced (Attachment 1 – MWG Attendance October 21-22 2014). No members were represented by proxy.

The group reviewed the agenda (Attachment 2—MWG Agenda for October 21-22 2014) and agreed to some changes in agenda order to accommodate presenters and audience. Agenda Item 2a and 2b — Minutes Approval Gene Anderson (OMPA) asked for feedback on the minutes from the MWG September 23-24 2014 meeting (Attachment 3a - MWG Sep 23-24 2014 Minutes), and the MWG September 29 2014 (Attachment 3b - MWG Sep 29 2014 Minutes). No changes were made and the minutes were deemed approved as posted.

Agenda Item 3 — MOPC MPRR Schedule Micha Bailey (SPP) presented reminded the group of dates for MPRRs for January MOPC Agenda Item 4 — MPRR215 – Product Substitution Debbie James (SPP) introduced MPRR215 (Attachment 5 - MPRR 215 Recommendation Report), which ensures that, for operational deployment and settlement purposes, each Operating Reserve product is linked to its respective Operating Reserve requirement such that the reported MWs for use in deployment and settlement do not exceed the requirements. This MPRR is to make it clear in the Protocols by changing the settlement calculation, but contains no changes to the original intent of the design, which is that Settlement should reflect the substituted product. Debbie also informed that the group that this correction does not include a resettlement. Monty Baugh (SPP) explained further that resettlement is not needed because the Marketplace implementation was done according to what’s in the current Protocols; it’s just that the settlement calculation in the Protocols was wrong all along and now needs to be fixed with this MPRR. The MWG agreed with Staff’s decision that no resettlement is needed. During the MPRR review, the MWG requested additional changes to separate out the Day-Ahead and Real-Time Regulation Up for Contingency Reserve Substitution MW Quantity. This will allow the MPs to see the amount of MWs that were substituted. The MWG also added Operating Reserve back onto the Settlement Statement. Richard Ross (AEP) made a motion and Ron Thompson (NPPD) seconded to approve MPRR215 with direction to SPP Staff to add conforming protocol changes to

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include the MW quantity bill determinant for DaRegUpforCRSubAvailHrlyAmt and RtRegUpforCRSubAvailHrlyAmt, and to make available all bill determinants related to Operating Reserve offers that are currently listed as not available on the settlement statements. The motion passed with no opposition and one abstention (Westar).

Agenda Item 5 — Prioritization of MWG Initiatives Debbie James (SPP) led a discussion on current Market Design staff and MWG initiatives (Attachment 6 - MWG Initiatives_102114_MWG), and asked the group for feedback on prioritization of the items, especially those items with a ranking of “high”. Gene suggests that MPs with issues in the Market to bring a proposal to MWG and let the group help them decide if it is something that we need to assign resources to and for the group to give guidance to the presenter about whether or not to go forward with an MPRR. There was much discussion on how to request items that do not need language changes and the suggestion was made to put those items into an MPRR form for now – even though it’s not a protocol change – just so it has a channel to go through in the stakeholder process. Debbie asked for direction the group on ensuring there is nothing missing from the list and that SPP Staff is working on items that the Stakeholders feel are the highest priority items. The first step is to make sure the list contains all items to be ranked, and then go through a ranking process. It was decided that SPP Staff will send this list to MWG members and give them until COB on 10/31/14 to add items to the list. Then, Staff will compile a final master list, and send it back out for ranking by 11/7/14. Agenda Item 06a — Working Group/Committee Updates: MOPC Gene Anderson (OMPA) delivered an update from the MOPC meeting on October 14-14 in Little Rock, Arkansas, which included a status on the following MPRRs: 1) MPRR196 – MOPC took no action on this MPRR, pending an additional language correction needed by SPP Staff, which will be reviewed later on the MWG agenda, item number 9; 2) MPRR197 (VOM Cost Clarification) – MOPC sent this MPRR back to the Working Groups to develop Tariff language and will a special MOPC conference call in early December to review the Tariff additions and to decide the next actions on MPRR197; 3) MPRR198 – MOPC took no action and therefore the MWG recommendation died there; 4) MPRR212 – MOPC approved this MPRR; 5) MPRR208 – MOPC directed SPP Staff to bring this MPRR back to MOPC in January for a MOPC discussion on where the Revision Request process definition belongs and with a request in the meantime for SPP Staff to research the need to possibly add some Working Groups to the tracking path. Gene also reported that the MWG recommendation for Enhanced Combined Cycle (ECC) was rejected and a new recommendation was proposed and approved by MOPC to resume work again on ECC in the fourth quarter 2015 for projected go-live in March 2017.

Agenda Item 06b — Working Group/Committee Updates: Quick-Start Resource Sub Group Gay Anthony (SPP) reported progress and status from the Quick-Start Resource (QSR) Sub-Group meeting so far, and Carrie Simpson (SPP) presented and discussed proposed QSR design changes from

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the Sub-Group (Attachment 7 - QSR Logic Enhancements MWG October 2014). One of the proposed items in the presentation is a “Quick Reliability Unit Commitment” (QRUC), which proposes a RUC study window of 2 hours or less and could include intra-hour commitments. This would make for RUC studies and commitment closer to real-time and including real-time pricing, which could benefit QSRs and other resources as well. The general consensus of the MWG is to move forward with the QRUC with direction to SPP Staff to bring forward more information and details on the design soon. Any other proposed changes to QSR logic from the Sub-Group would now need to be brought forth via the MPRR process, and therefore the QSR Sub-Group will now dissolve. Agenda Item 06c — Working Group/Committee Updates: Seams Steering Committee Casey Cathey (SPP) and David Kelley (SPP) delivered an update from the Seams Steering Committee, particularly to inform the MWG of proposed SPP-MISO JOA language being submitted as part of the SPP reply comments to the recent Market-to-Market (M2M) technical conference (Attachment 8 - SPP-MISO JOA M2M Language Proposal Rev3-4_final 10212014). These comments are regarding the timing of outages related to temporary flowgates. Casey reported that M2M will go live in March 2015 without these proposed changes, so that SPP can keep working with MISO on the details. David reported that there are other issues regarding outages in MISO and SPP that need to be and will continued to be looked at further.

Agenda Item 06d — Working Group/Committee Updates: MOTF-2014 Update Amber Metzker (Xcel) delivered an update from the MOTF-2014 meeting on October 20, 2014, which mainly included information on MPRRs 197 and 213. Amber reminded the group that the MOPC did not take any action on MPRR197 and the MOPC will hold a special conference call in early December to discuss it further. She reported that the MOTF-2014 members concluded that since they already voted on MPRR197, that the group did not need to take any more action on it. It would be up to the MWG to decide if MPRR197 is to move forward or not. She also reported that the MOTF-2014 did recommend approval of MPRR213 to the MWG, with direction to Staff to make some additions to the VOM costs table. Agenda Item 06e — Working Group/Committee Updates: RTWG Modification of MPRRs • 06e(i) – MPRR199 Intra-Day Mitigation Measures Clarifications: Micha Bailey (SPP) presented the

RTWG modifications to MPRR199 (Attachment 9 - MPRR 199 Recommendation Report). The SPP

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MMU commented that the RTWG modifications are not recommended by the MMU because their changes removed some section references that may diminish the enforceability of the Tariff.

o Rick McCord (EDE) made a motion and Ron Thompson (NPPD) seconded to accept the RTWG modifications to MPRR199. The motion passed with no opposition and one abstention (Xcel).

• 06e(ii) – MPRR201 Dispute Clarification: Micha Bailey (SPP) presented the RTWG modifications to MPRR201 (Attachment 10 - MPRR 201 Recommendation Report).

o Jim Flucke (KCPL) made a motion and Ron Thompson (NPPD) seconded to accept the RTWG modifications to MPRR201. The motion passed with no opposition and no abstentions.

• 06e(iii) – MPRR204 Compliance and Additional Changes FERC Order 755: Micha Bailey (SPP) presented the RTWG modifications to MPRR204 (Attachment 11 - MPRR 204 Recommendation Report).

o Jim Flucke (KCPL) made a motion and Ann Scott (Tenaska) seconded to accept the RTWG modifications to MPRR204. The motion passed with no opposition and one abstention (Xcel).

• 06e(iv) – MPRR212 Over-Collected Losses Design Change: Micha Bailey (SPP) presented the RTWG modifications to MPRR212 (Attachment 12 - MPRR 212 Recommendation Report).

o Bruce Walkup (AECC) made a motion and Ann Scott (Tenaska) seconded to accept the RTWG modifications to MPRR212. The motion passed with no opposition and one abstention (Xcel).

Agenda Item 07a — Congestion Hedging Reports: TCR Update Charles Cates (SPP) presented the TCR Update and answered questions from the group (Attachment 13 - TCR Update October MWG – final). Charles requested and received agreement that the TCR Update will become a quarterly update going forward and will be on the same meeting timeline as the quarterly Limit Expansion report and the 6-month funding report required by Protocols. The Limit Expansion report and the 6-month funding report are included in this month’s TCR update. After seeing the reports, there was discussion amongst the group on whether or not to take any action as allowed by the Protocols on the 6-month underfunding result of 89.8%; the Protocols state that the MWG can take action regarding flowgate ratings if the underfunding is below 90%. One opinion was suggested to wait another 6 months and see if the proposed adjustments to outage scheduling make a difference. Charles reminded the group that there are factors other than outages that contribute to under-funding, such as limit expansion and parallel flow. The group requested and an MWG action item was recorded for SPP Staff to bring analysis results to the MWG showing the breakdown of how parallel flow, outages and limit expansion contribute to TCR under-funding. In the meantime, the group will take no action at this time regarding the results of the 6-month under-funding report. Agenda Item 07b — Congestion Hedging Reports: Transitional Allocation Charles Cates (SPP) delivered a presentation on proposed options for provision of a “transitional ARR allocation” process to be used for new transmission facilities entering SPP (Attachment 14 - Transitional

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Allocation – Final). The proposed design options are intended to be generic for any future needs, but are being proposed now in order to be in time to provide for an interim ARR Allocation process that can used for implementation of the Integrated System (IS) into SPP in 2015. Charles presented several options and asked the MWG for guidance on which option he and others from SPP Staff should pursue. MWG’s direction was to pursue implementation of the single round allocation only option, and directed Staff to draft an MPRR to implement that option. A request was made and an MWG action item was recorded for SPP Staff to publicly publish the TCR models in June 2015 for the Integrated System (IS) interim allocation. Ann Scott (Tenaska) made a motion and Rick McCord (EDE) seconded to direct SPP Staff to draft and submit an MPRR to implement option 2 – Single Round Allocation Only. The motion passed with no opposition and four abstentions (Boston Energy, Xcel, CUS, NPPD). Agenda Item 08 — Outage Sub-Group Proposal Jared Greenwalt (SPP) delivered a presentation that outlines a proposal from the Outage Sub-Group (Attachment 15 - Outage Subgroup Proposal) on recommended actions regarding outage coordination, particularly related to the TCR process. The proposal included four main actions: 1) clear communication of model deadlines, including education sessions for TOPs; 2) outages less than 120 hours will not be modeled; 3) use engineering judgment for outages related to congestions hedging modeling; and 4) begin drafting SPP Criteria revisions for design requirements regarding outage submission. The MWG agreed to the components of the proposal, and the following three MWG action items were recorded to reflect the work needed to implement the components of the proposal:

o SPP Staff to lead an effort to educate TOPs on outage coordination and associated market affects, beginning with education for ORWG and possibly getting their assistance with the TOP education.

o SPP Congestion Hedging Staff to draft and present a document that outlines the congestion hedging business practices related to “engineering judgment” in congestion hedging modeling.

o Marguerite Wagner of Boston Energy Trading and Marketing will lead an effort to draft changes to SPP Criteria 12 that reflect the Outage Sub-Group’s proposal for new outage submission requirements for transmission and generation.

Agenda Item 09 —MPRR196 – SPP Comments Micha Bailey (SPP) presented the SPP Comments to MPRR196 (Attachment 16 - MPRR 196 Recommendation Report). The purpose of MPRR196 is to allow units that were cleared for Operating

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Reserves in the Day-Ahead Market to receive compensation when those units are manually deselected in Real-Time for the Operating Reserves. The MPRR196 as originally approved by MWG proposed only one deselect flag, which as was discovered since the approval would cause an unintended consequence where all or none of the products will go through the OOME calculation. The SPP Comments presented here propose to avoid this unintended consequence by creating four more flags for Regulation-Up Service, Regulation-Down Service, Spinning Reserve and Supplemental Reserve. So, if for example, Regulation-Up Service receives the flag for being manually deselected, then only Regulation-Up will go through the OOME calculations. Amber Metzker (Xcel) made a motion and Jim Flucke (KCPL) seconded to approve SPP Comments to MPRR196 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 10 —MPRR214 – Adequate Fuel Cost Recovery Rob Janssen (Dogwood) brought MPRR124 back up for discussion (Attachment 17 - MPRR 214 Adequate Fuel Cost Recovery). This MPRR proposes to allow Market Participants to recover additional fuel costs required as a result of commitment directives issued by SPP. The MP will file a dispute with SPP using the Request Management System. SPP will review the dispute and associated documents. If the dispute is granted, then SPP will allocate those revenues to the MP which include the additional fuel cost recovery via the RUC MWP charge type and run a re-settlement statement. Carrie Simpson (SPP) communicated some concerns from SPP Staff on this MPRR, some of which are captured in the SPP Comments to MPRR124 (Attachment 18 - MPRR 214 SPP Comments 9-11-2014_MWG). The SPP Staff concerns and comments include: 1) determining “commercially reasonable” is difficult; 2) Staff thinks there is limited risk in this happening because we don’t de-commit resources. 3) there are system issues with doing this; will be a lot of manual work; 4) it could possibly send a wrong incentive; takes away the incentive to work hard to sell the fuel back – if you are going to get paid for it. Some of the group proposed that language be added to say that SPP will not de-commit if it was committed in an EOP situation. Rob said he was fine with those changes and would like to hear any other thoughts or ideas that the group may want to bring. He just wants to ensure that the ideas are thoroughly discussed to make sure there are no reliability impacts. Carrie will check with SPP reliability. The general consensus of the group was to table this MPRR again pending more research by SPP Staff to give MWG Members more time to consider it. Agenda Item 11 — Day-Ahead Must Offer Evaluation Jared Greenwalt (SPP) presented a 6-month evaluation of the Day-Ahead Must Offer (Attachment 19 - Must Offer Evaluation) as MWG told MOPC it would do approximately 6 months after Marketplace go-live. The evaluation was informational only and did not propose any conclusions or actions. The MWG discussed the evaluation and what the next steps or decisions might need to be for the Day-Ahead Must Offer. The discussion included some thoughts on the topic of Physical Withholding and its possible connection or not to a Must Offer. SPP MMU stated that it considers Physical Withholding as the monitoring tool that ensures enough capacity is offered into the markets, and that it does not consider the Day-Ahead Must Offer as a monitoring tool. The MWG also discussed the current efforts of the SPP Capacity Margin Task Force and there were some comments that it’s really the Task Force that should be considering capacity issues, not the groups work on Marketplace design and the Must Offer

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functionality. An opinion was also offered that Markets with a Capacity Markets do need a must offer but SPP really does not. The group seemed to narrow the future options for the Must Offer down to 3 options: 1) stay with what we have; 2) implement a full must offer; and 3) implement a “no must offer.” The group too no action at this time and decided to continue discussions later on the next steps for Day-Ahead Must Offer. Agenda Item 12 — RTO Marketplace Update Gene Anderson (OMPA) asked the group in the interest of time to consider the RTO Marketplace as a written report and to not have SPP Staff present it during the meeting (Attachment 20 - October 2014 RTO Update). He told the group to review it on their own and submit any questions to SPP Staff. Carrie Simpson (SPP) did present analysis results on Regulation Performance that were special to report for just this month. The analysis did show some differences between reg-up and reg-down performance and there was speculation amongst the group that the differences could be because Marketplace only allows one ramp rate for regulation, instead of two ramp rates – one for up and one for down. An MPRR would need to be brought forward to change that if needed. Agenda Item 13 — MPRR211 - Self-Commit Run Time Make Whole Payment Exemption This item was tabled due to time constraints. Agenda Item 14 - MPRR210 - Sync to Min Costs in Mitigated Start-Up Offer This item was tabled due to time constraints. Agenda Item 15 — MPRR209 - Change Start-Up Offer from Daily to Hourly This item was tabled due to time constraints. Agenda Item 16 — MPRR213 – Default VOM for Mitigated Offers Amber Metzker (Xcel) presented actions and recommendations from the MOTF-2014 on MPRR213 (Attachment 21 - MPRR 213 MOTF-2014 Comments 9-19-2014), which proposes a set of default VOM costs for MPs to use in calculating VOM costs for their Mitigated Offers, and removes the current language for calculating VOM in Appendix G. Amber reported that the MOTF-2014 does recommend MWG approval of MPRR213 as modified by the MOTF-2014 on 10/20/14, and with the action item for the SPP MMU to add an additional 6 rows of default VOM costs based on number of starts and number of hours run for both types of CTs and for Combined Cycle. Gene Anderson (OMPA) reminded the group that MOPC in its discussion on MPRR197-VOM Cost Clarification did direct the MWG to bring an MPRR, whether it be MPRR197 or some other, to the special MOPC meeting in December being held for the purpose of discussing the VOM Cost issues. So, part of this discussion on MPRR213 needs to include an MWG decision on how to handle MPRR213 and MPRR197 for delivery to MOPC. There was consensus amongst most of the MWG that MPRR213 is a reasonable approach and a good start towards addressing the VOM cost issues and that the group should go forward to MOPC with it. Based on that direction,

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Gene proposed an MWG Net Conference meeting on November 10 to specifically discuss and consider approval of MPRR213 and recommendation to MOPC. In the meantime, MWG Members and other Stakeholders are encouraged to submit comments to MPRR213, including any proposed language changes related to the discussion on MPRR197 about a possible expansion or clarification on the definition of short-run marginal cost. Agenda Item 17 — MPRR207 - Staggered Start-Up Time This item was tabled due to time constraints. Agenda Item 18 — Rules for Re-Direction of Transmission Service for Pseudo-Tied Out Resources Carrie Simpson (SPP) delivered a presentation to inform the MWG of efforts currently underway to clarify the rules for re-direction of transmission service for Pseudo-Tied Out Resources in Marketplace (Attachment 22 - Re-direction of TSRs for Pseudo-Ties_v4). Carrie’s presentation included background and reminders on how re-direction works today and basically that any transmission customer can request re-direction through the SPP tariff and scheduling services, but that the rules for transmission service associated with Pseudo-Ties are different and re-direction associated with those ties has not been allow to date. MPs with Pseudo-Tied Out Resources have recently questioned why re-direction is no allowed and have requested that it be better clarified one way or the other in the SPP Tariff. Jim Sweatt (SOCO-Alabama Power) was in attendance at the MWG and has submitted comments (Attachment 23 - SOCO Comments for SPP MWG Regarding Pseudo-Tie Redirects) representing SOCO as an MP who has pseudo-tied resources and who is a proponent of being allowed to re-direct the transmission service associated with his company’s pseud-tied, and would like to see that clarified in the Tariff. Carrie explained that SPP Staff has concerns about managing the re-direction of transmission service supporting pseudo-tied out resources both in operations and in settlements due to the manual work surrounding that management. For that reason, SPP Staff proposes to allow the redirection, but to limit it to a time period that is more manageable than hourly, such as monthly or weekly, which also better aligns with the static nature of the pseudo-tie. The MWG agreed with Staff’s proposal as presented by Carrie. The next steps are for SPP Staff to draft clarifying language in the Tariff and in the Business Practices and to bring that back to the MWG for informational purposes. At this time, there does not seem to be a need for Protocol changes associated with this proposal, but SPP Staff will continue to monitor that as it moves the other language through the process. Agenda Item 19 — MMU Marketplace Update Gene Anderson (OMPA) asked the group in the interest of time to consider the MMU Marketplace Update as a written report and to not have SPP MMU Staff present it during the meeting (Attachment 24 - 201409 MWG MMU Market Update). He told the group to review it on their own and submit any questions to SPP Staff. Catherine Tyler Mooney (SPP MMU) did request to verbally point out one item in the MMU Update regarding coal deliveries (slide 24) and asked MPs to contact her if they had any questions or if they needed to discuss that item further. Agenda Item 20 — MPRR Quarterly Report This item was tabled due to time constraints.

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Agenda Item 21 — Regulatory Report Gene Anderson (OMPA) asked the group in the interest of time to consider the Regulatory Report as a written report and to not have SPP Staff present it during the meeting (Attachment 25 - 2014 10 Regulatory Report to MWG). He told the group to review it on their own and submit any questions to SPP Staff. Marisa Choate (SPP) did request to verbally point out one item from that report regarding SPP’s filing of a motion for deferral for the 2nd post go live filing on 7/10/14. Marisa reported that TRR140 will satisfy the changes that FERC directed, but that Staff just needed more time to get TRR140 through the SPP stakeholder process, and that is the reason for the deferral request. Marisa also pointed out that separate filings were made for four MPRRs in order to keep questions on one filing from possibly holding up the others. Agenda Item 22 — New Settlement Location Type This item was tabled by the presenter. Agenda Item 23 — MPRR181 - Mirrored JOU Share Option This item was tabled due to time constraints. Agenda Item 24 - Review of Motions, Action Items and Future Meetings

Motions: Agenda Item 4 – MPRR215 - Product Substitution Cost Calculation Richard Ross (AEP) made a motion and Ron Thompson (NPPD) seconded to approve MPRR215 with direction to SPP Staff to add conforming protocol changes to include the MW quantity bill determinant for DaRegUpforCRSubAvailHrlyAmt and RtRegUpforCRSubAvailHrlyAmt, and to make available all bill determinants related to Operating Reserve offers that are currently listed as not available on the settlement statements. The motion passed with no opposition and one abstention (Westar). Agenda Item 6.e.i. – MPRR199 – Intra-Day Mitigation Measures Clarifications Rick McCord (EDE) made a motion and Ron Thompson (NPPD) seconded to accept the RTWG modifications to MPRR199. The motion passed with no opposition and one abstention (Xcel). Agenda Item 6.e.ii. – MPRR201 – Dispute Clarification Jim Flucke (KCPL) made a motion and Ron Thompson (NPPD) seconded to accept the RTWG modifications to MPRR201. The motion passed with no opposition and no abstentions. Agenda Item 6.e.iii. – MPRR204 – Compliance and Additional Changes FERC Order 755 Jim Flucke (KCPL) made a motion and Ann Scott (Tenaska) seconded to accept the RTWG modifications to MPRR204. The motion passed with no opposition and one abstention (Xcel). Agenda Item 6.e.iv. – MPRR212 – Over-Collected Losses Design Change Bruce Walkup (AECC) made a motion and Ann Scott (Tenaska) seconded to accept the RTWG modifications to MPRR212. The motion passed with no opposition and one abstention (Xcel).

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Agenda Item 7b – Transitional Allocation Ann Scott (Tenaska) made a motion and Rick McCord (EDE) seconded to direct SPP Staff to draft and submit an MPRR to implement option 2 – Single Round Allocation Only. The motion passed with no opposition and four abstentions (Boston Energy, Xcel, CUS, NPPD). Agenda Item 9 – MPRR196 – SPP Comments Amber Metzker (Xcel) made a motion and Jim Flucke (KCPL) seconded to approve SPP Comments to MPRR196 as submitted. The motion passed with no opposition and no abstentions. Action Items:

• From the TCR Update agenda item, SPP Staff to bring analysis results showing the breakdown of the how parallel flow, outages and limit expansion contribute to TCR under-funding.

• From the Congestion Hedging Transitional Allocation agenda item, SPP Staff to publicly publish

the TCR models in June 2015 for the Integrated System (IS) interim allocation.

• From the Outage Sub-Group Proposal agenda item, SPP Staff to lead an effort to educate TOPs

on outage coordination and associated market affects, beginning with education for ORWG and possibly getting their assistance with the TOP education.

• From the Outage Sub-Group Proposal agenda item, SPP Congestion Hedging Staff to draft and present a document that outlines the congestion hedging business practices related to “engineering judgment” in congestion hedging modeling.

• From the Outage Sub-Group Proposal agenda item, Marguerite Wagner of Boston Energy Trading and Marketing will lead an effort to draft changes to SPP Criteria 12 that reflect the Outage Sub-Group’s proposal for new outage submission requirements for transmission and generation.

Future Meetings: November 10, 2014 (1:00 p.m. – 4:00 p.m.) Location: Net Conference November 18, 2014 (8:15 a.m. – 6:00 p.m.) November 19, 2014 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor December 16, 2014 (8:15 a.m. – 6:00 p.m.) December 17, 2014 (8:15 a.m. – 12:00 p.m.)

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Location: AEP Office – Dallas, TX Room: 8th Floor Agenda Item 25 — MPRR186 - Mitigated Offer – External Dynamic Resource This item was tabled. Agenda Item 26 — MPRR126 - Real-Time Regulation Make Whole Payment This item was tabled.

Agenda Item 27 – Adjournment Gene Anderson adjourned the meeting at 11:55 a.m.

Respectfully Submitted, Debbie James Secretary

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Attachments Attachment 1 - MWG Attendance October 21-22 2014 Attachment 2 - MWG Agenda for October 21-22 2014 Attachment 3a - MWG Sep 23-24 2014 Minutes Attachment 3b - MWG Sep 29 2014 Minutes Attachment 4 - 2015 MOPC MPRR Schedule Attachment 5 - MPRR 215 Recommendation Report Attachment 6 - MWG Initiatives_102114_MWG Attachment 7 - QSR Logic Enhancements MWG October 2014 Attachment 8 - SPP-MISO JOA M2M Language Proposal Rev3-4_final 10212014 Attachment 9 - MPRR 199 Recommendation Report Attachment 10 - MPRR 201 Recommendation Report Attachment 11 - MPRR 204 Recommendation Report Attachment 12 - MPRR 212 Recommendation Report Attachment 13 - TCR Update October MWG – final Attachment 14 - Transitional Allocation – Final Attachment 15 - Outage Subgroup Proposal Attachment 16 - MPRR 196 Recommendation Report Attachment 17 - MPRR 214 Adequate Fuel Cost Recovery Attachment 18 - MPRR 214 SPP Comments 9-11-2014_MWG Attachment 19 - Must Offer Evaluation Attachment 20 - October 2014 RTO Update Attachment 21 - MPRR 213 MOTF-2014 Comments 9-19-2014 Attachment 22 - Re-direction of TSRs for Pseudo-Ties_v4 Attachment 23 - SOCO Comments for SPP MWG Regarding Pseudo-Tie Redirects Attachment 24 - 201409 MWG MMU Market Update Attachment 25 - 2014 10 Regulatory Report to MWG

X = In PersonP = By Phone* = By Proxy

Day 1 Day 2 Full Name Company E-mail Business PhoneP P Richard Ross (Chair) AEP [email protected] (918) 382-9285X X Gene Anderson (V-Chair) OMPA [email protected] (405) 645-2280P P Aaron Rome Midwest Energy [email protected] (785) 625-1431X X Amber Metzker Xcel Energy [email protected] (303) 571-6202X X Ann Scott Tenaska [email protected] (817) 462-1514P P Bruce Walkup AECC [email protected] (501) 570-2639X Chris Lyons Exelon [email protected] (410) 470-2465X X Cliff Franklin Westar [email protected] (785) 213-9722X X Debbie James (Sec) SPP [email protected] (501) 614-3577X X Jim Flucke KCPL [email protected] (816) 701-7836X X Lee Anderson LES [email protected] (402) 467-7591X X Marguerite Wagner Boston Energy Trading & Marketing [email protected] (617) 529-3127X X Matt Johnson City Utilities, Springfield [email protected] (904) 360-1460P P Matt Moore Golden Spread Electric Coop [email protected] (806) 379-7766P P Neal Daney KMEA [email protected] (913) 660-0242X X Rick McCord EDE [email protected] (417) 625-5129P P Rick Yanovich OPPD [email protected] (402) 514-1031X X Ron Thompson NPPD [email protected] (402) 845-5202X X Shawn McBroom OGE [email protected] (405) 239-0255

P Allison Wahrenberger Enel [email protected] Bill Nolte SECI [email protected] (420) 272-5458P P Billy Cutsor MEAN [email protected]

P Brenda Fricano SPP [email protected] Brent Hendrickson Nexant [email protected] (404) 276-9008

P Brian Moix SPP [email protected] X Carrie Simpson SPP [email protected] (501) 688-1757X P Casey Cathey SPP [email protected] (501) 614-3267X X Catherine Mooney SPP [email protected] X Chandler Brown SECI [email protected] Charles Cates SPP [email protected] Chris Winburn IPL [email protected] David Kelley SPP [email protected] (501) 688-1671

P David Marshall Southernco [email protected] Eileen O'grady Argus [email protected]

P P Eric Alexander GRDA [email protected] (918) 824-7245P Farrokh Rahimi OATI [email protected] (612) 360-1654P Gary Cate SPP [email protected] X Gay Anthony SPP [email protected] (501) 688-1722P P Hailey McKewon GRDA [email protected] P Harshikesh Panchal XO Energy [email protected] X Jack Madden GDA Associates [email protected]

Market Working Group10/21 - 10/22/2014

Face to Face Conference

mailto:[email protected]





































X James Sweatt Southernco [email protected] P Jan Bagnall SWPA [email protected] X Jared Greenwalt SPP [email protected] Jason Doerr Basin Electric Power Co. [email protected] (701) 557-5388P P Jason Russell SPP [email protected] Jay Caspary SPP [email protected]

P Jay Goldman BETM [email protected] Jeff Riles Enel [email protected] Jeremy Verzosa SPP [email protected]

P P Jerry Tielke MREnergy [email protected] P Jill Jones NMPP [email protected] Jim Jacoby AEP [email protected] JJ Guo AEP [email protected] P Jodi Woods SPP [email protected] X Joe Ghormley SPP [email protected] P Joey Schrepel BEPC [email protected] P John Hyatt SPP [email protected] John Stephens City Utilities [email protected] (417) 831-8470P P John Tennyson City Utilities [email protected] X John Varnell Tenaska [email protected] (817) 462-1037P P Julie Gerush SPP [email protected] Kari Hollandsworth GSEC [email protected] Ken Rutter Basin Electric Power Co. [email protected] (701) 557-5390P Kevin Kingsley MDU [email protected] P Kevin Warren SPP [email protected] X Kim Sullivan WFEC [email protected]

Kimberly Badenhop BEPC [email protected] Lisa Flowers-Davis BEPC [email protected]

P Lyle Larson Balch [email protected] P Marisa Choate SPP [email protected] (501) 688-1707P Mark Trumble OPPD [email protected] X Micha Bailey SPP [email protected] (501) 688-2522P P Michael Daly SPP [email protected] X Michael Erbrick MICS [email protected] (281) 687-0609P P Mike Grimes EDP Renewables [email protected] (713) 265-0316X P Mike Mushrush OMPA [email protected] X Monty Baugh SPP [email protected] P Natasha Brown SPP [email protected] Nick Parker SPP [email protected] (501) 614-3574P Nicole Wagner SPP [email protected] Peter Tucker SPP [email protected] Raleigh Mohr SPP [email protected] P Randy Root GRDA [email protected] Rashmi Karnik Hartigen [email protected] P Rebecca Atkins MPUA [email protected]

P Richard Dillon SPP [email protected] (501) 614-3228










































P P Robert Janssen Kelson Energy [email protected] Robert Pick NPPD [email protected]

X X Robert Safuto Customized Energy Solutions [email protected] (917) 446-2579P P Robert Stillwell IPL [email protected] (813) 325-7482X X Roy True Aces Power Marketing (APM) [email protected] (317) 695-4146P P Russell Quattlebaum SPP [email protected] Ryan Turner CUS [email protected] X Sam Ellis SPP [email protected] P Sarah Pettus Wind Coalition [email protected] Seth Cochran DC Energy [email protected] (512) 971-8767X X Shawn Geil KEPCo [email protected] X Shawnee Claiborn-Pinto PUCT [email protected] (512) 936-7388P P Sherry Hamilton SPP [email protected]

P Steve Gaw Wind Capital Group [email protected] (573) 645-0727P P Terry Gates AEP [email protected] (614) 583-6574P P Terry Wright EDE [email protected] P Tim Hooker GRDA [email protected] Ty Mitchell SPP [email protected] P Tyson Boatler GSEC [email protected] Vince Vandaveer CUS [email protected] X Walt Shumate Shumate & Associates [email protected] (512) 496-7704P P Wayne Camp Accenture [email protected] (856) 204-0298X X Wendell Drost Alstom [email protected] (318)348-0014P Will Tootle SPP [email protected] 83


























October 21-22, 2014

AEP Office – Dallas, TX

• A G E N D A •

Day 1 – 8:15 a.m. – 6:00 p.m.

1. Call to Order, Proxies, Agenda Discussion ....................................................................... Gene Anderson

2. Minutes Approval ............................................................................................................ Gene Anderson

a. September 23-24, 2014

b. September 29, 2014

3. MOPC MPRR Schedule ......................................................................................................... Micha Bailey

4. MPRR215-Product Substitution Cost Calculation (approval item) ....................................... Micha Bailey

5. Prioritization of MWG Initiatives ....................................................................................... Debbie James

6. Working Group/Committee Updates .............................................................................. Gene Anderson

a. MOPC ............................................................................................................. Gene Anderson

b. Quick-Start Resource Sub-Group ....................................................................... Gay Anthony

c. Seams Steering Committee ................................................................................ David Kelley

d. MOTF-2014 Update ....................................................................................... Amber Metzker

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

e. RTWG modification of MPRRs (approval item) .................................................. Micha Bailey

i. MPRR 199 Intra-Day Mitigation Measures Clarifications

ii. MPRR 201 Dispute Clarification

iii. MPRR 204 Compliance and Additional Changes FERC Order 755

iv. MPRR 212 Over Collected Losses Design Change

7. Congestion Hedging Reports .............................................................................................. Charles Cates

a. TCR Update ....................................................................................................... Charles Cates

b. Transitional Allocation ...................................................................................... Charles Cates

8. Outage Sub-Group Proposal ........................................................................................... Jared Greenwalt

9. MPRR196 - SPP Comments (approval item) ......................................................................... Micha Bailey

Lunch – 12:00 p.m. – 1:00 p.m.

10. MPRR214 - Adequate Fuel Cost Recovery (approval item) .................................................. Rob Janssen

11. Day-Ahead Must Offer Evaluation .................................................................................. Jared Greenwalt

12. RTO Marketplace Update .................................................................................................... Casey Cathey

13. MPRR211 - Self-Commit Run Time Make Whole Payment Exemption (approval item) .......... Jim Flucke

14. MPRR210 - Sync to Min Costs in Mitigated Start-Up Offer (approval item) ............................ Jim Flucke

15. MPRR209 - Change Start-Up Offer from Daily to Hourly (approval item) ............................... Jim Flucke

16. MPRR213 - Default VOM for Mitigated Offers (approval item) ................................................. Roy True

17. MPRR207 - Staggered Start-Up Time (approval item) .... Jim Flucke/Clifford Franklin/Shawn McBroom



Day 2 – 8:15 a.m. – 12:00 p.m.

18. Rules for Re-Direction of Transmission Service for Pseudo-Tied Out Resources ............. Carrie Simpson

19. MMU Marketplace Update ...................................................................................................... SPP MMU

20. MPRR Quarterly Report ........................................................................................................ Micha Bailey

21. Regulatory Report ............................................................................................................. Marisa Choate

22. New Settlement Location Type ......................................................................................... Zachary Sharp

23. MPRR181 - Mirrored JOU Share Option ................................................... Jared Greenwalt/Cliff Franklin

24. Review of Motions, Action Items and Future Meetings ...................................................... Gay Anthony

25. MPRR186 - Mitigated Offer – External Dynamic Resource (table) ................................. Amber Metzker

26. MPRR126 - Real-Time Regulation Make Whole Payment (table) ...................................... Dave Erickson

27. Adjournment ................................................................................................................... Gene Anderson





September 23-24, 2014


• Summary of Motions • Agenda Item 6 – Over-Collected Losses (OCL) John Varnell (Tenaska) made a motion and Bruce Walkup (AECC) seconded to direct SPP Staff to develop protocol and tariff language in MPRR212 to implement an allocation based on RTBM withdrawal ratio share and to evaluate including in the language the exclusion of the BSSs from the allocation of OCL. The motion passed with no opposition and no abstentions. Agenda Item 7 - MPRR214 - Adequate Fuel Cost Recovery (expedite) Matt Moore (GSEC) made a motion and Jim Flucke (KCPL) seconded to expedite MPRR214. The motion passed with no opposition and no abstentions. Agenda Item 8 – MPRR196 – SPP Comments and Impact Analysis Amber Metzer (Xcel) made a motion and Matt Moore (GSEC) seconded to amend the MPRR196 recommendation report to incorporate the 9/16/14 SPP comments as submitted, and to accept the MPRR196 impact analysis with a ranking of high. The motion passed with no opposition and no abstentions. Agenda Item 10 – MPRR203 - Market Participant Funded Incremental Upgrades Marguerite Wagner (Boston Energy) made a motion and John Varnell (Tenaska) seconded to approve MPRR203 as submitted. The motion failed with 10 oppositions (OPPD, Midwest, AEP, OGE, GSEC, KCPL, Xcel, CUS, OMPA, EDE) and four abstentions (Tenaska, LES, Westar, AECC). Agenda Item 11 – Enhanced Combined Cycle Cost Benefit Analysis Matt Moore (GSEC) made a motion and Shawn McBroom (OGE) seconded to approve MWG recommendations to MOPC. The motion passed with 6 votes in favor (WR, OGE, TNSK, KCPL, GSEC, EDE), 2 oppositions (AEP, Xcel), and nine abstentions (Boston, OPPD, NPPD, Midwest, OMPA, CUS, AECC, KMEA, LES). Agenda Item 27 - TRR140 - TSR Modification for Resource Specific Source Points Ron Thompson (NPPD) made a motion and John Varnell (Tenaska) seconded to approve TRR140 as modified. The motion passed with no opposition and two abstentions (Xcel, Boston Energy T&M).

Minutes No. [234]



September 23-24, 2014



Agenda Item 1 — Call to Order, Proxies, Agenda Discussion Gene Anderson (OMPA) called the meeting to order at 8:15 a.m. The attendance was recorded and proxies were announced (Attachment 1 – MWG Attendance September 23-24 2014). The following members were represented by proxy:

• Standing Proxy: John Varnell (Tenaska) for Ann Scott (Tenaska) (Attachment 1a - Ann Scott Proxy)

• Terry Gates (AEP) for Richard Ross (AEP) (Attachment 1b - Richard Ross Proxy) • Terry Wright (EDE) for Rick McCord (EDE) – on 9.24.14 only (Attachment 1c - Rick

McCord Proxy)

The group reviewed the agenda (Attachment 2—MWG Agenda for September 23-24 2014) and agreed to some changes in agenda order to accommodate presenters and audience. Agenda Item 2a— Minutes Approval Gene Anderson (OMPA) asked for feedback on the minutes from the MWG August 19-20 2014 meeting (Attachment 3a - MWG Aug 19-20 2014 Minutes), and the MWG August 22 2014 (Attachment 3b - MWG Aug 22 2014 Minutes). No changes were made and the minutes were deemed approved as posted. Agenda Item 3 — Working Group/Committee Updates

a. MWG Annual Charter Review – Debbie James (SPP) led the group in the required annual review of the MWG Charter (Attachment 4 - MWG Charter 012913), and no changes were made. Rob Janssen (MOPC Chair) commented that one of the key items under review this year is making sure that the working groups have equal representation amongst Transmission Owners and Transmission Customers. He also noted that some groups have had difficulty getting a quorum, but MWG does not have that issue.

b. MOTF-2014 – Amber Metzker (Xcel) provided an update from the MOTF-2014 and reported that

the Task Force will continue to meet through the end of the year as stated in the Task Force charter, after which they will review the Charter and may extend the Task Force.

c. GECTF – Amber Metzker (Xcel) provided an update from the Gas Electric Coordination Task Force (GECTF) and reminded the group of the comment period through 11/28/14 on the “strawman” proposal for changes to the market timeline in coordination with the gas schedule

Minutes No. [234]

timeline. This proposal will be presented to the MOPC in October, 2014, and the SPP RTO will have to respond to the FERC NOPR with additional details in the 1st quarter of 2015. A question was raised and the group discussed as to whether or not the SPP-proposed gas-electric timeline is the same as those being proposed by all RTOs, and Amber replied that no, each RTO has a different proposal, just as they currently have different market timelines today.

Agenda Item 4 — Quarterly MPRR Update Micha Bailey (SPP) presented the Quarterly MPRR report (Attachment 5 - MPRR - Quarterly Report) and pointed out new enhancements to the report to show schedule information for FERC filings and for software implementation associated with MPRRs. The report also now shows a running total for approved MPRRs of their cost to implement, according to the approved Impact Analysis for each MPRR. Debbie James (SPP) reported that SPP Staff is scheduling a meeting with representatives from ERCOT by the end of the year to benchmark their prioritization processes. SPP Staff hopes to use this and other research and information to define the best process for SPP and to continue to provide more and better information on the MPRRs. Agenda Item 5 — MPRR194 - Estimated Software/Tariff Implementation Schedule Debbie James (SPP) updated the group on the implementation schedule for MPRR194 and reported that MPRR194 will be implemented as soon as possible next year, but hopefully in the first quarter of next year. The purpose of MPRR194 is to relax the mitigation conduct test threshold for manually committed resources and to restrict the presumption of local market power for manual commitments to only those commitments for local reliability. Another change associated with MPRR194 that will likely happen as early as first quarter of next year is to re-categorize manual commitments so that operator overrides for staggering starts for Resources are not considered manual commitments and are therefore not subject to the tighter mitigation threshold of 10%. Agenda Item 6 — MPRR212 – Over Collected Losses Design Change Wayne Camp (SPP), Micha Bailey (SPP), and Jared Greenwalt (SPP) presented information on MPRR212 (Attachment 6 - MPRR 212 Over Collected Losses Design Change), which originally proposed to net together Day-Ahead and Real-Time monies for Over-Collected Losses (OCL) and then allocate it out based on Day-Ahead cleared withdrawals. The group was presented with examples of this proposed new OCL design with comparisons to other possible options (Attachment 7 - MPRR212 Presentation 9-8-2014). An Impact Analysis for MPRR212 was also presented (Attachment 8 - MPRR 212 Impact Analysis), which reported an estimate of $42,300 and 7 months to implement the changes, with a ROM equal to +/- 50%. After much discussion and analysis of the examples, the group motioned and approved a plan to develop Protocol and Tariff language for a design change that still nets together Day-Ahead and Real-Time monies for Over-Collected Losses (OCL), but allocates it according to Real-Time withdrawals. The group also requested that Bilateral Settlement Schedules (BSSs) be excluded from allocation of OCL, but SPP Staff ended up reporting later that the removal of BSSs was not feasible due to the GFA Carve Out functionality and its use of BSSs. The group will be presented with the final MPRR in the next MWG meeting on 9/29/14. John Varnell (Tenaska) made a motion and Bruce Walkup (AECC) seconded to direct SPP Staff to develop protocol and tariff language in MPRR212 to implement an allocation based on RTBM withdrawal ratio share and to evaluate including in the language the exclusion of the BSSs from the allocation of OCL. The motion passed with no opposition and no abstentions.

Minutes No. [234]

Agenda Item 7 — MPRR214 - Adequate Fuel Cost Recovery (expedite) Rob Janssen (Dogwood) introduced MPRR214 (Attachment 9 - MPRR 214 Adequate Fuel Cost Recovery and Attachment 10 - MPRR 214 SPP Comments 9-11-2014), which proposes to allow Market Participants to recover additional fuel costs required as a result of commitment directives issued by SPP. According to the proposal, the MP would file a dispute with SPP using the Request Management System. SPP will review the dispute and associated documents. If the dispute is granted, then SPP will allocate those revenues to the MP which include the additional fuel cost recovery via the RUC MWP charge type and run a re-settlement statement. Rob is requesting expedited treatment of MPRR214 due to the need for this design change prior to Winter operations, in which case it must be reviewed for possible approval at the October 2014 MOPC meeting. Matt Moore (GSEC) made a motion and Jim Flucke (KCPL) seconded to expedite MPRR214. The motion passed with no opposition and no abstentions. After approval of the expedited treatment, the group discussed MPRR214 and some concerns were raised about the lack of checks and balances to prevent unwarranted payments. The group also discussed some alternate solutions such as setting policy so that SPP must run units to burn the excess fuel associated with the situations described. MMU voiced concerns that SPP Staff is not in a good position to validate the payment and the reason given by an MP/AO through the dispute filing for the payment, and that the Market Participant is in the best position to bear the market risk of fuel procurement. In the end, the group decided it was not ready to vote on MPRR214 quite yet and tabled it to a future MWG meeting. Agenda Item 8 — MPRR196 - SPP Comments and Impact Analysis Micha Bailey (SPP) and Jared Greenwalt (SPP) presented SPP Comments and the Impact Analysis for MPRR196 (Attachment 11 - MPRR 196 Recommendation Report), which adds another provision into the protocols and tariff language allowing Make Whole Payments to occur when regulation is manually moved between the Day Ahead Market Clearing and the Real Time Actual causing a Market Participant to be financially harmed. The SPP Comments add language for the actual flag that would the trigger the calculation in Settlements for the compensation. The MPRR196 Impact Analysis reported a cost of $51,131 and duration of 7 months, both with a ROM of +/- 50%. Amber Metzer (Xcel) made a motion and Matt Moore (GSEC) seconded to amend the MPRR196 recommendation report to incorporate the 9/16/14 SPP comments as submitted, and to accept the MPRR196 impact analysis with a ranking of high. The motion passed with no opposition and no abstentions. Agenda Item 9 — MPRR199 - Intra-Day Mitigation Measures Clarifications This item was tabled due to time constraints. Agenda Item 10 — MPRR203 - Market Participant Funded Incremental Upgrades Marguerite Wagner (Boston Energy T&M) brought MPRR203 back up for discussion (Attachment 12 - MPRR 203 Recommendation Report). This MPRR was previously presented and discussed in the MWG meeting in August 2014. MPRR203 failed to get approval from the MWG, primarily because, as stated by some MWG Members, there is currently an intervention at FERC on the SPP LTCR design that proposes a construct similar to the one proposed in MPRR203, and because there is a feeling amongst the group that the MPRR lacks clarity on how the proposed design would work with the current SPP Tariff, particularly regarding the Sponsored Upgrade process. Marguerite Wagner (Boston Energy) made a motion and John Varnell (Tenaska) seconded to approve MPRR203 as submitted. The motion failed with 10 oppositions (OPPD, Midwest, AEP, OGE, GSEC, KCPL, Xcel, CUS, OMPA, EDE) and four abstentions (Tenaska, LES, Westar, AECC).

Minutes No. [234]

Agenda Item 11 — Enhanced Combined Cycle Cost Benefit Analysis Debbie James (SPP) introduced this agenda item and reminded the MWG of the two action items for SPP Staff from the SPP Board of Directors (BOD) regarding the Enhanced Combined Cycle (ECC) project. One action item was to perform and report results on a “back of the envelope” cost-benefit analysis (CBA), and the second action item was to evaluate what it would take run a full-fledged CBA. Nick Parker (SPP) reported first on the methods and findings from the “back of the envelope” CBA (Attachment 13 - ECC Cost Benefit Analysis_Final). During the discussion on these results, some MWG Members and MPs concluded that this analysis doesn’t show the true benefit of ECC, while others interpreted it to show a “wash” in benefit and that there are other projects that are more important for the Marketplace than ECC. The group was reminded to consider ROI, which the informal CBA results showed to be a return on the $9+ million investment in about 2-3 years. SPP Staff was asked what it’s confidence level was for this return and Staff reported an 80% confidence level. Gene Anderson (OMPA) suggested that MWG could report to the BOD that MWG does think the ECC project valuable, based on this analysis, and should be done sooner than later, and that there are some benefits not even recognized with this analysis. A straw-poll was taken regarding Gene’s suggestion about moving forward as soon as practical, which showed roughly 11 of 18 in support of moving forward. The group then began the next step of creating the MWG Recommendation to the MOPC (Attachment 14 - MWG ECC Recommendation_draft_MWG). A vote was taken and those MWG Members in opposition noted that there are not against the ECC project being implemented, they just have concerns about its priority compared to other projects and therefore the timing of when it should be implemented, given existing resource constraints. Some of the opposition did propose and present an alternative recommendation for the group to review and consider, but in the end, the group did approve the original recommendation created during the meeting. Matt Moore (GSEC) made a motion and Shawn McBroom (OGE) seconded to approve MWG recommendations to MOPC. The motion passed with 6 votes in favor (WR, OGE, TNSK, KCPL, GSEC, EDE), 2 oppositions (AEP, Xcel), and nine abstentions (Boston, OPPD, NPPD, Midwest, OMPA, CUS, AECC, KMEA, LES). Agenda Item 12 — Hub Design Ken Rutter (Basin Electric) delivered a presentation and discussion on SPP Hubs and possible proposals for new hub design in the new northern areas of the SPP market footprint that will be intact once the Integrated System (IS) of Basin, WAPA, and Heartland are in that fooprint (Attachment 15 - Hub Design). Ken and Basin would like have something new in the way of hub design by June 2015, and understands that the first step in proposing a new SPP Market Hub is to run analyses and submit results and a proposal to the MWG. With this presentation today, Ken is seeking a general direction from MWG of where to do his leg work before submitting a proposal to MWG. Ken’s suggested proposals for MWG review consisted of 1) at combination of the existing north hub and a UMZ hub; 2) a modified North Hub; 3) a new Central North Hub; and 4) an SPP Super North Hub. SPP Staff and some MWG Members noted that one obstacle to getting any new Market Hub functionality by June 2015 is the lack of IS data to run the analyses. A suggestion was made for Ken to use the Resource Hub functionality until there is more IS data to create a Market Hub proposal. There was also general agreement amongst the group against any changes to existing Hubs. Based on the feedback from MWG, Ken’s plan is to focus his analysis on options 1 and 3 (standalone hub and combined north hub plus UMZ) and not on changing the existing North Hub. He also plans to rethink the timeline Basin would like to use, and will research the Resource Hub functionality. Ken noted that Basin would hate to have to wait until summer of 2016 or 2017 and will continue to work with SPP Staff to see what other timelines might be feasible. Ken

Minutes No. [234]

thanked the group very much for their advice and feedback. During the course of the discussion, there were some questions about the current lack of liquidity around the SPP Hubs. Matt Moore (GSEC) suggested and an MWG Action Item was captured for SPP Staff to assess the SPP activity (BSS, Virtual, TCR, etc.) on the SPP existing Hubs and report back to MWG. This might help MWG determine if there is possibly some flaw in the design that is hindering the liquidity. Agenda Item 13 — Examples of Price Volatility Nick Parker (SPP) delivered a presentation in response to an MWG Action Item to show examples of price volatility in the Marketplace (Attachment 16 - RT Price Volatility). Nick pointed out that this presentation is just for the purpose of showing examples and does not discuss or propose any design changes or solutions. The results of the examples primarily to help drive the discussion and the decision on whether or not we need to pursue a price volatility MWP, which had originally been proposed by Amber Metzker (Xcel) at a previous MWG meeting. There was discussion and speculation on the root cause of the price spikes being presented, with some MPs suggesting that it’s possibly the lack of ramping capability in a 5-minute interval. If so, the group discussed if there might be a need to hange the market design to incent faster ramping units in the Market. This discussion prompted the capture of an MWG Action Item for SPP Staff to provide examples of DA ramping vs RT ramping. Amber Metzker (Xcel) commented that this presentation does at least confirm that there some issue and something that we need to be paying attention to. She continued by saying it is likely that some change or enhancement is needed; it may not be a MWP, but we cannot just ignore these examples and not try to get to the bottom of why they are happening. The group agreed that more analysis is needed and Gene Anderson pointed out that someone would need to prove that there is a design issue before we should make a significant design change. Debbie James (SPP) suggested that individual MPs bring examples of where a resource lost money over a day or a commitment period. More analysis and information on the spikes is needed, including what all is going on at the time that they happen. The group was encouraged to report any analysis or information they may have on each of their situations. Agenda Item 14 — MPRR211 - Self-Commit Run Time Make Whole Payment Exemption This item was tabled due to time constraints. Agenda Item 15 — MPRR210 - Sync to Min Costs in Mitigated Start-Up Offer This item was tabled due to time constraints. Agenda Item 16 — MPRR209 - Change Start-Up Offer from Daily to Hourly This item was tabled due to time constraints. Agenda Item 17 — MPRR213 - Default VOM for Mitigated Offers This item was tabled due to time constraints.

Minutes No. [234]

Agenda Item 18 — MPRR207 - Staggered Start-Up Time This item was tabled due to time constraints. Agenda Item 19 — RTO Marketplace Update This item was tabled due to time constraints. Agenda Item 20 — MMU Marketplace Update This item was tabled due to time constraints. Agenda Item 21 — MOPC Action Item #227 – ARRs and FCAs John Hyatt (MMU) delivered a presentation (Attachment 17 - 201409 MOPC Action Item 227 - Study Results Update) to show additional and updated study results, as requested by the MWG in July 2014. John’s original presentation was to satisfy the MOPC Action Item 227 for SPP MMU Staff to evaluate the impact of transmission service and financial rights allocations in constrained areas and reserve zones. During that presentation, the MWG asked to see additional data before making a decision on whether or not any action is needed by MWG, such as adding a rule or changing design. John also offered that MMU could help with any additional information that may be requested by the MWG regarding any next steps and actions. There was consensus amongst the MWG that the data does show MPs are not getting everything needed to hedge in the FCAs through the ARR allocation process, but that it’s not surprising, given the constrained nature of the areas. But expanding past the limits could cause issues with oversells and uplift. John pointed out that MPs are generally able to fully hedge through the TCR auction and that this is the way the market is intended to function. The group concluded that there does not seem to be a need for MWG or the MMU to do anything about these findings at this time and suggested that John take his report on to MOPC as it was presented here. Agenda Item 22 — Working Group/Committee Updates (cont’d) This item was tabled due to time constraints. Agenda Item 23 — TCR Update This item was tabled due to time constraints. Agenda Item 24 — 2013-2014 VRL Analysis This item was tabled due to time constraints. Agenda Item 25 — NERC Standard INT-001-1 – Intra-Balancing Authority Transaction ID This item was tabled due to time constraints.

Minutes No. [234]

Agenda Item 26 — Regulatory Report This item was tabled due to time constraints. Agenda Item 27 — TRR140 - TSR Modification for Resource Specific Source Points Matt Harward (SPP) introduced TRR140 (Attachment 18 - TRR 140 TSR Modification for Resource Specific Source Points), which is related to MPRR124 and its inclusion of a TSR modification process for resource specific source points into the Marketplace Protocols. Matt reported that after speaking with FERC staff, SPP Staff feels that this TSR Modification process should also be included in the Tariff due to potential rate impacts downstream. TRR140 contains the conforming Tariff language to the Protocol language in MPRR124. Ron Thompson (NPPD) made a motion and John Varnell (Tenaska) seconded to approve TRR140 as modified. The motion passed with no opposition and two abstentions (Xcel, Boston Energy T&M). Agenda Item 28 — New Settlement Location Type This item was tabled due to time constraints. Agenda Item 29 — MPRR181 - Mirrored JOU Share Option This item was tabled due to time constraints. Agenda Item 30 - Review of Motions, Action Items and Future Meetings

Motions: Agenda Item 6 – Over-Collected Losses (OCL) John Varnell (Tenaska) made a motion and Bruce Walkup (AECC) seconded to direct SPP Staff to develop protocol and tariff language in MPRR212 to implement an allocation based on RTBM withdrawal ratio share and to evaluate including in the language the exclusion of the BSSs from the allocation of OCL. The motion passed with no opposition and no abstentions. Agenda Item 7 - MPRR214 - Adequate Fuel Cost Recovery (expedite) Matt Moore (GSEC) made a motion and Jim Flucke (KCPL) seconded to expedite MPRR214. The motion passed with no opposition and no abstentions. Agenda Item 8 – MPRR196 – SPP Comments and Impact Analysis Amber Metzer (Xcel) made a motion and Matt Moore (GSEC) seconded to amend the MPRR196 recommendation report to incorporate the 9/16/14 SPP comments as submitted, and to accept the MPRR196 impact analysis with a ranking of high. The motion passed with no opposition and no abstentions. Agenda Item 10 – MPRR203 - Market Participant Funded Incremental Upgrades

Minutes No. [234]

Marguerite Wagner (Boston Energy) made a motion and John Varnell (Tenaska) seconded to approve MPRR203 as submitted. The motion failed with 10 oppositions (OPPD, Midwest, AEP, OGE, GSEC, KCPL, Xcel, CUS, OMPA, EDE) and four abstentions (Tenaska, LES, Westar, AECC). Agenda Item 11 – Enhanced Combined Cycle Cost Benefit Analysis Matt Moore (GSEC) made a motion and Shawn McBroom (OGE) seconded to approve MWG recommendations to MOPC. The motion passed with 6 votes in favor (WR, OGE, TNSK, KCPL, GSEC, EDE), 2 oppositions (AEP, Xcel), and nine abstentions (Boston, OPPD, NPPD, Midwest, OMPA, CUS, AECC, KMEA, LES). Agenda Item 27 - TRR140 - TSR Modification for Resource Specific Source Points Ron Thompson (NPPD) made a motion and John Varnell (Tenaska) seconded to approve TRR140 as modified. The motion passed with no opposition and two abstentions (Xcel, Boston Energy T&M). Action Items: • SPP Staff will assess the SPP activity (BSS, Virtual, TCR, etc.) on the SPP existing Hubs and report

results back to MWG. • During the price volatility examples and discussion, MWG asked SPP Staff to provide examples of

Day Ahead Market ramping vs Real-Time ramping.

Future Meetings: October 21, 2014 (8:15 a.m. – 6:00 p.m.) October 22, 2014 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor September 29, 2014 (1:00 p.m. – 4:00 p.m.) Location: Net Conference November 18, 2014 (8:15 a.m. – 6:00 p.m.) November 19, 2014 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor Agenda Item 31 — MPRR186 - Mitigated Offer – External Dynamic Resource This item was tabled.

Minutes No. [234]

Agenda Item 32 — MPRR126 - Real-Time Regulation Make Whole Payment This item was tabled.

Agenda Item 33 – Adjournment Gene Anderson adjourned the meeting at 12:06 p.m.

Respectfully Submitted, Debbie James Secretary Attachments Attachment 1 - MWG Attendance September 12 2014 Attachment 1a - Ann Scott Proxy Attachment 1b - Richard Ross Proxy Attachment 1c - Rick McCord Proxy Attachment 2 - MWG Agenda for September 23-24 2014 Attachment 3a - MWG Aug 19-20 2014 Minutes Attachment 3b - MWG Aug 22 2014 Minutes Attachment 4 - MWG Charter 012913 Attachment 5 - MPRR - Quarterly Report Attachment 6 - MPRR 212 Over Collected Losses Design Change Attachment 7 - MPRR212 Presentation 9-8-2014 Attachment 8 - MPRR 212 Impact Analysis Attachment 9 - MPRR 214 Adequate Fuel Cost Recovery Attachment 10 - MPRR 214 SPP Comments 9-11-2014 Attachment 11 - MPRR 196 Recommendation Report Attachment 12 - MPRR 203 Recommendation Report Attachment 13 - ECC Cost Benefit Analysis_Final Attachment 14 - MWG ECC Recommendation_draft_MWG Attachment 15 - Hub Design Attachment 16 - RT Price Volatility Attachment 17 - 201409 MOPC Action Item 227 - Study Results Update Attachment 18 - TRR 140 TSR Modification for Resource Specific Source Points



September 29, 2014

Net Conference

• Summary of Motions • Agenda Item 2 – VRL Recommendation Ron Thompson (NPPD) made a motion, and Clifford Franklin (Westar) seconded to accept SPP staff’s recommendation of keeping the VRLs that are currently set. The motion passed with no opposition and one abstention (BETM). Agenda Item 3 – MPRR 212 Over-Collected Losses (OCL) John Varnell (TNSK) made a motion, and Bruce Walkup (AECC) seconded to approve MPRR212 as modified by the MWG to implement option 3-RT with a rank of High, priority 1. The motion passed with two abstentions (Xcel, OGE) and no oppositions. Agenda Item 4 - MPRR204 - Compliance & Add’l Changes FERC Order 755 – RTWG Comments Jim Flucke (KCPL) made a motion, and John Varnell (TNSK) seconded, to accept RTWG comments and to incorporate staff’s recommended deletion of the product substitution language from RTWG Comments dated 9-24-2014 as modified by MWG. The motion passed with no opposition and one abstention (Xcel). Agenda Item 5 – MPRR197 – VOM Cost Clarification – RTWG Comments MWG agreed to move the MPRR forward to MOPC in order to retain the option of voting on it. Agenda Item 6 – MPRR199 - Intra-Day Mitigation Measures Clarifications Terry Gates (AEP) made a motion, and Ron Thompson (NPPD) seconded to approve MPRR 199 AEP Comments 9-3-2014 with modifications. The motion passed with no opposition and one abstention (Xcel).

Minutes No. [235]



September 29, 2014

Net Conference


Agenda Item 1 — Call to Order, Proxies, Agenda Discussion Gene Anderson (OMPA) called the meeting to order at 1:00 p.m. The attendance was recorded and the following Members were represented by proxy (Attachment 1 – MWG Attendance Sep 29 2014):

• Brad Lafler (LES) for Lee Anderson (LES) (Attachment 1a – Lee Anderson Proxy) • Terry Gates (AEP) for Richard Ross (AEP) (Attachment 1b – Richard Ross Proxy) • John Varnell (TNSK) for Ann Scott (TNSK) (Attachment 1c – Ann Scott Proxy) • Clifford Franklin (Westar) for Aaron Rome (Midwest) (Attachment 1d – Aaron Rome Proxy)

The group reviewed the agenda (Attachment 2—MWG Agenda for September 29 2014) and agreed to the order as submitted. Agenda Item 2 — VRL Recommendation Kevin Bates (SPP MMU) presented an analysis of the Violation Relaxation Limits (VRLs) (Attachment 3 - 2014 VRL Presentation). Kevin noted that the Integrated Marketplace has been live for only six months, and therefore there is not sufficient information to change the VRLs at this time. There was consensus from the group to proceed with SPP’s recommendation. Ron Thompson (NPPD) made a motion, and Clifford Franklin (Westar) seconded to accept SPP staff’s recommendation of keeping the VRLs that are currently set. The motion passed with no opposition and one abstention (BETM). Agenda Item 3 — MPRR212 - Over Collected Losses Design Change Wayne Camp (SPP) updated the group on the latest changes to MPRR 212 (Attachment 4 - MPRR 212 Recommendation Report), which implements “option 3-RT” as directed by MWG at the September 23-24 meeting. Option 3-RT sums the Day-Ahead and Real-Time OCL amounts, then distributes those amounts to the Settlement Area Loss Pools using Real-Time withdrawals, and finally allocates the amounts in each Loss Pool to each Asset Owner based on Real-Time withdrawals. It was noted that all Bilateral Settlement Schedules were included in the allocation to each Asset Owner. The group determined that if someone wanted to change the design to exclude non-GFA Bilateral Settlement Schedules, then it could be done in another MPRR so that MPRR 212 can be implemented sooner. John Varnell (TNSK) made a motion, and Bruce Walkup (AECC) seconded to approve MPRR 212 as modified by the MWG to implement option 3-RT with a rank of High, priority 1. The motion passed with two abstentions (Xcel, OGE) and no oppositions.

Minutes No. [235]

Agenda Item 4 — MPRR204 - Compliance & Add’l Changes FERC Order 755 Debbie James (SPP) presented the RTWG comments on MPRR 204 (Attachment 6 - MPRR 204 Recommendation Report). MWG modified the language in Attachment AE Section 8.6.5(4)(a)(v) to clarify the condition in which Operating Reserve costs will be set to zero in the RUC Make Whole Payment Cost Amount calculation. Jim Flucke (KCPL) made a motion, and John Varnell (TNSK) seconded, to accept RTWG comments and to incorporate staff’s recommended deletion of the product substitution language from RTWG Comments dated 9-24-2014 as modified by MWG. The motion passed with no opposition and one abstention (Xcel). Agenda Item 5 — MPRR197 – VOM Cost Clarification – RTWG Comments Debbie James (SPP) presented the RTWG comments on MPRR 197 (Attachment 7 - MPRR 197 Recommendation Report). Based on SPP legal counsel, the RTWG believes that MPRR 197 lacks Tariff language. Richard Ross (AEP) asked the group to move the MPRR forward to MOPC as-is in order to retain the option to vote on it at MOPC, and if the MPRR was not ready for a vote by the time MOPC meets, then MOPC could remand it back to MWG for further work. The group agreed to this proposal. Agenda Item 6 — MPRR199 - Intra-Day Mitigation Measures Clarifications Terry Gates (AEP) presented the AEP comments on MPRR 199 (Attachment 8 - MPRR 199 Recommendation Report). Matthew Johnson (CUS) agreed with both the AEP and MMU comments. The group made a grammatical modification to the Tariff language. Terry Gates (AEP) made a motion, and Ron Thompson (NPPD) seconded to approve MPRR 199 AEP Comments 9-3-2014 with modifications. The motion passed with no opposition and one abstention (Xcel). Agenda Item 7 — NERC Standard INT-001-1 – Intra-Balancing Authority Transaction ID Debbie James (SPP) opened the discussion regarding NERC Standard INT-001-1. This NERC Standard deals with monitoring transactions inside a balancing authority when using Point to Point Transmission and the fact that the PTP service must be tagged. Since SPP is one balancing authority, there is no longer any tagging amongst entities within the SPP BA. The SPP Compliance Department has prepared an attestation for MPs confirming that the market does not require any internal tagging for Point-to-Point transmission. Debbie James (SPP) will send the attestation to MWG members. Agenda Item 8 — Working Group/Committee Updates a. Quick-Start Resource Subgroup – Debbie James (SPP) provided an update on the Quick-Start

Resource Subgroup. The subgroup listed and prioritized issues and concerns. The group brainstormed some possible changes to address the concerns. The next meeting is scheduled for Wednesday, October 1, at 3:30-5:00 (CDT).

b. MOPC MPRR Schedule – Micha Bailey (SPP) presented the MOPC MPRR Schedule for the October MOPC (Attachment 9 - MOPC MPRR Schedule).

Minutes No. [235]

c. Outage Subgroup – Jared Greenwalt (SPP) provided an update on the Outage Subgroup. The subgroup has agreed on a proposal to MWG to improve the transmission outage coordination process. This proposal will be discussed at the October 20-21 MWG.

Agenda Item 9 — Review of Motions, Action Items and Future Meetings Motions: Agenda Item 2 – VRL Recommendation Ron Thompson (NPPD) made a motion, and Clifford Franklin (Westar) seconded to accept SPP staff’s recommendation of keeping the VRLs that are currently set. The motion passed with no opposition and one abstentions (BETM). Agenda Item 3 – MPRR 212 Over-Collected Losses (OCL) John Varnell (TNSK) made a motion, and Bruce Walkup (AECC) seconded to approve MPRR212 as modified by the MWG to implement option 3-RT with a rank of High, priority 1. The motion passed with two abstentions (Xcel, OGE) and no oppositions. Agenda Item 4 - MPRR204 - Compliance & Add’l Changes FERC Order 755 – RTWG Comments Jim Flucke (KCPL) made a motion, and John Varnell (TNSK) seconded, to accept RTWG comments and to incorporate staff’s recommended deletion of the product substitution language from RTWG Comments dated 9-24-2014 as modified by MWG. The motion passed with no opposition and one abstention (Xcel). Agenda Item 5 – MPRR197 – VOM Cost Clarification – RTWG Comments MWG agreed to move the MPRR forward to MOPC in order to retain the option of voting on it. Agenda Item 6 – MPRR199 - Intra-Day Mitigation Measures Clarifications Terry Gates (AEP) made a motion, and Ron Thompson (NPPD) seconded to approve MPRR 199 AEP Comments 9-3-2014 with modifications. The motion passed with no opposition and one abstention (Xcel). Action Items: • Debbie James (SPP) will send out to MWG Members the attestation for the NERC Reliability

Standard INT-001-1.

Future Meetings: October 21, 2014 (8:15 a.m. – 6:00 p.m.)

Minutes No. [235]

October 22, 2014 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor November 18, 2014 (8:15 a.m. – 6:00 p.m.) November 19, 2014 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor

Agenda Item 10 – Adjournment Gene Anderson (AEP) adjourned the meeting at 3:11 p.m.

Respectfully Submitted, Debbie James Secretary

Minutes No. [235]

Attachments Attachment 1 – MWG Attendance September 29 2014 Attachment 1a – Lee Anderson Proxy Attachment 1b – Richard Ross Proxy Attachment 1c – Ann Scott Proxy Attachment 1c – Aaron Rome Proxy Attachment 2 – MWG Agenda for September 29 2014 Attachment 3 – 2014 VRL Presentation Attachment 4 – MPRR 212 Recommendation Report Attachment 5 – OCL Allocation Examples Presentation Attachment 6 – MPRR 204 Recommendation Report Attachment 7 – MPRR 197 Recommendation Report Attachment 8 – MPRR 199 Recommendation Report Attachment 9 - MOPC MPRR Schedule

MOPC MPRR Schedule for 1/2015 and 4/2015 October 21-22, 2014

Micha Bailey [email protected]


3

MPRRs going to January 2015 MOPC

MPRR Submission Deadline for Non-Expedited10/28/2014

MPRR January 2015 MOPC Internal Schedule

MPRR Posting Deadline for Non-Expedited10/31/2014

ORWG Meeting before MOPC for MPRRs12/4/2014

MWG Meeting before MOPC for MPRRs11/18/2014

MOPC Meeting Materials due date1/2/2015

RTWG Meeting before MOPC for MPRRs12/18/2014

3/26/2015MOPC Meeting Materials due date

4/3/2015

MWG Meeting before MOPC for MPRRs3/17/2015

ORWG Meeting before MOPC for MPRRsApr-14

RTWG Meeting before MOPC for MPRRs

2/24/2015MPRR Posting Deadline for Non-Expedited

2/27/2015

MPRR April 2015 MOPC Internal ScheduleMPRR Submission Deadline for Non-Expedited

4

MPRRs going to April 2015 MOPC

PRR Recommendation Report

MPRR No. 215 PRR

Title Product Substitution Cost Calculation

Timeline

Normal Expedited Urgent Action

Provide explanation if Expedited and/or Urgent Action is selected: This MPRR is expedited to correct an Integrated Marketplace system implementation error.

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Ranking High – 2

Impact Analysis Required Yes, Estimated Cost: TBD Duration: TBD No

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: 4.3.1.3, 4.4.2.4, 4.5.8.4, 4.5.8.6, 4.5.8.7, 4.5.8.8, 4.5.8.10, 4.5.8.11, 4.5.8.12, 4.5.9.4, 4.5.9.6, 4.5.9.7, 4.5.9.8, 4.5.9.9, 4.5.9.10, 4.5.9.15. Day-Ahead Market Results, RTBM Results, Day-Ahead Regulation-Up Amount, Day-Ahead Spinning Reserve Amount, Day-Ahead Supplemental Reserve Amount, Day-Ahead Regulation-Up Service Distribution Amount, Day-Ahead Spinning Reserve Distribution Amount, Day-Ahead Supplemental Reserve Distribution Amount, Day-Ahead Make-Whole-Payment Amount, Real-Time Regulation-Up Service Amount, Real-Time Spinning Reserve Amount, Real-Time Supplemental Reserve Amount, RUC Make-Whole-Payment Amount, Real-Time Out-Of-Merit Amount, RUC Make-Whole-Payment Distribution Amount, Real-Time Regulation Non-Performance Amount Protocol Version: 21.a

Type of Revision Correction Clarification

Design Enhancement Design Change

Revision Description

Currently, when a higher quality Operating Reserve product is used to meet a lower quality Operating Reserve product requirement, the higher quality Operating Reserve cleared MWs are reported as MWs cleared for the lower quality product. For example, if Regulation-Up is cleared in excess of the Regulation-Up requirement in order to meet the Spinning Reserve requirement, these excess Regulation-Up MWs are reported as Spinning Reserve MWs. This ensures that, for operational deployment and settlement purposes, each Operating Reserve product is linked to its respective Operating Reserve requirement such that the reported MWs (“Operational MWs”) for use in deployment and settlement do not exceed the requirements.

Revenues associated with Settlement of each of the “up” Operating Reserve MWs is correct based upon these “Operational MWs”. However, using these Operational MWs to calculate availability costs in both the DA MWP and RUC MWP may produce higher availability costs since the cost of the higher quality

Attachment 5 - MPRR 215 Recommendation Report.docx 10/21/2014 Page 1 of 44

product that substituted for the lower quality product is not being properly captured. For example, under the current calculations, if Spinning Reserve at an Offer cost of $10/MW is being used to substitute for Supplemental Reserve being offered in at $90/MW, the cleared Spinning Reserve is reported as Supplemental Reserve and the $90/MW cost is used to calculate the Supplemental Reserve availability cost. These proposed changes will properly account for the fact that a $10/MW Spin Offer cost was used to meet the Supplemental Reserve requirement.

To properly account for the $10/MW Spin Offer cost in the example above, we need to use the actual “cleared MWs” directly from the clearing engine for each up product. In the above example, if we assume that the Spinning Reserve requirement is 100 MWs, the Supplemental Reserve Requirement is 100 MWs and 20 MWs of Spinning Reserve in excess of the Spinning Reserve requirement at $10/MW is being used to meet the Supplemental Reserve requirement, the “cleared MWs” of Spinning Reserve is equal to 120 MWs and the cleared MWs of Supplemental Reserve is equal to 80 MWs. Further assume that the Supplemental Reserve Offer cost of the 80 MWs of cleared Supplemental Reserve MWs is $5/MW and the Supplement Reserve Offer Cost of the 20 MWs of Supplemental Reserve requirement met by cleared Spinning Reserve was $90/MW.

The availability cost for cleared Spinning Reserve is then equal to 120 MWs * $10/MW = $1200. The availability cost for cleared Supplemental Reserve is then equal to 80 MWs * $5/MW = $400. Total Spin + Supp Costs = $1600.

Under the current calculation method, the availability cost for Spinning Reserve would be 100 MWs * $10/MW = $1000 and the availability cost for Supplemental Reserve would be 80 MWs * $5/MW + 20 MWs * $90/MW = $2200, for a total Spin + Supp Cost of $3200.

Tariff Implications or Changes

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

No

Criteria Impact or Changes


No

Working Group Voting Record

MWG

Date of Vote: 10/21/2014 Vote: Approved

Opposed: N/A

Abstained: WR

RTWG Date of Vote: Vote:

ORWG Date of Vote: Vote:

MOPC Date of Vote: Vote:

Board/Members Committee Date of Vote: Vote:

Date 10/14/2014


Sponsor

Name Micha Bailey E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.2522

Comments Received Comment Author Micha Bailey on behalf of MWG Date 10/21/2014

Comment Description MWG separated out the Day-Ahead and Real-Time Regulation Up for Contingency Reserve Substitution MW Quantity. This will allow the MPs to see the amount of MWs that were substituted. The MWG also added the Operating Reserve back onto the Settlement Statement.

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

Proposed Protocol Language Revision

4.3.1.3 DA Market Results

No later than 1600 hours Day-Ahead, SPP electronically communicates the DA Market results for each hour of the Operating Day to Market Participants. The following results are communicated to each Market Participant that relates only to that Market Participant:

(1) Cleared Resource Offers for Energy and Regulation-Down Service in MW, and cleared offered and cleared operational Regulation-Up Service, Regulation-Down, Spinning Reserve and/or Supplemental Reserve Offers, in MW;

(a) Cleared Offers for Energy associated with Resource Offers represent a physical Resource commitment schedule that forms the basis for the Current Operating Plan for the upcoming Operating Day. Market Participants should consider Resource commitment schedules resulting from SPP commitment of Resources with a Commit Status of “Market” or “Reliability as SPP start-up orders and shut-down orders.

(b) Resources committed by SPP in the DA Market with a Commit Status of “Market” or “Reliability” are guaranteed to receive DA Market revenues that are at least equal to the DA Market Resource Offer costs for the associated cleared amount of Energy, Regulation-Up, Regulation-Down Spinning Reserve and/or Supplemental Reserve. See Section 4.5.8.12 for additional details.

Comment [MPRR102.1]: MPRR102 Awaiting implementation. #ER13-1748




(c) Cleared offered Resource Offer MWs for Regulation-Up Service, Spinning Reserve and Supplemental Reserve represent the following:

(i) Cleared offered Resource Offer MWs for Regulation-Up Service include additional Regulation-Up Service MWs cleared above the Regulation-Up requirement to meet either the Spinning Reserve requirement or Supplemental Reserve requirement resulting from product substitution as described under Section 4.3.1.2(2)(c). The additional Regulation-Up Service MWs cleared above the Regulation-Up requirement are used in the calculation of Operating Reserve Offer costs described under Section 4.5.8.12.

(ii) Cleared offered Resource Offer MWs for Spinning Reserve include additional Spinning Reserve MWs cleared above the Spinning Reserve requirement to meet the Supplemental Reserve requirement resulting from product substitution as described under Section 4.3.1.2(2)(c). Cleared offered Resource Offer MWs for Spinning Reserve are used in the calculation of Spinning Reserve Offer costs described under Section 4.5.8.12.

(iii) Cleared offered Resource Offer MWs for Supplemental Reserve represent the Supplemental Reserve Offers cleared to meet the remaining Supplemental Reserve requirement after accounting for any Regulation-Up MWs and/or Spinning Reserve MWs that were cleared to meet the Supplemental Reserve requirement resulting from product substitution as described under Section 4.3.1.2(2)(c). Cleared offered Resource Offer MWs for Supplemental Reserve are used in the calculation of Supplemental Reserve Offer costs described under Section 4.5.8.12.

(d) Cleared operational Resource Offer MWs for Regulation-Up Service, Spinning Reserve and Supplemental Reserve represent the following:

(i) Cleared operational Resource Offer MWs for Regulation-Up Service include only the Regulation-Up MWs cleared to meet the Regulation-Up requirement. Cleared operational Resource Offer MWs for Regulation-Up Service are used to calculate Regulation-Up Service revenues as described under Section 4.5.8.4, are used to calculate Regulation-Up Service Offer costs described under Section 4.5.8.12, and are used in the Regulation-Up Service cost allocation as described under Section 4.5.8.8.


(ii) Cleared operational Resource Offer MWs for Spinning Reserve include both Regulation-Up Service Offer MWs and Spinning Reserve Offer MWs cleared to meet the Spinning Reserve requirement. Cleared operational Resource Offer MWs for Spinning Reserve are used to calculate Spinning Reserve revenues as described under Section 4.5.8.6 and are used in the Spinning Reserve cost allocation as described under Section 4.5.8.10.

(iii) Cleared operational Resource Offer MWs for Supplemental Reserve include Regulation-Up Service Offer MWs, Spinning Reserve Offer MWs and Supplemental Reserve Offer MWs cleared to meet the Supplemental Reserve requirement. Cleared operational Resource Offer MWs for Supplemental Reserve are used to calculate Supplemental Reserve revenues as described under Section 4.5.8.7 and are used in the Supplemental Reserve cost allocation as described under Section 4.5.8.11.

1.(2) Cleared Virtual Energy Offers, in MW;

2.(3) Cleared Import Interchange Transaction Offers, in MW;

3.(4) Cleared Demand Bids, in MW;

4.(5) Cleared Virtual Energy Bids, in MW;

5.(6) Cleared Export Interchange Transaction Bids, in MW;

6.(7) Cleared Through Interchange Transactions, in MW.

The following results are communicated to all Market Participants:

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

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

4.4.2.4 RTBM Results

Following execution of the RTBM SCED, the following results are communicated to Market Participants prior to the start of the applicable Dispatch Interval. All Market Participants must have the capability to receive and follow Resource Dispatch Instructions via XML in the event of

Formatted: Indent: Left: 0.13", Hanging: 0.38", Numbered + Level: 1 + Numbering Style:1, 2, 3, … + Start at: 1 + Alignment: Left +Aligned at: 0.75" + Tab after: 1" + Indent at: 1"

Formatted: Indent: Left: 0.13", Hanging: 0.38", Numbered + Level: 1 + Numbering Style:1, 2, 3, … + Start at: 1 + Alignment: Left +Aligned at: 0.75" + Tab after: 1" + Indent at: 1"


an ICCP communications failure. The following results are communicated to each Market Participant that relates only to that Market Participant:

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

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

(3) Cleared offered and cleared operational Regulation-Up Service, Spinning Reserve and Supplemental Reserve MW by Resource.

(a) Cleared offered Regulation-Up Service, Spinning Reserve and Supplemental Reserve MWs represent the following:

(i) Cleared offered Regulation-Up Service MWs include additional Regulation-Up Service MWs cleared above the Regulation-Up requirement to meet either the Spinning Reserve requirement or Supplemental Reserve requirement resulting from product substitution as described under Section 4.4.2.3(4). The additional Regulation-Up Service MWs cleared above the Regulation-Up requirement are used in the calculation of Operating Reserve Offer costs described under Section 4.5.9.8.

(ii) Cleared offered Spinning Reserve MWs include additional Spinning Reserve MWs cleared above the Spinning Reserve requirement to meet the Supplemental Reserve requirement resulting from product substitution as described under Section 4.4.2.3(4). Cleared offered Spinning Reserve MWs are used in the calculation of Spinning Reserve Offer costs described under Section 4.5.9.8.

(iii) Cleared offered Supplemental Reserve MWs represent the Supplemental Reserve MWs cleared to meet the remaining Supplemental Reserve requirement after accounting for any Regulation-Up MWs and/or Spinning Reserve MWs that were cleared to meet the Supplemental Reserve requirement resulting from product substitution as described under Section 4.4.2.3(4). Cleared offered Supplemental Reserve MWs are used in the calculation of Supplemental Reserve Offer costs described under Section 4.5.9.8.

(b) Cleared operational Regulation-Up Service, Spinning Reserve and Supplemental Reserve MWs represent the following:

Formatted: Indent: Left: 0.25", Numbered +Level: 1 + Numbering Style: 1, 2, 3, … + Startat: 1 + Alignment: Left + Aligned at: 1.38" +Tab after: 1.63" + Indent at: 1.63", Tab stops:Not at 1.63"




(i) Cleared operational Regulation-Up MWs include only the Regulation-Up MWs cleared to meet the Regulation-Up requirement. Cleared operational Regulation-Up MWs are used to calculate Regulation-Up Service revenues as described under Section 4.5.9.4 and are used to calculate Regulation-Up Service Offer costs described under Section 4.5.9.8.

(ii) Cleared operational Spinning Reserve MWs include both Regulation-Up Service MWs and Spinning Reserve MWs cleared to meet the Spinning Reserve requirement. Cleared operational Spinning Reserve MWs are used to calculate Spinning Reserve revenues as described under Section 4.5.9.6.

(iii) Cleared operational Supplemental Reserve MWs include Regulation-Up Service MWs, Spinning Reserve MWs and Supplemental Reserve MWs cleared to meet the Supplemental Reserve requirement. Cleared operational Supplemental Reserve MWs are used to calculate Supplemental Reserve revenues as described under Section 4.5.9.7.

These MW values described under subsections (1), (2) and (3)(b) above are used by the Energy Management System (EMS) for Energy and Regulation Deployment and by the Reserve Sharing System (RSS) for Contingency Reserve Deployment.

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

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

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

Formatted: Indent: Hanging: 0.38",Numbered + Level: 1 + Numbering Style: 1, 2,3, … + Start at: 1 + Alignment: Left + Alignedat: 0.25" + Tab after: 0.5" + Indent at: 0.5"


4.5.8.4 Day-Ahead Regulation-Up Amount

The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

DaRegUpHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Operational Regulation-Up Service Quantity per AO per Settlement Location per Hour - The total quantity of Regulation-Up Service represented by AO a’s cleared operational Regulation-Up Offers in the DA Market in Reserve Zone z that includes Resource Settlement Location s for the Hour, as described under Section 4.3.1.3(1)(d)(i).

EqrDaRegUpHrlyQty a, s, h

MWh Hour Day-Ahead Electric Quarterly Reporting Regulation-Up Sales per AO

per Settlement Location per Hour – AO a’s DA Market DaRegUpHrlyQty a, z, s, h Regulation-Up Service sales at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.

EqrDaRegUpHrlyPrc a, s, h

$/MWh Hour Day-Ahead Electric Quarterly Reporting Regulation-Up Sales Prices

per AO per Settlement Location per Hour – AO a’s DA Market DaRegUpHrlyQty a, z, s, h Regulation-Up Service sales price at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.



Formatted: Font: Italic


4.5.8.6 Day-Ahead Spinning Reserve Amount


Variable

Unit

Settlement Interval

Definition

DaSpinHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Operational Spinning Reserve Quantity per AO per Settlement Location per Hour - The total quantity of Spinning Reserve MW represented by AO a’s cleared operational Spinning Reserve Offers in the DA Market in Reserve Zone z that includes Resource Settlement Location s, for the Hour, as described under Section 4.3.1.3(1)(d)(ii).

EqrDaSpinHrlyQty a, s, h

MWh Hour Day-Ahead Electric Quarterly Reporting Spinning Reserve Sales per AO per

Settlement Location per Hour – AO a’s DA Market DaSpinHrlyQty a, z, s, h Spinning Reserve sales at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.

EqrDaSpinHrlyPrc a, s, h

$/MWh Hour Day-Ahead Electric Quarterly Reporting Spinning Reserve Sales Prices per AO

per Settlement Location per Hour – AO a’s DA Market DaSpinHrlyQty a, z, s, h Spinning Reserve sales price at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.


4.5.8.7 Day-Ahead Supplemental Reserve Amount


Variable

Unit

Settlement Interval

Definition

DaSuppHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Operational Supplemental Reserve Quantity per AO per Settlement Location per Hour - The total quantity of Supplemental Reserve represented by AO a’s cleared operational Supplemental Reserve Offers in the DA Market in Reserve Zone z that includes Resource Settlement Location s, for the Hour, as described under Section 4.3.1.3(1)(d)(iii).

EqrDaSuppHrlyQty a, s, h

MWh Hour Day-Ahead Electric Quarterly Reporting Supplemental Reserve Sales per AO

per Settlement Location per Hour – AO a’s DA Market DaSuppHrlyQty a, z, s,

hSupplemental Reserve sales at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.

EqrDaSuppHrlyPrc a, s, h

$/MWh Hour Day-Ahead Electric Quarterly Reporting Supplemental Reserve Sales Prices

per AO per Settlement Location per Hour – AO a’s DA Market DaSuppHrlyQty a, z, s, hSupplemental Reserve sales price at Resource Settlement Location s in Hour h for use by AO a in reporting such sales to FERC in accordance with FERC EQR requirements.


4.5.8.8 Day-Ahead Regulation-Up Service Distribution Amount


Variable

Unit

Settlement Interval

Definition

DaRegUpHrlyQty a, z, s, h MW Hour Day-Ahead Operational Regulation-Up Service Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.4.

4.5.8.10 Day-Ahead Spinning Reserve Distribution Amount


Variable

Unit

Settlement Interval

Definition

DaSpinHrlyQty a, z, s, h MW Hour Day-Ahead Operational Spinning Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.6.




4.5.8.11 Day-Ahead Supplemental Reserve Distribution Amount


Variable

Unit

Settlement Interval

Definition

DaSuppHrlyQty a, z, s, h MW Hour Day-Ahead Operational Supplemental Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.7.


4.5.8.12 Day-Ahead Make-Whole-Payment Amount

1.(1) The Day-Ahead Make-Whole-Payment Amount is a credit or charge1 to a Resource Asset Owner and is calculated for each Resource with an associated DA Market Commitment Period that was committed by SPP with a Day-Ahead Market Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1, or was committed as part of the Multi-Day Reliability Assessment as defined under Section 4.2.6.3. A payment is made to the Resource Asset Owner when the sum of the Resource’s DA Market Start-Up Offer costs, No-Load Offer costs, Energy Offer Curve and Operating Reserve Offer costs associated with cleared DA Market amounts for Energy and Operating Reserve is greater than the Energy and Operating Reserve DA Market revenues received for that Resource over the Resource’s DA Market Make-Whole-Payment Eligibility Period.

2.(2) A Resource’s DA Market Make-Whole-Payment Eligibility Period is equal to a Resource’s DA Market Commitment Period except as defined below:

1.(a) For Resources with an associated DA Market Commitment Period that begins in one Operating Day and ends in the next Operating Day, two DA Market Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the hour that the DA Market Commitment Period begins and ends in the last hour of the first Operating Day. The second period begins in the first hour of the next Operating Day and ends in the last hour of the DA Market Commitment Period.

1.(3) The following cost recovery eligible rules apply to each DA Market Make-Whole-Payment Eligibility Period. Offer costs are calculated using the DA Market Offer prices in effect at the time the commitment decision was made except under the situation described under Section (b)(i)(1) below.

1.(a) There may be more than one DA Market Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single DA Market Make-Whole Payment Eligibility Period is contained within a single Operating Day.

2.(b) A Resource’s DA Market Start-Up Offer costs are not eligible for recovery in the following DA Market Make-Whole Payment Eligibility Periods:

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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Formatted: Numbered + Level: 1 +Numbering Style: a, b, c, … + Start at: 1 +Alignment: Left + Aligned at: 0.25" + Tabafter: 0.5" + Indent at: 0.5"

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Formatted: Numbered + Level: 1 +Numbering Style: a, b, c, … + Start at: 1 +Alignment: Left + Aligned at: 1" + Tab after: 1.25" + Indent at: 1.25", Tab stops: Not at 0.5"


1.(i) Any DA Market Make-Whole Payment Eligibility Period that is adjacent to the end of a RUC Make-Whole Payment Eligibility Period except as described in (1) below;

1.(1) As described under Section 4.5.9.8(3)(h), to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the adjacent RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the adjacent Day-Ahead Make-Whole Payment Eligibility Period.

2.(ii) Any DA Market Make-Whole Payment Eligibility Period resulting from a DA Market Commitment Period that contains a DA Market Self-Commit Hour; and

3.(iii) Any DA Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s DA Market Commit Time less the Resource’s Sync-To-Min Time.

3.(c) For each DA Market Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s DA Market Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time rounded down to the nearest hour or (2) 24 Hours, and that portion of the Start-Up Offer is included as a cost in each hour of the DA Market Make-Whole Payment Eligibility Period until the sum of these hourly costs are equal to the DA Market Start-Up Offer or until the end of the DA Market Make-Whole Payment Eligibility Period, whichever occurs first.

4.(d) To the extent that the full amount of the DA Market Start-Up Offer is not accounted for in the last DA Market Make-Whole Payment Eligibility Period in the Operating Day, any remaining DA Market Start-Up Offer costs are carried forward for recovery in the first DA Market Make-Whole Payment Eligibility Period of the following Operating Day. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $10,000. The DA Market Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For DA Market Make-Whole Payment calculation purposes, the DA Market Commitment Period is split into two

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separate DA Market Make-Whole Payment Eligibility Periods as described in (2).b above. The first DA Market Make-Whole Payment Eligibility Period will include $1000/hour of Start-Up Offer costs ($10,000 / 10 Hours) in hours 23 and 24. The second DA Market Make-Whole Payment Eligibility Period will include $1000/hour of Start-Up Offer costs in hours 1 through 8.

5.(4) The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for each hour in a given DA Market Make-Whole Payment Eligibility Period is calculated as follows:

#DaMwpCpAmt a, s, c =

Max (0, ∑h

( DaMwpCostHrlyAmt a, h, s, c + DaMwpRevHrlyAmt a, h, s, c ) ) * (-1)

(a) DaMwpCostHrlyAmt a, h, s, c =

DaStartUpEligHrlyFlg a, h, s, c * DaStartUpHrlyAmt a, h, s, c

+ DaClrdComStatHrlyFlg h, s, c

* [ DaRucRmndrStartUpHrlyAmt a, s, h, c

+ DaNoLoadHrlyAmt a, h, s, c + DaIncrEnHrlyAmt a, h, s, c

+ DaRegUpAvailHrlyAmt a, h, s, c + DaRegDnAvailHrlyAmt a, h, s, c

+ DaSpinAvailHrlyAmt a, h, s, c + DaSuppAvailHrlyAmt a, h, s, c

+ DaRegUpforCRSubAvailHrlyAmt a, s, h, c ]

Where,

#DaIncrEnHrlyAmt a, h, s, c = ∫) s h, a,yQty (DaClrdHlr ABS

0

CurveOffer Energy Market DA

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(b) DaMwpRevHrlyAmt a, h, s, c = DaClrdComStatHrlyFlg h, s, c

* [ ( DaLmpHrlyPrc s, h * DaClrdHrlyQty a, s, h )

+ DaRegUpHrlyAmt a, h, s + DaRegDnHrlyAmt a, h, s

+ DaSpinHrlyAmt a, h, s + DaSuppHrlyAmt a, h, s ]

(c) DaRegUpAvailHrlyAmt a, h, s

= DaRegUpHrlyQty a, h, s * DaRegUpOffer a, h, s

(d) DaRegDnAvailHrlyAmt a, h, s

= DaRegDnHrlyQty a, h, s * DaRegDnOffer a, h, s

(e) DaSpinAvailHrlyAmt a, h, s, c

= DaOffSpinHrlyQty a, h, s * DaSpinOffer a, h, s

(f) DaSuppAvailHrlyAmt a, h, s, c

= DaOffSuppHrlyQty a, h, s * DaSuppOffer a, h, s

(g) DaRegUpforCRSubAvailHrlyAmt a, s, h, s, c

= DaRegUpforCRSubHrlyQty a, h, s * DaRegUpCapOffer a, h, s

(g.1) DaRegUpforCRSubHrlyQty a, h, s = DaOffRegUpHrlyQty a, h, s - DaRegUpHrlyQty a, s, h

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

DaMwpDlyAmt a, s, d = ∑c

DaMwpCpAmt a, s, c

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


DaMwpAoAmt a, m, d = ∑s

DaMwpDlyAmt a, s, d

(7) 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:

DaMwpMpAmt m, d = ∑a

DaMwpAoAmt a, m, d

(8) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates DA Market Make-Whole Payment $ per DA Market Make-Whole-Payment Eligibility Period for each Asset Owner as follows:

(a) #EqrDaMwpHrlyPrc a, s, c = (-1) * DaMwpCpAmt a, s, c

(b) IF #EqrDaMwpHrlyPrc a, s, c > 0

THEN

#EqrDaMwpHrlyQty a, s, c = 1



Variable Unit Settlement Interval

Definition

DaRegUpAvailHrlyAmt a, h, s $ Hour Day-Ahead Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The Regulation-Up Service Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h. in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Regulation-Up Offer cost in the Hour is equal to the Resources DaRegUpHrlyQty a, z, s, h multiplied by the Resource’s Regulation-Up Offer, in $/MW.

DaRegDnAvailHrlyAmt a, h, s $ Hour Day-Ahead Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The Regulation-Down Service Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h. in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Regulation-Up Offer cost in the Hour is equal to the Resources DaRegUpHrlyQty a, z, s, h multiplied by the Resource’s Regulation-Up Offer, in $/MW.

DaRegUpOffer a, h, s

$/MW Dispatch Interval

Day-Ahead Regulation-Up Service Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Regulation-Up Service Offer associated with AO a’s Resource Settlement Location s for Hour h. Note that this value will be equal to the Regulation-Up Service Offer following Order 755 implementation or the Regulation-Up Offer prior to Order 755 implementation.







Definition

DaRegUpCapOffer a, h, s


Day-Ahead Regulation-Up Service Capability Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Regulation-Up Offer associated with Regulation-Up Service capability associated with AO a’s Resource Settlement Location s for Hour h.

DaOffRegUpHrlyQty a, h, s MW Hour Day-Ahead Cleared Offered Regulation-Up Service Quantity per AO per Settlement Location per Hour - The total quantity of Regulation-Up Service MW represented by AO a’s cleared offered Regulation-Up Service Offers in the DA at Resource Settlement Location s for Hour h, as described under Section 4.3.1.3(1)(c)(i) .

DaSpinAvailHrlyAmt a, h, s, c $ Hour Day-Ahead Spin Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The Spinning Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Spinning Reserve Offer cost in the Hour is equal to the Resources DaSpinHrlyQty a, z, s, h multiplied by the Resource’s Spinning Reserve Offer, in $/MW.

DaOffSpinHrlyQty a, h, s MW Hour Day-Ahead Cleared Offered Spinning Reserve Quantity per AO per Settlement Location per Hour - The total quantity of Spinning Reserve MW represented by AO a’s cleared offered Spinning Reserve Offers in the DA Market at Resource Settlement Location s for Hour h, as described under Section 4.3.1.3(1)(c)(ii) .



Definition

DaSuppAvailHrlyAmt a, h, s, c $ Hour Day-Ahead Supplemental Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The Supplemental Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Supplemental Reserve Offer cost in the Hour is equal to the Resources DaSuppHrlyQty a, z, s, h multiplied by the Resource’s Supplemental Reserve Offer, in $/MW.

DaRegUpforCRSubAvailHrlyAmt a, s, h, c $ Dispatch Interval

Day-Ahead Cleared Substituted Regulation-Up Service for Contingency Reserve Offer Cost Amount per AO per Settlement Location per Hour in the DA Market Make-Whole-Payment Eligibility Period – The cost of the quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the DA Market on AO a’s Resource at Settlement Location s for Hour h.

DaOffSuppHrlyQty a, h, s MW Hour Day-Ahead Cleared Offered Supplemental Reserve Quantity per AO per Settlement Location per Hour - The total quantity of Supplemental Reserve MW represented by AO a’s cleared offered Supplemental Reserve Offers in the DA Market at Resource Settlement Location s for Hour h, as described under Section 4.3.1.3(1)(c)(iii) .

DaRegUpforCRSubHrlyQty a, s, h MW Hour Day-Ahead Cleared Substituted Regulation-Up Service for Contingency Reserve MW Amount per AO per Settlement Location per Hour – The MW amount quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the DA Market on AO a’s Resource at Settlement Location s for Hour h.

DaRegUpHrlyQty a, h, s MW Hour Day-Ahead Cleared Operational Regulation-Up Service Quantity per AO per Settlement Location per Hour - The quantity described in Section 4.5.8.4.



Definition

DaRegDnHrlyQty a, h, s MW Hour Day-Ahead Cleared Regulation-Down Service Quantity per AO per Settlement Location per Hour - The quantity described in Section 4.5.8.5.

DaRegDnOffer a, h, s $/MW Dispatch Interval

Day-Ahead Regulation-Down Service Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Regulation-Down Service Offer associated with AO a’s Resource Settlement Location s for Hour h.

DaSpinOffer a, h, s $/MW Dispatch Interval

Day-Ahead Spin Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Spinning Reserve Offer associated with AO a’s Resource Settlement Location s for Hour h.

DaSuppOffer a, h, s $/MW Dispatch Interval

Day-Ahead Supplemental Offer per AO per Resource Settlement Location per Dispatch Interval in DA Market Make-Whole-Payment Eligibility Period – The Supplemental Reserve Offer associated with AO a’s Resource Settlement Location s for Hour h.


4.5.9.4 Real-Time Regulation-Up Service Amount


Variable

Unit

Settlement Interval

Definition

RtRegUp5minQty a, z, s, i MW Dispatch Interval

Real-Time Cleared Operational Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Regulation-Up Service MW represented by AO a’s cleared operational Regulation-Up Service Offers in the RTBM in the Reserve Zone z that includes Resource Settlement Location s, for Dispatch Interval i, as described under Section 4.4.2.4(3)(b)(i).

EqrRtRegUp5minQty a, s, i

MWh Dispatch

Interval Real-Time Electric Quarterly Reporting net Regulation-Up Service Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM RtRegUp5minQty a, z, s, i Regulation-Up sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead in Dispatch Interval i or AO a’s RTBM RtRegUp5minQty a, z, s, i Regulation-Up purchase at Resource Settlement Location s created when the cleared Real-Time RtRegUp5minQty a, z, s, i Regulation-Up is less than the amount cleared Day-Ahead in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.

DaRegUpHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Operational Regulation-Up Service Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.4








4.5.9.6 Real-Time Spinning Reserve Amount


Variable

Unit

Settlement Interval

Definition

RtSpin5minQty a, z, s, i MW Dispatch Interval

Real-Time Cleared Operational Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Spinning Reserve represented by AO a’s cleared operational Spinning Reserve Offers in the RTBM in the Reserve Zone z that includes Resource Settlement Location s, for Dispatch Interval i, as described under Section 4.4.2.4(3)(b)(ii).

EqrRtSpin5minQty a, s, i

MWh Dispatch

Interval Real-Time Electric Quarterly Reporting net Spinning Reserve Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM RtSpin5minQty a, z, s, iSpinning Reserve sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead in Dispatch Interval i or AO a’s RTBM RtSpin5minQty a, z, s, iSpinning Reserve purchase at Resource Settlement Location s created when the cleared Real-Time RtSpin5minQty a, z, s, iSpinning Reserve is less than the amount cleared Day-Ahead in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.

DaSpinHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Operational Spinning Reserve Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.6


4.5.9.7 Real-Time Supplemental Reserve Amount


Variable

Unit

Settlement Interval

Definition

RtSupp5minQty a, z, s, i MW Dispatch Interval

Real-Time Cleared Operational Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Supplemental Reserve represented by AO a’s cleared operational Supplemental Reserve Offers in the RTBM in the Reserve Zone z that includes Resource Settlement Location s, for Dispatch Interval i, as described under Section 4.4.2.4(3)(b)(iii).

EqrRtSupp5minQty a, s, i

MWh Dispatch

Interval Real-Time Electric Quarterly Reporting net Supplemental Reserve Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM RtSupp5minQty a, z, s, i Supplemental Reserve sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead in Dispatch Interval i or AO a’s RTBM RtSupp5minQty a, z, s, iSupplemental Reserve purchase at Resource Settlement Location s created when the cleared Real-Time RtSupp5minQty a, z, s, i Supplemental Reserve is less than the amount cleared Day-Ahead in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.

DaSuppHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Operational Supplemental Reserve Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.7

Formatted: Font: Italic


4.5.9.8 RUC Make-Whole-Payment Amount

1.(1) The RUC Make-Whole-Payment Amount is a credit or charge2 to a Resource Asset Owner and is calculated for each Resource with a RUC Commitment Period that was committed by SPP with an RTBM Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1. Asset Owners of Resources committed by a local transmission operator to address a Local Emergency Condition are eligible to receive a RUC make whole payment, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a RUC make whole payment. For such eligible local transmission operator commitments, a manual process is employed for the calculations and the make-whole-payments will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. . A payment is made to the Resource Asset Owner when the sum of the Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy Offer Curve and Operating Reserve Offer costs associated with actual MWh amounts for Energy and cleared RTBM Operating Reserve is greater than the Energy and Operating Reserve RTBM revenues received for that Resource over the Resource’s RUC Make-Whole-Payment Eligibility Period. Recovery of such compensation shall be collected in accordance with Section 8.6.7 of Attachment AE.

2.(2) A Resource’s RUC Make-Whole-Payment Eligibility Period is equal to the Resource’s RUC Commitment Period except as described below:

1.(a) As shown in Exhibit 4-25, for Resources with a RUC Commitment Period that begins in one Operating Day and ends in the next Operating Day, two RUC Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last Dispatch Interval of the first Operating Day. The second period begins in the first Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated with the Resource’s RUC De-Commit Time.



Formatted: Numbered + Level: 1 +Numbering Style: a, b, c, … + Start at: 1 +Alignment: Left + Aligned at: 0.25" + Indentat: 0.5", Tab stops: Not at 0.5"


Exhibit 4-1: RUC Make-Whole Payment Eligibility Period – Multiple Operating Days

2.(3) The following cost recovery eligible rules apply to each RUC Make-Whole-Payment Eligibility Period. Resource production costs are calculated using the RTBM Offer prices in effect at the time the commitment decision was made for start-up, no-load, and minimum-energy; and the RTBM Offer prices in effect at the solving of a dispatch interval for incremental energy, Regulation-Up, Regulation-Down, Spin, and Supplement Reserves.

1.(a) If SPP cancels a start-up order prior to the start of the associated RUC Make-Whole-Payment Eligibility Period and the Resource is not a Synchronized Resource, the Asset Owner will receive reimbursement for a time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset Owners may request additional compensation through submittal of actual cost documentation to the 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.

2.(b) In order to receive Start-Up Offer recovery within a RUC Make-Whole-Payment Eligibility Period, the Resource must be a Synchronized Resource for at least one Dispatch Interval in the RUC Make-Whole Payment Eligibility Period.

3.(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the RUC Make-Whole Payment Eligibility Period, the Resource must be a Synchronized Resource in that Dispatch Interval.

Operating Day 1 Operating Day 2

RUC Commitment

Period

Time

Real-Time Make-Whole Payment Eligibility Period



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4.(d) There may be more than one RUC Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single RUC Make-Whole Payment Eligibility Period is contained within a single Operating Day.

5.(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the following RUC Make-Whole Payment Eligibility Periods:

1.(i) Any RUC Make-Whole Payment Eligibility Period that is adjacent to the end of a DA Market Make-Whole Payment Eligibility Period;

2.(ii) Any RUC Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s RUC Commit Time less the Resource’s Sync-To-Min Time; and

3.(iii)Any RUC Make-Whole Payment Eligibility Period resulting from a RUC Commitment Period that contains an hour for which the Resource Commitment Status is Self-Commit.

6.(f) For each RUC Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time multiplied by 12 rounded down to the nearest whole interval or (2) 24 Hours multiplied by 12, and that portion of the Start-Up Offer is included as a cost in each interval of the RUC Make-Whole Payment Eligibility Period until the sum of these interval costs are equal to the RTBM Start-Up Offer or until the end of the RUC Make-Whole Payment Eligibility Period, whichever occurs first.

7.(g) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the last RUC Make-Whole Payment Eligibility Period in the Operating Day, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the first RUC Make-Whole Payment Eligibility Period of the following Operating Day provided that the Resource has not been committed in the DA Market in any hour of the first RUC Make-Whole Payment Eligibility Period as described in (h) below. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $12,000. The RUC Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For RUC Make-Whole Payment calculation purposes, the RUC Commitment Period is split into two separate RUC Make-Whole Payment Eligibility Periods as described in (2).a above. The first RUC Make-Whole Payment Eligibility

Formatted: Indent: Left: 0.31", Hanging: 0.38", Numbered + Level: 1 + Numbering Style:a, b, c, … + Start at: 1 + Alignment: Left +Aligned at: 0.06" + Tab after: 0.31" + Indentat: 0.31", Tab stops: Not at 0.31" + 0.5"

Formatted: Indent: Left: 0.44", Numbered +Level: 1 + Numbering Style: a, b, c, … + Startat: 1 + Alignment: Left + Aligned at: 0.06" +Tab after: 0.31" + Indent at: 0.31", Tab stops:Not at 0.5"


Period will include $100/interval of Start-Up Offer costs ($12,000 / 120 intervals) in hour 23 and 24 intervals. The second RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs in hours 1 through 8 intervals.

8.(h) If the Resource has been committed in the DA Market in a period adjacent to and following a RUC Make-Whole Payment Eligibility Period to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the Day-Ahead Make-Whole Payment Eligibility Period.

9.(4) The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for a given RUC Make-Whole Payment Eligibility Period is calculated as follows:

#RtMwpCpAmt a, s, c = ( CncldStartAmt a, s, c

+ Max (0, ( { IF ( CncldStartRatio a, s, c = 0, THEN 1, ELSE 0) }

* ∑i

{ RtStartUpElig5minFlg a, s, i, c * RtStartUp5minAmt a, s, i, c

+ RtRucComStat5minFlg a, s, i, c * [ RtMwpCost5minAmt a, s, i, c

+ RtMwpRev5minAmt a, s, i, c

+ RtOom5minAmt a, s, i + RtRegAdj5minAmt a, s, i

– RtURDAdj5minAmt a, s, i, c – RtStatusAdj5minAmt a, s, i, c

– RtLimitAdj5minAmt a, s, i, c ] } ) ) ) * (-1)

Where,

(a) #RtMwpCost5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c *

( RtIncrEn5minAmt a, s, i

+ Max ( 0, [ RtNoLoad5minAmt a, s, i, c

- IF (DaClrdHrlyQty a, s, h < 0, THEN DaNoLoadHrlyAmt a, s, h, c , ELSE 0 ) ] )

+ RtMinEn5minAmt a, s, i, c



+ RtRegUpAvail5minAmt a, s, i, c +

RtRegDnAvail5minAmt a, s, i, c

+ RtSpinAvail5minAmt a, s, i, c + RtSuppAvail5minAmt a, s, i, c

+ RtRegUpforCRSubAvail5minAmt a, s, i, c ) / 12

(a.1) IF ABS (DaClrdHrlyQty a, s, h ) > = ABS ( RtBillMtr5minQty a, s, i )

THEN

RtIncrEn5minAmt a, s, i = 0

ELSE

#RtIncrEn5minAmt a, s, i = ∫y

x

CurveOffer Energy Dispatched As RTBM

Where:

X = Max (ABS (DaClrdHrlyQty a, s, h ), RtEffMin5minQty a, s, i )

AND

IF ControlStatus5minFlg a, s, i = “Regulating”

THEN

RtEffMin5minQty a, s, i = Min (

RtComMinRegCapOL5minQtya, s, i ,

RtDispMinRegCapOL5minQtya, s, i ,

Max (0, (-1) * RtBillMtr5minQtya, s, i )

ELSE



RtComMinEconCapOL5minQtya, s, i ,

RtDispMinEconCapOL5minQtya, s, i ,


AND

Y = Max ( (-1) * RtBillMtr5minQtya, s, i , 0)

(a.2) IF ABS (DaClrdHrlyQty a, s, h ) > 0

THEN

RtMinEn5minAmt a, s, i, c = 0

ELSE

# RtMinEn5minAmt a, s, i, c =

∫i s, a,inQty RtEffMin5m

0

CurveOffer Energy Committed As RTBM

(a.3) If RtOffRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, c, i

THEN


RtRegUpAvail5minAmt a, s, i, c =

Max ( 0, [ RtRegUp5minQty a, z, s, i - ∑z

DaRegUpHrlyQty a, z, s, h] )

* RtRegUpOffer a, s, i, c

ELSE

RtRegUpAvail5minAmt a, s, i, c =0

(a.4) If RtRegDn5minQty a, s, i > RtFixedRegDn5minQty a, s, c, i

THEN

RtRegDnAvail5minAmt a, s, i, c =

Max ( 0, [ RtRegDn5minQty a, z, s, i - ∑z

DaRegDnHrlyQty a, z, s, h] )

* RtRegDnOffer a, s, i, c

ELSE

RtRegDnAvail5minAmt a, s, i =0

(a.5) If RtOffSpin5minQty a, s, i > RtFixedSpin5minQty a, s, c, i

THEN

RtSpinAvail5minAmt a, s, i, c =

Max ( 0, [ RtOffSpin5minQty a, z, s, i - ∑z

DaOffSpinHrlyQty a, z, s, h] )


* RtSpinOffer a, s, i, c

ELSE

RtSpinAvail5minAmt a, s, i =0

(a.6) If RtOffSupp5minQty a, s, i > RtFixedSupp5minQty a, s, c, i

THEN

RtSuppAvail5minAmt a, s, i, c =

Max ( 0, [ RtOffSupp5minQty a, z, s, i - ∑z

DaOffSuppHrlyQty a, z, s, h] )

* RtSuppOffer a, s, i, c

ELSE

RtSuppAvail5minAmt a, s, i =0

(a.7) If RtOffRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, c, i

THEN

RtRegUpforCRSubAvail5minAmt a, s, i, c

= RtRegUpforCRSub5minQty a, i, s * RtRegUpCapOffer a, s, i

ELSE

RtRegUpforCRSubAvail5minAmt a, s, i, c = 0

(a.7.1) RtRegUpforCRSub5minQty a, s, i =

RtOffRegUp5minQty a, i, s - RtRegUp5minQty a, i, s


- DaRegUpforCRSubHrlyQty a, h, s

(b) #RtMwpRev5minAmt a, s, i, c =

RtRucComStat5minFlg a, s, i, c * [ ( ( RtLmp5minPrc s, i

* Min (0, [ RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h ] ) ) / 12 )

+ RtRegUpRev5minAmt a, s, i, c + RtRegDnRev5minAmt a, s, i, c

+ RtSpinRev5minAmt a, s, i, c + RtSuppRev5minAmt a, s, i, c ]

(b.1) RtRegUpRev5minAmt a, s, i, c =

(-1) * RtRucComStat5minFlg a, s, i, c

* ( Max ( 0, [ RtRegUp5minQty a, z, s, i - ∑z


* RtRegUpMcp5minPrc z, i ) / 12

(b.2) RtRegDnRev5minAmt a, s, i, c =


*( Max ( 0, [ RtRegDn5minQty a, z, s, i - ∑z


* RtRegDnMcp5minPrc z, i ) / 12

(b.3) RtSpinRev5minAmt a, s, i, c =



*( Max ( 0, [ RtSpin5minQty a, z, s, i - ∑z

DaSpinHrlyQty a, z, s, h ] )

* RtSpinMcp5minPrc z, i ) / 12

(b.4) RtSuppRev5minAmt a, s, i, c =


*( Max ( 0, [ RtSupp5minQty a, z, s, i - ∑z

DaSuppHrlyQty a, z, s, h ] )

* RtSuppMcp5minPrc z, i ) / 12

(c) #CncldStartAmt a, s, c =

∑i

( RtStartUp5minAmt a, s, i, c * RtStartUpElig5minFlg a, s, i, c )

* CncldStartRatio a, s, c

CncldStartRatio a, s, c = (ElapsedTime a, s, c / StartUpTime a, s, c )

(d) In any Dispatch Interval in which the Resource has operated outside of its Operating Tolerance and that Resource has not been exempted from URD per Section 4.4.4.1, any incremental Energy costs associated with actual Energy output above the Resource’s Desired Dispatch is not eligible for recovery. The URD adjustment is calculated as follows:

IF ABS (URD5minQty a, s, i ) > ResOpTol5minQty a, s, i AND

( XmptDev5minFlg a, s, i = 0 )

THEN


#RtURDAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c

* Max ( 0, ( RtIncrEn5minAmt a, s, i – RtDesiredEn5minAmt a, s, i )) / 12

ELSE

RtURDAdj5minAmt a, s, i, c = 0

(d.1) URD5minQty a, s, i =

Max ( RtBillMtr5minQty a, s, i * (-1), 0 ) - RtAvgSetPoint5minQty a, s, i

(d.2) ResOpTol5minQty a, s, i =

Min ( URDMaxTol5minQty i , Max (URDMinTol5minQty i ,

URDTol5minPct i * RtDispMaxEmerCapOL5minQty a, s, i ) )

(d.3) IF RtDesiredEn5minQty a, s, i < ABS (DaClrdHrlyQty a, s, h )

THEN

#RtDesiredEn5minAmt a, s, i = RtIncrEn5minAmt a, s, i

ELSE

#RtDesiredEn5minAmt a, s, i = ∫y

x


Where:

X = Max (ABS (DaClrdHrlyQty a, s, h ) , RtEffMin5minQty a, s, i )

Y = Max ( X, RtDesiredEn5minQtya, s, i )

(e) In any Dispatch Interval in which a Resource is in “Manual” status, any incremental Energy costs associated with actual Energy output above the Resource’s Desired Dispatch is not eligible for recovery. The status change adjustment is calculated as follows:


IF ControlStatus5minFlg a, s, i = “Manual”

AND ABS (URD5minQty a, s, i ) <= ResOpTol5minQty a, s, i

THEN

#RtStatusAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c


ELSE

RtStatusAdj5minAmt a, s, i, c = 0

(f) In any Dispatch Interval in which a Resource has increased its Minimum Economic Capacity Operating Limit (or its Minimum Regulation Capacity Operating Limit if the Resource has cleared for Regulation-Up or Regulation-Down) above the Resource’s minimum limits used by SPP in the commitment decision or the minimum limits used to move from one configuration to another in the case of a Combined Cycle Resource, the Resource is not in “Manual” status and the increase in minimum limit is greater than the Resource’s Operating Tolerance, any incremental Energy costs associated with actual Energy output above the Resource’s Desired Dispatch is not eligible for recovery. The limit change adjustment is calculated as follows:

IF ControlStatus5minFlg a, s, i < > “Regulating” AND

ControlStatus5minFlg a, s, i < > “Manual” AND

( RtDispMinEconCapOL5minQty a, s, i

- RtComMinEconCapOL5minQty a, s, i ) > ResOpTol5minQty a, s, i AND

ABS (URD5minQty a, s, i ) <= ResOpTol5minQty a, s, i

THEN

#RtLimitAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c

* Max ( 0, ( RtIncrEn5minAmt a, s, i – RtDesiredEn5minAmt a, s, i ) / 12


ELSE IF

ControlStatus5minFlg a, s, i = “Regulating” AND

( RtDispMinRegCapOL5minQty a, s, i

- RtComMinRegCapOL5minQty a, s, i ) > ResOpTol5minQty a, s, i AND

ABS (URD5minQty a, s, i ) < =ResOpTol5minQty a, s, i

THEN



ELSE

RtLimitAdj5minAmt a, s, i, c = 0

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

RtMwpDlyAmt a, s, d = ∑c

RtMwpCpAmt a, s, c

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

RtMwpAoAmt a, m, d = ∑s

RtMwpDlyAmt a, s, d

(1)(7) 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:

RtMwpMpAmt m, d = ∑a

RtMwpAoAmt a, m, d




(8) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates RUC Make-Whole Payment $ per RUC Make-Whole-Payment Eligibility Period for each Asset Owner as follows:

(a) #EqrRtMwp5minPrc a, s, c = (-1) * RtMwpCpAmt a, s, c

(b) IF #EqrRtMwp5minPrc a, s, c > 0

THEN

#EqrRtMwp5minQty a, s, c = 1



Variable

Unit

Settlement Interval

Definition

RtOffRegUp5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Offered Regulation-Up Service Quantity per AO per Settlement Location per Hour - The total quantity of Regulation-Up Service MW represented by AO a’s cleared offered Regulation-Up Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4(3)(a)(i).

RtRegUp5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Operational Regulation-Up Service Quantity per AO per Settlement Location per Hour –The value described under Section 4.5.9.4.

RtRegUpOffer a, s, i, c

(Not Available on Settlement Statement)


Real-Time Regulation-Up Service Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Regulation-Up Service Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c. Note that this value is equal to the Regulation-Up Service Offer following FERC Order 755 implementation or is equal to the Regulation-Up Offer prior to Order 755 implementation.

RtRegDnOffer a, s, i, c (Not Available on Settlement Statement)


Real-Time Regulation-Down Service Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Regulation-Down Service Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.






Variable

Unit

Settlement Interval

Definition

RtSpinOffer a, s, i, c (Not Available on Settlement Statement)


Real-Time Spinning Reserve Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Spinning Reserve Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.

RtSuppOffer a, s, i, c (Not Available on Settlement Statement)


Real-Time Supplemental Reserve Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Supplemental Reserve Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.

RtRegUpCapOffer a, s, i

$/MW Dispatch

Interval Real-Time Regulation-Up Offer per AO per Resource Settlement Location per Dispatch Interval– The Regulation-Up Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i.

RtOffSpin5minQty a, s, i, c MW Dispatch Interval

Real-Time Cleared Offered Spinning Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The total quantity of Spinning Reserve MW represented by AO a’s cleared offered Spinning Reserve Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4(3)(a)(ii).

RtOffSupp5minQty a, s, i, c MW Dispatch Interval

Real-Time Cleared Offered Supplemental Reserve Quantity per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The total quantity of Supplemental Reserve MW represented by AO a’s cleared Offered Supplemental Reserve Offers in the RTBM at Resource Settlement Location s for Dispatch Interval i, as described under Section 4.4.2.4(3)(a)(iii).


Variable

Unit

Settlement Interval

Definition

RtRegUpforCRSubAvail5minAmt a, s, i, c $ Dispatch Interval

Real-Time Cleared Substituted Regulation-Up for Contingency Reserve Offer Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The cost of the quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the RTBM on AO a’s Resource at Settlement Location s for Dispatch Interval i.

RtRegUpforCRSub5minQty a, s, i MW Dispatch Interval

Real-Time Cleared Substituted Regulation-Up for Contingency Reserve MW Amount per AO per Settlement Location per Dispatch Interval – The MW amount quantity of Regulation-Up Service cleared to meet the Contingency Reserve requirement in the RTBM on AO a’s Resource at Settlement Location s for Dispatch Interval i.

DaRegUpforCRSubHrlyQty a, h, s MW Hour Day-Ahead Cleared Substituted Regulation-Up Service for Contingency Reserve MW Amount per AO per Settlement Location per Hour – The quantity described in Section 4.5.8.12.


4.5.9.9 Real-Time Out-Of-Merit Amount


Variable

Unit

Settlement Interval

Definition

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.


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.

4.5.9.10 RUC Make-Whole-Payment Distribution Amount


Variable

Unit

Settlement Interval

Definition

DaRegUpHrlyQty a, z, s, h MW Hour Day-Ahead Operational Regulation-Up Service Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.4.





4.5.9.15 Real-Time Regulation Non-Performance Amount


Variable

Unit

Settlement Interval

Definition


Real-Time Cleared Operational Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.4.

DaRegUpHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Operational Regulation-Up Service Quantity per AO per Settlement Location per Hour - The value described under Section 4.5.8.4.




Proposed Tariff Language Revision

N/A

Proposed Criteria Language Revision

N/A


Staff Support for Market Working Group Initiativ

Title

Manage the MPRR Process

Support the MWG

MOTF-2014

Support Project Pinnacle implementation

Support the Integrated System (IS) integration into SPP

TCR Outage Coordination Sub-Group

MPRR194-Mitigation Tests for Manual Commitments

Manual Commitments

Quick Start Resource Sub-Group

Over Collected Losses Allocation



Must Offer analysis

MPRR215-Product Substitution Cost Calculation

Maximum Capacity of Zero for Wind Resources

Price Volatility MWP

Price Volatility MWP

MPRR181-Mirrored JOU Share Option

Ramp Product

Market-to-Market

Hubs Activity

Turn-Around-Ramp-Rate-Factor (TARRF)Modify definition of a commitment period

ves

Description Rank RatingReview and post new MPRRs. Create Recommendations Reports. Manage the Impact Analysis process. Review and post comments. Present MPRRs to ORWG and RTWG. Facilitate SPP internal review of the changes. Update the Protocols after MPRRs are approved. Ensure the Tariff changes are scheduled for filing and software changes are scheduled for implementation.

High

Prepare meeting agendas. Develop, review and coordinate background materials. Prepare meeting minutes and manage the action item list. Prepare MOPC background materials.

High

Support the Mitigated Offer Task Force. High

Represent Market Design in the implementation efforts for Regulation Compensation, LTCRs, Market-to-Market, and Enhanced Combined Cycle.

High

Represent Market Design in the efforts to integrate the Integrated System (IS) of WAPA, Basin, Heartland and other associated entities into the SPP Marketplace.

High

SPP Market Design Staff will lead an effort to convene a sub group of MWG Members and MPs to gather concerns regarding the SPP outage coordination processes and related TCR processes; and to propose possible short-term and long-term solutions to address the concerns, including bringing proposed SPP Criteria changes to the ORWG.

High

The purpose of this revision is to relax the mitigation conduct test threshold for manually committed resources and to restrict the presumption of local market power for manual commitments to those commitments for local reliability. The intention of the 10% threshold for manual commitments is to ensure that Resources that must be committed to relieve a local reliability issue cannot take advantage of their local market power in that situation. SPP did not anticipate that many manual commitments would occur for other reasons when designing the mitigation process.

High

Based on discussion during the RTO Marketplace Update, particularly the Manual Commitment observations, SPP Staff will work on an MPRR to better define and distinguish all of the different manual commitments that currently happen; for example, do not include operator overrides as a manual commitment.

High

SPP Market Design staff will facilitate discussion on QSR logic with stakeholders for the September 2014 MWG meeting.

High

Remove BSS from the Over Collected Lossess distribution. High

Regarding Real-Time Over-Collected Losses, SPP Staff to document and publish all data that goes into the Rebate Factors – both Day-Ahead and Real-Time.

High

Regarding Real-Time Over-Collected Losses, SPP Staff to document and present the process for defining Hubs and External Interfaces. High

SPP Staff to evaluate and analyze the Must Offer design currently in production in Marketplace and bring results and findings to the October 2014 MWG meeting. High

The availability cost calculations for Regulation-Up, Spinning Reserve and Supplemental Reserve contained within the DA MWP and RUC MWP calculation sections do not calculate costs correctly if a higher quality product was substituted to meet a lower quality product requirement.

High

Request from MWG members to have the ability to set the maximum capacity of Wind Resources to zero instead of .1 when the Wind forecast is zero for the hour.

Medium

Regarding real-time price volatility make-whole payment, SPP Staff will research and report back to MWG on the possible cause of real-time price spikes that have occurred in Marketplace, and the magnitude of the issue across the SPP market footprint.

Medium

During the price volatility examples and discussion, MWG asked SPP Staff to provide examples of Day Ahead Market ramping vs Real-Time ramping. Medium

Regarding MPRR181-Mirrored JOU Share Option, SPP Staff will work with the MPRR author - Cliff Franklin (Westar) - to create comments for further proposed language modifications as needed to propose a solution with the least impact possible, but that still meets the goal of the MPRR where parties in JOUs and PPAs agree to designate one party to submit Marketplace data, but the Marketplace Settlement is separated by party.

Medium

MWG will visit the subject of ramp ancillary product in December 2012. MediumMWG to review the final Market-to-Market design from the Seams SC and JOA, and assess the impact. Medium

SPP Staff will assess the SPP activity (BSS, Virtual, TCR, etc.) on the SPP existing Hubs and report results back to MWG.

Medium

Staff will bring back to MWG a rough impact estimate on options 2 and 3 indicating difficulty of implementation. Option 2 is a system-wide tolerance band for TARRF and 3 Option is an MP-submitted, Resource-specific tolerance band for TARRF.

Medium

Quick Start Resource Logic Enhancement Goals

Quick-Start Resource Sub-Group

Quick-Start Resources (QSRs) – Current Issues

• No registration requirement for QSRs

• No qualification process for QSRs

• No commit status for QSR like in the EIS Market

• RTBM can dispatch QSR below Eco Min

• Min and Max Run Times are not honored

2

Design Enhancement Goals

• Develop market design improvements to enable Market Participants and the Market systems to more effectively use Quick Start Resources

3

Design Changes: Registration and Status

• Create new “Quick Start” commitment status – Enables visibility to SPP Operations

– Subjects the resource to resource plan validation rules

• Create Quick Start Resource qualification process – Ensures resources using QS status are QS capable

• Apply QSR logic only when commitment status = “Quick Start”

4

Logic Enhancement Goals: SCED

5

• QSRs treated as online at all times by SPP systems

• Respect submitted parameters

– Eco Min, Max Run Time, Max Daily Starts, Min Downtime, etc.

– Initial dispatch must be at least equal to the eco min

• Include Start-up and No Load costs in initial dispatch determination

• No URD charges if SPP did not respect minimum.

Logic Enhancement Goals: SCUC

• QSR fleet’s capacity counted in SPP’s total capacity for use in RUC processes

• Not flagged for commitment in DA RUC studies under normal circumstances – QSRs only considered for short lead time commitments

(at least less than 4 hours from start instruction)

– Short lead time commitments result from QRUC studies

6

Logic Enhancement Goals: DA Market

• A DA Market commitment of a QSR only a financial position – QSR is not added into Current Operating Plan

– QSR does not receive START/STOP instructions from a DA Market commitment

• No RUC deviation charges for not meeting the DA Market schedule

7

Quick Reliability Unit Commitment (QRUC)

• Staff is pursuing new functionality in the SPP RUC studies – Minimal impact to systems

• Study window of 2 hours or less – Will yield a shorter study run time

– Closer to real-time pricing

– More extensions Smooth out commitments off the top of the hour

• Benefits QSRs with short lead commitments – QRUC benefits the market as a whole (not specifically

for QSR)

8

Expectation of Enhancement Workload

• Modifying SCUC or SCED to include these enhancements will be significant work – Impacts:

CMT, Markets UI/API, MDB, MCE, MOI, POPs, Settlements, business processes

9

8.4.3.. A new M2M Flowgate shall be subject to a hold-harmless provision for the balance of the current

operating day in which the M2M Flowgate is submitted for coordination by the Monitoring RTO as a

result of a planned outage in the Monitoring RTO’s system as provided below:

a) If the Non-Monitoring RTO’s integrated market flows are below its Firm Flow Entitlement for the

hour, there will be a market-to-market settlement with a payment from the Monitoring RTO to

the Non-Monitoring RTO for the hour.

b) If the Non-Monitoring RTO’s integrated market flows exceed its Firm Flow Entitlement for

the hour, there will be no market-to-market settlement for the hour.

c) Notwithstanding the above provisions, these hold-harmless provisions shall not apply (i.e., a

market-to-market settlement will occur) if the new M2M Flowgate was necessitated by an

unplanned outage (forced, emergency, or urgent) that could not meet normal outage scheduling

timeframes.

Nothing in this section is intended to restrict either Party’s ability to submit new M2M Flowgates for

coordination using the real-time market-to-market coordination procedures.

8.4.4. The settlement provisions, including exceptions, contained in Section 8.4.3 shall also apply for the

next operating day when a new M2M Flowgate is submitted for coordination by the Monitoring RTO, as

a result of a planned outage in the Monitoring RTO’s system, subsequent to the cutoff for data

submission of (i.e., the close of) the Non-Monitoring RTO’s Day-Ahead market.

8.4.5. A new M2M Flowgate shall be subject to a hold-harmless provision for the balance of the current

operating day in which the M2M Flowgate is submitted for coordination by the Monitoring RTO as a

result of a planned outage in the Non-Monitoring RTO’s system as provided below:

a) If the Non-Monitoring RTO’s integrated market flows exceed its Firm Flow Entitlement for the

hour, there will be a market-to-market settlement with a payment from the Non-Monitoring

RTO to the Monitoring RTO for the hour.

b) If the Non-Monitoring RTO’s integrated market flows are below its Firm Flow Entitlement for

the hour, there will be no market-to-market settlement for the hour.

c) Notwithstanding the above provisions, these hold-harmless provisions shall not apply (i.e., a

market-to-market settlement will occur) if the new M2M Flowgate was necessitated by an

unplanned outage (forced, emergency, or urgent) that could not meet normal outage scheduling

timeframes.

d) Notwithstanding the above provisions, these hold-harmless provisions shall not apply (i.e., a

market-to-market settlement will occur) if the planned outage had been previously coordinated

with the Monitoring RTO but the M2M Flowgate was submitted after the beginning of the

current operating day by the Monitoring RTO.

Nothing in this section is intended to restrict either Party’s ability to submit new M2M Flowgates for

coordination using the real-time M2M coordination procedures.

8.4.6. The settlement provisions, including exceptions, contained in Section 8.4.5 shall also apply for the

next operating day when a new M2M Flowgate is submitted for coordination by the Monitoring RTO as

a result of a planned outage on the Non-Monitoring RTO’s system, subsequent to the cutoff for data

submission of (i.e., the close of) the Monitoring RTO’s Day-Ahead market.

Section 8.1.4 would be deleted upon mutual agreement of edits to section 3.1.13


MPRR No. 199 PRR

Title Intra-Day Mitigation Measures Clarifications

Timeline Normal Expedited Urgent Action

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


Approve Reject


Defer Refer

Ranking N/A

Impact Analysis Required Yes, Estimated Cost: Duration: No


Section No.: 8.2.2.3; 8.2.2.4; 8.2.2.5 Title: Mitigation Measures for Energy Offer Curves; Mitigation Measures for Start-Up and No-Load Offers; Mitigation Measures for Operating Reserve Offers Protocol Version: 20.b

Type of Revision Correction/Clean-Up Clarification



MPRR199 proposes to explicitly identify the allowance of more frequent Intra-day Mitigated Offer updates: • Intra-day changes to the Mitigated Energy Offer Curve are allowed if the

Resource is using the Quick-Start Resource Logic • Intra-day changes to the Mitigated Start-Up and No Load Offers are allowed

for: 1. Higher fuel procurement costs due to an extended commitment period 2. Fuel switching for unforeseen operating conditions 3. Resources using Quick-Start Resource logic

• Intra-day changes to the Mitigated Operating Reserve Offers are allowed for: 1. Higher fuel costs due to an extended commitment period 2. Fuel switching due to unforeseen operating conditions 3. Regulation Offers after the DA RUC clears for uncompensated costs



Attachment AF; 3.2 Mitigation Measures for Energy Offers; 3.3 Mitigation Measures for Start-Up and No-Load Offers; 3.4 Mitigation Measures for Operating Reserve Offers

No



No



MWG


Opposed: N/A

Abstained: Xcel


Opposed: N/A

Abstained: Xcel

RTWG

Date of Vote: 10/3/2014 Vote: Approved with modifications

Opposed: N/A

Abstained: TNSK, Xcel

ORWG Date of Vote: 10/3/2014 Vote: Unanimously Approved with no Reliability Impact

MOPC


Opposed: 1

Abstained: 2 Board/Members Committee Date of Vote: Vote:

Date 7/30/2014

Sponsor Name Matthew Johnson E-mail Address [email protected] Company The Energy Authority Phone Number 904.360.1460

Comments Received Comment Author Terry Gates (AEP) Date 8/12/2014

Comment Description

In sections 8.2.2.3(9)(e), 8.2.2.5(11)(d) and the corresponding tariff sections AEP believes the proposed language is too vague. This not only has the potential to give EDRs an unfair market advantage, but it is virtually impossible to monitor effectively for potential abuse. The initial proposed language is too ambiguous and as such is overly burdensome, if not impractical to both market participants and SPP. 1) “intra-day fuel cost” is vague and could lead to second guessing of Market Participant decisions associated with not only day-ahead versus intraday purchase decisions, but also the timing of such decisions, and 2) Actual fuel cost (including imbalance and other charges) is not known until after the fact. AEP offers the following changes to the initial proposed language In sections 8.2.2.3(9), 8.2.2.3(9)(c), 8.2.2.4(11), 8.2.2.2.4(11)(c), 8.2.2.5(11), 8.2.2.5(11)(c) and the corresponding tariff sections.

Comment Status These comments were taken into consideration by the MWG. MWG made some language changes based on these comments at this time.

Comments Received Comment Author Catherine Tyler Mooney (SPP MMU) Date 9/2/2014



Comment Description

The Market Monitoring Unit suggests that the Market Working Group

consider the removal of the intra-day mitigated offer changes for intra-day changes

in fuel costs. This provision would have otherwise allowed Market Participants to

change their mitigated offers with intra-day fuel cost changes greater than 10%.

While the MMU agrees that resources should have mitigated offers that accurately

reflect their costs, these changes correspondingly open up the responsibility to

lower mitigated offers when fuel costs fall. MWG members have expressed

concern with their ability to develop a clear compliance policy with such a provision

in an environment of volatile natural gas prices.

Section 8.2.2.10 of the Protocols (Attachment AF Section 3.8 B of the

Tariff) provides Market Participants with the ability to contact the MMU if their costs

have risen to a point where they anticipate failing the mitigation conduct test. The

MMU may then approve mitigated offer increases to ensure that mitigation is not

applied when it would result in resources clearing below the appropriate cost. The

MMU received several such calls from February 28 to March 4, 2014, allowed for

intra-day mitigated offer changes, and was able to validate the gas prices after the

fact. The process worked smoothly and kept the MMU informed of the critical

situation. For Market Participants that would like to develop an alternative intra-

day fuel pricing policy for mitigated offers, the fuel cost policy may be used to

establish an agreed upon process with the MMU.

Similar issues have arisen around mitigation and intra-day fuel cost

uncertainty in other markets, and the MMU will continue to look for improvements

in this process. In the meantime, the MMU proposes to evaluate the mitigation

conduct thresholds to ensure that they are high enough to cover historical fuel cost

volatility.


Comments Received Comment Author Terry Gates (AEP) Date 9/3/2014

Comment Description

In sections 8.2.2.3(9)(e), 8.2.2.5(11)(d) and the corresponding tariff sections AEP believes the proposed language is too vague. This not only has the potential to give EDRs an unfair market advantage, but it is virtually impossible to monitor effectively for potential abuse. AEP concurs with the SPP Market Monitoring Unit comments regarding intra-day changes in fuel costs. AEP proposes the removal of the same language in the MMU’s comment document and the additional removal of the EDR language based on our comments in the paragraph above. Grammatical changes were made to the Tariff.



Comments Received Comment Author Micha Bailey on behalf of MWG Date 9/29/2014 Comment Description MWG deleted extra “or” in the Tariff.


Comments Received

Comment Author Brenda Fricano on behalf of RTWG Date 10/3/2014

Comment Description RTWG corrected section references and grammar errors in the Protocols and Tariff. RTWG separated out one sentence into two sentences for clarity.

Comment Status


8.2.2.3 Mitigation Measures for Energy Offer Curves

(1) Mitigated energy offer curves shall be submitted on a daily basis by the Market Participant in accordance with the Mitigated Offer Development Guidelines. The mitigated energy offer curve may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource is not committed by the DA Market, the mitigated energy offer curve may be updated until the Day-Ahead RUC process begins. For Resources committed by the DA Market, the mitigated energy offer curve submitted as of 1100 hours on the day before the Operating Day will apply to the DA Market on the day before the Operating Day and the RTBM on the Operating day; for all other Resources the mitigated energy offer submitted at the time the Day-Ahead RUC process begins will apply to the Day-Ahead RUC process on the day before the Operating Day, and the Intra-Day RUC processes and the RTBM on the Operating Day.

(2) The Energy Offer Curve conduct thresholds are as follows: (a) For Resources with local market power as described in Section 8.2.2.7(3), the threshold is

a 10% increase above the Mitigated Energy Offer Curve;

(b) For Resources located in a Frequently Constrained Area and not subject to the threshold in Section 8.2.2.3(1), the threshold is a 17.5% increase above the Mitigated Energy Offer Curve.

(c) For all other Resources the threshold is a 25% increase above the Mitigated Energy Offer Curve.

(3) The Transmission Provider shall apply mitigation measures by replacing the Energy Offer Curve with the Mitigated Energy Offer Curve if:


(a) The Resource’s Energy Offer Curve exceeds the Mitigated Energy Offer Curve by the applicable conduct threshold; and

(b) The Resource has local market power as determined in Section 8.2.2.7; and (c) The Resource either:

(i) Fails the Market Impact Test as described in Section 8.2.2.9, or (ii) Has local market power as described in Section 8.2.2.7(3).

An Energy Offer below $25/MWh will not be subject to mitigation measures for economic withholding.

(4) The Mitigated Energy Offer Curve 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 variable operations and maintenance costs (VOM) as detailed in the Mitigated Offer Development Guidelines. The formula for Mitigated Energy Offer Curves can be found in Appendix G Section 2.5.

(5) Opportunity costs may be reflected in the total fuel related costs and/or the VOM under the following circumstances:

(a) Externally imposed environmental run-hour restrictions; or (b) Physical equipment limitations on the number of starts or run-hours; or (c) Fuel supply limitations.

(6) The Market Participant shall submit heat rates and the methods for determining fuel costs, fuel related costs including emissions costs, opportunity costs, and variable operation and maintenance costs to the Market Monitoring Unit. The information will be sufficient for replication of the Mitigated Energy Offer Curve and shall include, among other data, the following information:

(a) 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.

(b) For emissions costs, Market Participants shall report the emissions rate of each of their units and indicate the applicable emissions allowance cost.

(c) 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 and validation of these costs are included in SPP’s Mitigated Offer Development Guidelines.

(7) For Demand Response Resources with behind the meter generation the Mitigated Energy Offer Curve shall be developed in the same manner, described above, as any other generating Resource. For load response Demand Response Resources, the mitigated Energy Offer Curve


shall reflect the quantifiable opportunity costs associated with the reduction, net of related offsetting increases in usage.

(8) 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 for Energy Offers for Non-Dispatchable Variable Energy Resources will occur.

(9) Intra-day changes to the Mitigated Energy Offer Curve are allowed under the following conditions:

(a) The Market Participant incurs higher fuel procurement costs due to a request by the Transmission Provider for a Resource to remain online past the scheduled commitment period by the DA Market or a RUC process; or

(b) A Resource must switch fuels due to unforeseen operating conditions; (c) The Resource is employing the Quick-Start Resource logic described in Section 4.4.2.3.1

in accordance with Appendix G, Section 6.4. In which case, the Mitigated Energy Offer Curve may be changed after the DA RUC clears on the day before the operating day.

Intra-day changes to the Mitigation Energy Offer Curve must follow the Mitigated Offer Development Guidelines and will be validated by the Market Monitor.

(10) In all cases under this Section 8.2.2.3, cost data submitted for the development of mitigated offers, including additional opportunity cost data, shall be subject to the confidentiality provisions set forth in Section 11 of Attachment AE to the Tariff.

8.2.2.4 Mitigation Measures for Start-Up and No-Load Offers

(1) A Mitigated Start-up Offer and a Mitigated No-load Offer shall be submitted daily by the Market Participant in accordance with the Mitigated Offer Development Guidelines. The Mitigated Start-up and No-load Offers may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource in not committed by the DA Market, the Mitigated Start-up and No-load Offers may be updated until the Day-Ahead RUC process begins. The Mitigated Start-up and No-load Offers submitted at the time the Day-Ahead RUC process begins will apply to the Day-Ahead RUC process on the day before the Operating Day and the Intra-Day RUC processes on the Operating Day.

(2) The Start-Up and No-Load Offer conduct thresholds are as follows:

(a) For Resources with local market power as described in Section 8.2.2.7(3), the threshold is a 10% increase above the mitigated offer for the applicable offer;

(b) For all other Resources the threshold is a 25% increase above the mitigated offer for the applicable offer.

(3) The Transmission Provider shall apply mitigation measures by replacing the Start-Up or No-Load Offer with the applicable Mitigated Start-up or mitigated No-load Offer if:


(a) The Resource’s Start-Up or No-Load Offer exceeds the mitigated offer by the applicable threshold; and

(b) The Resource has local market power as determined in Section 8.2.2.6; and (c) The Resource fails the Market Impact Test as described in Section 8.2.2.9, or the

Resource has local market power as described in Section 8.2.2.6(3).

(4) The mitigated Start-Up Offer shall represent the cost per start as determined from start fuel usage and the costs related to that fuel usage, electrical costs (station service), maintenance costs attributed to starts, and additional labor costs, if required above normal station manning levels. The formula for mitigated Start-Up Offers can be found in Appendix G Section 2.6:

(5) The mitigated Start-Up Offer for Demand Response resources shall be the cost to shut down or curtail load for a given period, which does not vary with output, or the start cost of a behind the meter generator.

(6) The mitigated Start-Up Offer for Variable Energy Resources shall be zero.

(7) The mitigated No-Load Offer shall be the hourly fixed cost required to create a monotonically increasing mitigated Energy Offer Curve. It shall be calculated according to either of two methods found in Appendix G Section 2.7 which are No-Load Fuel Approach and No-Load Cost Approach.

(8) The Mitigated No-Load Offer for behind the meter Demand Response resources shall adhere to the same definition above as a generating Resource. For load response Demand Response Resources, the Mitigated No-Load Offer shall not exceed the quantifiable ongoing hourly costs associated with manufacturing process changes associated with a reduction in load consumption.

(9) The mitigated No-Load Offer for Variable Energy Resources shall be zero.

(10) The Market Participant shall submit documentation of the method for calculating mitigated Start-Up and mitigated No-Load Offers that is adequate to permit the MMU to verify submitted offers. Further details associated with the development of these costs are included in SPP’s Mitigated Offer Development Guidelines.

(11) Intra-day changes to the Mitigated Start-Up and Mitigated No Load Offers are allowed under the following conditions:

(a) The Market Participant incurs higher fuel procurement costs due to a request by the Transmission Provider for a Resource to remain online past the scheduled commitment period by the DA Market or a RUC process;

(b) A Resource must switch fuels due to unforeseen operating conditions; or (a)(c) The Resource is employing the Quick-Start Resource logic described in Section 4.4.2.3.1

in accordance with Appendix G, Section 6.4. Intra-day changes to the Mitigated Start-Up and Mitigated No Load Offers must follow the Mitigated Offer Development Guidelines and will be validated by the Market Monitor.


(11)(12) In all cases under this Section 8.2.2.4, cost data submitted for the development of mitigated offers, including additional opportunity cost data, shall be subject to the confidentiality provisions set forth in Section 11 of Attachment AE to the Tariff.

8.2.2.5 Mitigation Measures for Operating Reserve Offers

(1) A mitigated offer for each Operating Reserve product shall be submitted daily by the Market Participant in accordance with the Mitigated Offer Development Guidelines. The mitigated operating reserve offers may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource is not committed by the DA Market, the mitigated operating reserve offers may be updated until the Day-Ahead RUC process begins. For Resources committed by the DA Market, the mitigated operating reserve offers submitted as of 1100 hours on the day before the Operating Day will apply to the DA Market on the day before the Operating Day and the RTBM on the Operating Day; for all other Resources, the mitigated operating reserve offers submitted at the time the Day-Ahead RUC process begins will apply to the RTBM on the Operating Day.

(2) The offer conduct thresholds for each of the Operating Reserve products are as follows: (a) For Resources with local market power as described in Section 8.2.2.6(3), the threshold is

a 10% increase above the mitigated offer for the applicable Operating Reserve Offer; (b) For all other Resources the threshold is a 25% increase above the mitigated offer for the

applicable Operating Reserve Offer. (3) Any Operating Reserve Offer exceeding the applicable threshold, except offers below $10/MW,

will be deemed excessive. (4) The Transmission Provider shall apply mitigation measures by replacing the relevant Operating

Reserve Offer with the applicable mitigated operating reserve offer if: (a) The Resource’s Operating Reserve Offer exceeds the mitigated offer by the applicable

conduct threshold and; (b) The Resource has local market power as determined in Section 8.2.2.6; and (c) The Resource either:


(5) The mitigated Spinning Reserve Offer shall be equal to zero for Resources other than CTs and Hydro Resource with synchronous condenser capability. No known incremental costs are incurred for providing Spinning Reserves from other resource types. Mitigated Spinning Reserve Offers for CTs and Hydro Resources with synchronous condenser capability are calculated as described in Appendix G, Sections 6 and 7.

(6) The mitigated Supplemental Reserve Offer shall not exceed any fuel related costs and labor costs necessary for the unit to be prepared for deployment. The formula for mitigated Supplemental Reserve Offer can be found in Appendix G Section 2.9.


(7) The mitigated Regulation-Up Offer and Regulation-Down Offer shall not exceed the sum of the cost increase due to:

(a) The heat rate increase during non-steady state operation;

(b) The cost increase in variable operations and maintenance costs due to non-steady state operation; and

(c) Uncompensated costs

The formula for mitigated Regulation-Up and Regulation-Down Offers can be found in Appendix G Section 2.10

(8) Further details associated with the development of the exact costs specified in the formulas above are included in Appendix G.

(9) The Market Participant may include in the calculation of its mitigated Operating Reserve Offer an amount reflecting the Resource-specific opportunity costs if the Market Participant is able to demonstrate to the satisfaction of the SPP Market Monitoring Unit that such costs are legitimate and verifiable and not otherwise included in market outcomes. To the extent such costs include run-time restrictions, such run-time restrictions shall be updated at least weekly with more frequent updating to occur the fewer hours that remain available. The formulas and instructions in the price forecast model for any such opportunity costs shall be determined by the SPP Market Monitoring Unit and published in Appendix G as part of the Mitigated Offer Development Guidelines, updated, as needed, by the SPP Market Monitoring Unit. Opportunity costs for mitigated Operating Reserve Offers shall not include Energy and Operating Reserve Markets revenues associated with forgone Energy or other types of Operating Reserve production to the extent that such costs are included in market outcomes

(10) 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 Operating Reserve Offers and shall include, among other data, the following information:



(c) 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.


(11) Intra-day changes to the Mitigated Operating Reserve Offers are allowed under the following conditions:

(a) The Market Participant incurs higher fuel procurement costs due to a request by the Transmission Provider for a Resource to remain online past the scheduled commitment period by the DA Market or a RUC process;

(b) A Resource must switch fuels due to unforeseen operating conditions; or (c) Intra-day changes to the Mitigated Regulation-Up and Mitigated Regulation-Down

Offers are allowed after the DA RUC clears on the day before the operating day under the following condition: (i) The Resource incurs the uncompensated cost in (7)(c) above, for which the

mitigated offer calculation is described in Appendix G Section 2.10.3.

(11)(12) Intra-day changes to the Mitigated Operating Reserve Offers must follow the Mitigated Offer Development Guidelines and will be validated by the Market Monitor.


Revised Proposed Tariff Language Revision

Attachment AF

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. The mitigated Energy Offer Curve may be updated up to 1100 hours on the

day before the Operating Day 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 1100 hours on the day before

the Operating Day 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 with local market power as described in Section 3.1(3), 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) Has local market power as described in Section 3.1(3).

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 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 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

3)

4) 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 the Market Protocols.

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 and 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.

3.3 Mitigation Measures for Start-Up Offers and No-Load Offers

A mitigated Start-Up Offer and a mitigated No-Load Offer shall be submitted daily by

the Market Participant in accordance with the mitigated offer development guidelines in

the Market Protocols. The mitigated Start-Up and No-Load Offers may be updated up to

1100 hours on the day before the Operating Day for use in the Day-Ahead Market. In the

case a Resource is not committed by the Day-Ahead Market, the Start-Up and No-Load

Offers may be updated until the Day-Ahead RUC begins. The mitigated Start-Up and

No-Load Offers 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 on the

Operating Day.

A. The Start-Up and No-Load Offer conduct thresholds are as follows:


conduct threshold is a 10% increase above the mitigated Start-Up or

mitigated No-Load Offer, as applicable;


mitigated Start-Up or mitigated No-Load Offer, as applicable.


B. The Transmission Provider shall apply mitigation measures by replacing the Start-

Up or No-Load Offer with the applicable mitigated Start-Up or No-Load Offer if:

(1) The Resource’s Start-Up or No-Load Offer exceeds the mitigated Start-Up

or mitigated No-Load Offer, as applicable, by the applicable conduct

threshold; and





C. The mitigated Start-Up Offer shall represent the cost per start as determined from

start fuel usage and the costs related to that fuel usage, Performance Factor cost of

electricity for station use to start (“Station Service”), maintenance costs attributed

to starts, and additional labor costs, if required above normal station staffing

levels. The following formula shall apply to all mitigated Start-Up Offers:

Mitigated Start-Up Offer ($/Start) = [Start Fuel (mmBtu/Start) *

Total Fuel Related Costs ($/mmBtu) * Performance Factor] + [Station

Service (MWh/Start) *

Station Service Rate ($/MWh)] + Start VOM ($/Start) + Start Additional

Labor Cost ($/Start)

The mitigated Start-Up Offer for Demand Response resources shall be the cost to

shut down or curtail load for a given period, which varies with the number of

deployments rather than the amount of response, and/or the start cost of Behind-

The-Meter Generation utilizing the mitigated Start-Up Offer calculation

applicable to other generation Resources as defined above.

The mitigated Start-Up Offer for Variable Energy Resources shall be zero.

D. The mitigated No-Load Offer shall be the hourly fixed cost required to create a

monotonically increasing mitigated Energy Offer Curve. It shall be calculated

according to either of two methods:

(1) No-Load Fuel Approach

Mitigated No-Load Offer ($/hour) = No Load Fuel (mmBtu/hour) *

Performance Factor * (No-Load VOM ($/mmBtu) +

Total Fuel Related Cost ($/mmBtu)

(2) No-Load Cost Approach


Mitigated No-Load Offer ($/hour) =

(Heat Input at Minimum Economic Capacity Operating Limit

(mmBtu) * Performance Factor *

(Total Fuel Related Cost ($/mmBtu) + No Load VOM ($/mmBtu)

) ) –

(Incremental Cost up to Minimum Economic Capacity Operating

Limit ($/MWh) * Minimum Economic Capacity Operating Limit

(MW) )

The mitigated No-Load Offer for Demand Response Resources utilizing

Behind-The-Meter Generation shall adhere to the same definition above as a

generating Resource. For Demand Response Resources utilizing load

reduction, the mitigated No-Load Offer shall not exceed the quantifiable

ongoing hourly costs associated with load reduction.

The mitigated No-Load Offer for Variable Energy Resources shall be zero.

E. The Market Participant shall submit all inputs used in calculating mitigated Start-

Up and mitigated No-Load Offers to permit the Market Monitor to verify

submitted offers. Required information includes: 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. 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. Information to be provided by the Market Participant

shall include the following:









(3) For VOM costs, Market Participants shall submit VOM costs reflecting



Further details associated with the development, validation and updating of these


F. Intra-day changes to the mitigated Start-Up and mitigated No -Load Offers are allowed under the following conditions: 1) In the event that the Transmission Provider requests that a Resource

remain online past their commitment period, the Market Participant may

submit updated mitigated Start-Up and mitigated No-Load Offers that

reflect 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 Start-Up and

mitigated No Load offers as described in Appendix G of the Market

Protocols.

Intra-day changes to the mitigated Start-Up and mitigated No-Load offers must

follow the mitigated offer development guidelines Appendix G of in the Market

Protocols. Any such changes will be validated by the Market Monitor.

G) In all cases under this Section 3.3, cost data submitted for the development of



3.4 Mitigation Measures for Operating Reserve Offers

A mitigated offer for each Operating Reserve product shall be submitted daily by the

Market Participant in accordance with the mitigated offer development guidelines in the

Market Protocols. The mitigated Operating Reserve Offers may be updated up to 1100

hours on the day before the Operating Day for use in the Day-Ahead Market. In the case

a Resource is not committed by the Day-Ahead Market, the mitigated Operating Reserve

Offers may be updated until the Day-Ahead RUC begins. For Resources committed by

the Day-Ahead Market, the mitigated Operating Reserve Offers submitted as of 1100

hours on the day before the Operating Day 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 Operating Reserve Offers submitted at the time the Day-Ahead

RUC begins will apply to the RTBM on the Operating Day.

A. The offer conduct thresholds for each of the Operating Reserve products are as

follows: Attachment 9 - MPRR 199 Recommendation Report.docx 10/21/2014 Page 17 of 21


conduct threshold is a 10% increase above the mitigated offer for the

applicable Operating Reserve Offer;

(2) For all other Resources, the conduct threshold is a 25% increase above the

mitigated offer for the applicable Operating Reserve Offer.

B. Any Operating Reserve Offer exceeding the applicable threshold, except offers

below $10/MWh, will be deemed excessive. The Transmission Provider shall

apply mitigation measures by replacing the Operating Reserve Offer with the

applicable mitigated Operating Reserve Offer if:

(1) The Resource’s Operating Reserve Offer exceeds the applicable mitigated

offer by the conduct threshold; and





C. The mitigated Spinning Reserve Offer shall be equal to zero for Resources other

than combustion turbines, reciprocating engines and hydro Resources operating as

a synchronous condenser. No known incremental costs are incurred for providing

Spinning Reserves from other resource types.

Total mitigated Spinning Reserve Offer for combustion turbines, reciprocating

engines and hydro Resources operating as a synchronous condenser shall not

exceed any additional fuel related costs, maintenance costs and power

consumption costs necessary for the Resource to be prepared for deployment of

Spinning Reserve:

Mitigated Spinning Reserve Offer ($/MW) ≤

(Additional Fuel Cost($/Hr) + Additional Maintenance Cost

($/Hr) + Condensing Power Cost ($/Hr) ) /

Spinning Reserve MW

The mitigated Supplemental Reserve Offer shall not exceed labor costs necessary for the

Resource to be prepared for deployment of Supplemental Reserve:

Mitigated Supplemental Reserve Offer ($/MW) <

Additional Labor Cost($) / Average Supplemental Reserve MW


D. The mitigated Regulation-Up Offer shall not exceed the sum of the cost increase

due to:

(1) the heat rate increase during non-steady state operation,

(2) increase in VOM due to non-steady state operation,

(3) uncompensated costs, as described in the Market Protocols:

Mitigated Regulation-Up Offer ($/MW) <

Cost Increase due to Heat Rate Increase during non-steady state operation

($/MW) +

Cost Increase in VOM ($/MW) + Uncompensated Cost ($/MW)

E. The mitigated Regulation-Down Offer shall not exceed the sum of the cost

increase due to:




Mitigated Regulation-Down Offer ($/MW) <


($/MW) +


Further details associated with the development of the exact costs in the formulas

above are included in the Market Protocols.

F. Intra-day changes to the mitigated Operating Reserve Offers are allowed under the following conditions: 1) In the event that the Transmission Provider requests that a Resource that is

supplying Operating Reserves remain online past their commitment period by the Day-Ahead Market or a RUC process, the Market Participant may submit an updated mitigated Operating Reserve offer curve that reflects the procurement of higher cost fuel;

2) A Resource must switch fuels due to unforeseen operating conditions; or 3) Intra-day changes to the mitigated Regulation-Up and mitigated

Regulation-Down Offers are allowed after the Day-Ahead RUC clears on the day before the Operating Day under the following condition: a. The Resource incurs the uncompensated cost in Section 3.4(D)(3)

of this Attachment AF, for which the mitigated offer calculation is described in Appendix G of the Market Protocols.


Intra-day changes to the mitigated Operating Reserve Offer curve must follow the

mitigated offer development guidelines in Appendix G and Section 8.2.2 of the

Market Protocols. Any such changes will be validated by the Market Monitor.

G) The Market Participant may include in the calculation of its mitigated Operating

Reserve Offer an amount reflecting the Resource-specific opportunity costs if the

Market Participant is able to demonstrate to the satisfaction of the SPP Market

Monitoring Unit that such costs are legitimate and verifiable and not otherwise

included in market outcomes. To the extent such costs include run-time

restrictions, such 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 formulas and instructions in

the price forecast model for any such opportunity costs shall be determined by the



Monitoring Unit. Opportunity costs for mitigated Operating Reserve Offers shall

not include Energy and Operating Reserve Markets revenues associated with

forgone Energy or other types of Operating Reserve production to the extent that

such costs are included in market outcomes.

G-H. 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 Operating Reserve Offers 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.




(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.

HI. In all cases under this Section 3.4, cost data submitted for the development of



Revised Proposed Criteria Language Revision None Submitted.



MPRR No. 201 PRR

Title Dispute Clarification




Approve Reject


Defer Refer

Ranking N/A

Impact Analysis Required Yes, Estimated Cost: Duration: No



Section No.: Disputes Title: 4.5.15 Protocol Version: 20.b




The dispute process outline in the Protocols is old legacy EIS language. The EIS version of disputes had the Market Participant file a dispute on the SPP portal. This new language outlines what to submit in a dispute through the Request Management System.



Attachment AE Section 10.3 Invoice Disputes

No



No


MWG

Date of Vote: 8/22/2014 Vote: Unanimously Approved

Opposed: N/A

Abstained: N/A


Opposed: N/A

Abstained: N/A

RTWG Date of Vote: 9/24/2014 Vote: Unanimously Approved with Modifications



MOPC Date of Vote: 10/14/2014 Vote: Approved


Date 7/31/2014

Sponsor Name Micha Bailey E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.2522


Comment Description The MWG deleted the bottom portion of the picture of the Request Management System. The bottom portion of the picture contained information that would only be seen by the administrator.



4.5.15 Disputes

A Market Participant may dispute items set forth in any Settlement Statement (initial, final, or resettlement). The dispute must be filed on the Portal using the Request Management System Contents of Notice dispute form as shown in Exhibit 4-28 with the following minimum content:

(1) Statement type (initial, final, resettlement 1-12); (2) Charge type; (3) Estimated dispute amount in dollars; (4) Operating Day; (5) Start interval; (6) End interval; (7) Statement ID; (8) Transmission Customer ; (9) Settlement Location; (10) Long description; and (1) Short description.Request Type;

(2) Subject;

(3) Full Description;



(4) Statement Type;

(5) Charge Type;

(6) Settlement Location;

(7) Operating Day;

(8) Start Interval;

(9) End Interval;

(10) Dispute Amount; and

(11) Proposed Resolution

(11)(12)


Exhibit 4-1: Contents of Notice Dispute Form

Comment [MCB1]: Deleted Picture

Comment [MCB2]: Deleted Picture


Formatted: Font: 8 pt

Comment [MCB3]: Added Picture



Attachment AE

10.3 Invoice Disputes

In the event that a dispute arises between the Market Participant and the Transmission

Provider concerning any initial, final or resettlement Settlement Statements contained within an

invoice that cannot be resolved to the Market Participant’s satisfaction, such disputes shall be

resolved as follows:

(1) In the case of a dispute relating to an initial or final Settlement Statement, the Market

Participant must notify the Transmission Provider within ninety (90) calendar days

following the issue date of the applicable invoice of the items that the Market Participant

wishes to dispute. In the case of resettlement statements, the Market Participant must

notify the Transmission Provider within thirty (30) calendar days following the issue date

of the applicable invoice of the items contained in that statement that the Market

Participant wishes to dispute, which issues must relate to incremental changes in data that

occurred between issuance of the final Settlement Statement and the first (1st)

resettlement statement or between resettlement statements.

The notice of dispute must contain the following minimum information:

• Request Statement Ttype

(initial, final, resettlement 1-12)

• Subject

• Full Description

• Statement Type

• Charge Ttype

• Estimated dispute amount in dollars

Settlement Location

• Operating Day

• Start Iinterval

• End Iinterval

• Dispute Amount

• Proposed Resolution

• Market Participant


• Asset Owner

• Settlement Location

• Long description

• Short description.

(2) If the Transmission Provider determines that additional information is required

concerning a submitted notice of dispute, the Transmission Provider shall notify the

Market Participant no later than thirty (30) days following the date the notice of dispute

was submitted to the Transmission Provider. The Market Participant must then submit

additional information to the Transmission Provider within thirty (30) days in order to

have the notice of dispute considered valid.

(3) The Transmission Provider shall use its best efforts to notify the Market Participant of

approval or denial of the submitted notice of dispute within twenty (20) business days

following the close of the applicable ninety (90) day or thirty (30) day window specified

under Subsection 10.3(1) or Subsection 10.3(2). If the Transmission Provider estimates

that it will take longer than the twenty (20) business day window to analyze a specific

billing dispute, the Transmission Provider shall notify the Market Participant and provide

an estimate of the amount of time required to complete the analysis.

(4) If the Transmission Provider denies a Market Participant’s notice of dispute or the

Market Participant is not satisfied that it is receiving timely consideration of the dispute,

the Market Participant may initiate the dispute resolution procedures specified under

Section 12 of the Tariff.

Proposed Criteria Language Revision N/A



MPRR No. 204 PRR

Title Compliance and Additional Changes FERC Order 755




Approve Reject


Defer Refer

Ranking N/A

Impact Analysis Required Yes, Estimated Cost: In Scope Duration: No



Section No.: 4.2.2; 4.5.4.2; 4.5.7; 4.5.8.12; 4.5.9; 4.5.9.4; 4.5.9.5; 4.5.9.8; 4.5.9.11; 4.5.9.12; 4.5.9.28; 4.5.9.29; 4.5.12; 8.2.5 Title: Offer Submittal; MCP Calculations; FERC Electric Quarterly Reporting; Day-Ahead Make-Whole-Payment Amount; Real-Time balancing Market Settlement; Real-Time Regulation-Up Serivce Amount; Real-Time Regulation-Down Service Amount; RUC Make-Whole-Payment Amount; Real-Time Regulation-Up Service Distribution Amount; Real-Time Regulation-Down Service Distribution Amount; Unused Regulation-Up Mileage Make Whole Payment Amount; Unused Regulation-Down Mileage Make Whole Payment Amount; Revenue Neutrality Uplift Distribution Amount; Offer Caps and Floors Protocol Version: 20.b




Section 4.2.2 – Offer Submittal • Automatically set RTBM regulation mileage offers to Day-Ahead mileages

offers for Resource cleared for Day-Ahead regulation service Section 4.5.4.2 – MCP Calculations • Correct mileage MCP calculations Section 4.5.8.12 – DA MWP • Update for changes to Unused Regulation-Up/Down Mileage MWP Section 4.5.9.4 & 5 – Real-Time Regulation Up/Down Service • remove zonal attributes • add intermediate step in excess amount calculation • add additional EQR calculations Section 4.5.9.8 – RUC MWP • Update for changes to Regulation-Up/Down Unused Mileage MWP Section 4.5.9.28 – Unused Regulation Up Mileage MWP • change Unused Regulation-Up Mileage MWP calculation to split into Day-

Ahead portion and Real-Time portion and account for regulation-up service margin from cleared Day-Ahead and RTBM regulation service as a potential reduction to MWP


Section 4.5.9.29 – Unused Regulation-Down Mileage MWP • change Unused Regulation-Down Mileage MWP calculation to split into Day-

Ahead portion and Real-Time portion and account for regulation-down service margin from cleared Day-Ahead and RTBM regulation service as a potential reduction to MWP

Section 4.5.12 - RNU • Update unused mileage charge type names. 8.2.5 – Offer Caps and Floors Remove references to regulation capability and mileage offers.



Attachment AE Section 1.1 – Definitions • clarifications and corrections Section 4.1 Offer Submittal • (automatically set RTBM mileage offers equal to DA Market mileage offer for

Resource that cleared regulation in DA Market Section 8.3.4 – Market Clearing Price Calculations • Correct mileage MCP calculation Section 8.5.9 – Day-Ahead Make Whole Payment Amount • Update for changes to Unused Regulation-Up/Down Mileage MWP Section 8.6.5 – Reliability Unit Commitment Make Whole Payment Amount • Update for changes to Unused Regulation-Up/Down Mileage MWP Section 8.6.19 – Unused Regulation-Up Mileage Make Whole Payment • change Unused Regulation-Up Mileage MWP calculation to split into Day-

Ahead portion and Real-Time portion and account for regulation-up service margin from cleared Day-Ahead and RTBM regulation service as a potential reduction to MWP

Section 8.6.20 – Unused Regulation-Down Mileage Make Whole Payment • change Unused Regulation-Down Mileage MWP calculation to split into Day-

Ahead portion and Real-Time portion and account for regulation-down service margin from cleared Day-Ahead and RTBM regulation service as a potential reduction to MWP

No



No


MWG


Opposed: N/A

Abstained: AEP, Xcel, OPPD, WR, OGE, Boston Energy, NPPD, LES


Opposed: N/A

Abstained: Xcel



Opposed: N/A

Abstained: Xcel

RTWG

Date of Vote: 10/3/2014 Vote: Approved with modifications

Opposed: N/A

Abstained: Xcel, NPPD ORWG Date of Vote: 10/3/2014 Vote: Unanimously Approve with no Reliability Impact

MOPC


Opposed: 1

Abstained: 7 Board/Members Committee Date of Vote: Vote:

Date 8/1/2014

Sponsor Name Micha Bailey E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.2522

Comments Received Comment Author Micha Bailey (SPP) Date 8/13/2014

Comment Description

Definitions in the Glossary of the Protocols are updated. They now point to the Tariff with updated language in the Tariff. Changes to Unused Regulation-Up Mileage MWP Amount and Unused Regulation-Down Mileage MWP Amount are proposed in these comments. The current redline proposal in MPRR 204 only works for Mileage Factor equal 1.0 and will over allocate unused regulation mileage to RTBM for Mileage Factor less than 1. These comments fix this by making changes to Sections 4.5.9.28 to the DaRegUpUnusedMile5minQty. These comments take the min of the (DaRegUpHrlyQty / RtRegUp5minQty) and then multiples it by the RtRegUpUnusedMile5minQty to get the amnout of DaRegUpUnusedMile5minQty. (same for Reg Down) These comments also clean up various minor clean-up on formula subscripts. Real-Time and Day-Ahead Reg Up/Down, Spin and Supp amounts/quantities were not included in the variable table under section 4.5.9.8 RUC MWP Amount. These comments add those bill determinates to the variable table


Comments Received Comment Author Patti Kelly (SPP) Date 9/8/2014 Comment Description Includes Tariff language changes only – to identify the Tariff language that has



already been filed in compliance with the June 19, 2014 Order in Docket No. ER13-1748 as italicized language for ease of review by the RTWG. Only those proposed revisions that are the subject of MPRR 204 will remain redlined in the Tariff. Order No. 755 was issued by FERC as a result of Docket No. RM11-7 and is entitled Frequency Regulation Compensation in Organized Wholesale Power Markets. By issuing this order, FERC revises its regulations to remedy undue discrimination in the procurement of frequency regulation in organized wholesale electric markets and ensures that providers of frequency regulation receive just and reasonable and not unduly discriminatory or preferential rates. The Commission found that at the time of this order, that current methods for compensating resources for the provision of frequency regulation are unduly discriminatory. Order No. 755 requires RTOs and ISOs to compensate frequency regulation resources based on the actual service provided, including a capacity payment that includes the marginal unit’s opportunity costs and a payment for performance that reflect the quantity of frequency regulation service provided by a resource when the resource is accurately following the dispatch signal.



Comment Description These comments combine Tariff language in previous comments together that were left out. Added language to Attachment AE Section 8.5.9(4)(x) of the Tariff. The new language deals with product substitution. Clear Regulation-Up Service can be used to meet the Contingency Reserve requirement.


Comments Received Comment Author Brenda Fricano on behalf of RTWG Date 9/24/2014

Comment Description

RTWG made the following changes in the Tariff Language: • Section 8.5.9(4)(a)(x): per SPP Staff’s request, RTWG removed all of the

language in (x). This language had been added because of a fix needed to the product substitution logic; that fix was scheduled to go into production on 3/1/15 along with the Regulation Compensation release, but has since been postponed until after 3/1/15. This deleted language will now go into an upcoming MPRR containing all of the proposed language changes for the product substitution fix.

• Section 8.5.9(4)(a): typo correction – added a missing “to”. • Section 8.6.5(4)(a): some formatting changes, typo correction to add a

missing “to”, and some clarifying edits to the new language in paragraph (v).

• Section 8.6.5(4)(b): typo correction to add a missing “to”.




Comment Description MWG changes to the language in Attachment AE Section 8.6.5(4)(v). These changes help clarify that which costs are set to zero.


Comments Received


Comment Description RTWG updated incorrect section references in the Tariff. RTWG also added “all three of these” to the cost reference in Section 8.5.6(4)(a)(v). This will let the reader know that all three of those costs will be set to zero if they are less than or equal to the amount of Operating Reserve.

Comment Status


1. Glossary

Actual Regulation-Down Mileage The sum of the absolute values of actual movements by a Resource with cleared Regulation-Down Service MW in response to Regulation Deployment As defined in the SPP Tariff.

Actual Regulation-Up Mileage

As defined in the SPP TariffThe sum of the absolute values of actual movements by a

Resource with cleared Regulation-Up Service MW in response to Regulation

Deployment.

Instructed Regulation-Down Mileage As defined in the SPP TariffThe sum of the absolute values of instructed movements to a Resource with cleared Regulation-Down Service through Regulation Deployment instructions.

Instructed Regulation-Up Mileage

Comment [MPRR102.1]: MPRR102 awaiting implementation


As defined in the SPP TariffThe sum of the absolute values of instructed movements to a Resource with cleared Regulation-Up Service through Regulation Deployment instructions.

Regulation-Down Mileage Factor

As defined in the SPP TariffA factor determined through historical Regulation Deployment analysis that represents the ratio of cleared Regulation-Down to the observed Regulation-Down mileage created in response to Regulation Deployment instructions. The Regulation-Down Mileage Factor shall initially be set equal to 1.0.

Regulation-Up Mileage Factor As defined in the SPP TariffA factor determined through historical Regulation Deployment analysis that represents the ratio of cleared Regulation-Up to the Instructed Regulation-Up Mileage created in response to Regulation Deployment instructions. The Regulation-Up Mileage Factor shall initially be set equal to 1.0.

4.2.2 Offer Submittal

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

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

(a) If a Resource is cleared for Regulation-Up Service and/or Regulation-Down Service in the Day-Ahead Market, the RTBM Offers for Regulation-Up Mileage and/or Regulation-Down Mileage for that Resource must are set equal those submitted for use in the Day-Ahead Market for that Resource.

…

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


Comment [MCB3]: MPRR102 awaiting implementation




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 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 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, multiplied by the Regulation-Up Mileage Factor. 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, multiplied by the Regulation-Down Mileage Factor. For Resource’s submitting a Regulation-Down Service Dispatch








Comment [WRC13]: Deleted per para 35 of Order 755 Order.


Comment [MCB15]: Deleted per para 35 of Order 755 Order.


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;

…

4.5.7 FERC Electric Quarterly Reporting

In order to assist Market Participants in meeting their FERC Electric Quarterly Reporting (EQR) obligations, SPP has provided the required billing determinants under each applicable charge type These charge types along with the EQR transaction type for the billing determinant provided are summarized in the Exhibit 4-23 below.



Exhibit 4-1: FERC EQR Reporting Billing Determinants Charge Type EQR Transaction Type EQR Reporting

Interval

Day-Ahead Asset Energy DA Market Energy Sale from Resource net of Bilateral Settlement Schedule Hour

Price for DA Market Energy Sale from Resource net of Bilateral Settlement Schedule

Hour

Day-Ahead Non-Asset Energy

DA Market Energy Sale from Export Transaction net of Bilateral Settlement Schedule

Hour

Price for DA Market Energy Sale from Export Transaction net of Bilateral Settlement Schedule

Hour

Day-Ahead Regulation-Up Service

DA Market Regulation-Up Service Sale by Resource by Hour Hour

Price for DA Market Regulation-Up Service Sale by Resource by Hour Hour

Day-Ahead Regulation-Down Service

DA Market Regulation-Down Service Sale by Resource by Hour Hour

Price for DA Market Regulation-Down Service Sale by Resource by Hour Hour

Day-Ahead Spinning Reserve DA Market Spinning Reserve Sale by Resource Hour

Prices for DA Market Spinning Reserve Sale by Resource Hour

Day-Ahead Supplemental Reserve

DA Market Supplemental Reserve Sale by Resource Hour

Prices for DA Market Supplemental Reserve Sale by Resource Hour

Day-Ahead Make-Whole Payment

DA Market Make-Whole-Payment $ by Resource DA Make-

Whole-Payment Eligibility Period

Real-Time Asset Energy

RTBM net Energy transaction from Resource Settlement Location net of Bilateral Settlement Schedule, by Settlement Location Dispatch Interval

Price for RTBM net Energy transaction from Resource Settlement Location net of Bilateral Settlement Schedule, by Settlement Location Dispatch Interval








Charge Type EQR Transaction Type EQR Reporting Interval

Real-Time Non-Asset Energy

RTBM net Energy Sale net of Bilateral Settlement Schedule from External Interface Settlement Location, by Settlement Location Dispatch Interval

Price for RTBM net Energy Sale net of Bilateral Settlement Schedule from External Interface Settlement Location, by Settlement Location Dispatch Interval

Real-Time Regulation-Up Service

RTBM net Regulation-Up Service transaction by Resource Dispatch Interval

Price for RTBM net Regulation-Up Service transaction by Resource Dispatch Interval

RTBM Excess Regulation-Up Mileage transaction by Resource Dispatch Interval

Price for RTBM Excess Regulation-Up Mileage transaction by Resource Dispatch Interval

RTBM Unused Regulation-Up Mileage transaction by Resource Dispatch Interval

Price for RTBM Unused Regulation-Up Mileage transaction by Resource Dispatch Interval

Real-Time Regulation-Down Service

RTBM net Regulation-Down Service transaction by Resource Dispatch Interval

Price for RTBM net Regulation-Down Service transaction by Resource Dispatch Interval

RTBM Excess Regulation-Down Mileage transaction by Resource Dispatch Interval

Price for RTBM Excess Regulation-Down Mileage transaction by Resource Dispatch Interval

RTBM Unused Regulation-Down Mileage transaction by Resource Dispatch Interval

Price for RTBM Unused Regulation-Down Mileage transaction by Resource Dispatch Interval

Real-Time Spinning Reserve RTBM net Spinning Reserve transaction by Resource Dispatch Interval

Price for RTBM net Spinning Reserve transaction by Resource Dispatch Interval

Real-Time Supplemental Reserve RTBM net Supplemental Reserve transaction by Resource Dispatch Interval

Price for RTBM net Supplemental Reserve transaction by Resource Dispatch Interval








Charge Type EQR Transaction Type EQR Reporting Interval

RUC Make-Whole Payment RUC Make-Whole-Payment $ by Resource RUC Make-Whole-Payment Eligibility

Period

Real-Time Out-of-Merit RTBM Out-of-Merit Energy and Operating Reserve $ by Resource Dispatch Interval

Real-Time Regulation Deployment Adjustment

RTBM Regulation Deployment Adjustment $ by Resource Dispatch Interval

Real-Time Unused Regulation-Up Mileage Make Whole Payment

RTBM Unused Regulation-Up Mileage Make Whole Payment MW Quantity and $ by Resource

Dispatch Interval

Real-Time Unused Regulation-Down Mileage Make Whole Payment

RTBM Unused Regulation-Down Mileage Make Whole Payment MW Quantity and $ by Resource Dispatch Interval


4.5.8.12 Day-Ahead Make-Whole-Payment Amount

(1) The Day-Ahead Make-Whole-Payment Amount is a credit or charge1 to a Resource Asset Owner and is calculated for each Resource with an associated DA Market Commitment Period that was committed by SPP with a Day-Ahead Market Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1, or was committed as part of the Multi-Day Reliability Assessment as defined under Section 4.2.6.3. A payment is made to the Resource Asset Owner when the sum of the Resource’s DA Market Start-Up Offer costs, No-Load Offer costs, Transition State Offer costs, Energy Offer Curve and Operating Reserve Offer costs associated with cleared DA Market amounts for Energy and Operating Reserve is greater than the Energy and Operating Reserve DA Market revenues received for that Resource over the Resource’s DA Market Make-Whole-Payment Eligibility Period.

(2) A Resource’s DA Market Make-Whole-Payment Eligibility Period is equal to a Resource’s DA Market Commitment Period except as defined below:

(a) For Resources with an associated DA Market Commitment Period that begins in one Operating Day and ends in the next Operating Day, two DA Market Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the hour that the DA Market Commitment Period begins and ends in the last hour of the first Operating Day. The second period begins in the first hour of the next Operating Day and ends in the last hour of the DA Market Commitment Period.

(3) The following cost recovery eligible rules apply to each DA Market Make-Whole-Payment Eligibility Period. Offer costs are calculated using the DA Market Offer prices in effect at the time the commitment decision was made except under the situation described under Section (b)(i)(1) below.

(a) There may be more than one DA Market Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single DA Market Make-Whole Payment Eligibility Period is contained within a single Operating Day.


Comment [MPRR101.29]: MPRR101 awaiting FERC filing


(b) A Resource’s DA Market Start-Up Offer costs are not eligible for recovery in the following DA Market Make-Whole Payment Eligibility Periods:

(i) Any DA Market Make-Whole Payment Eligibility Period that is adjacent to the end of a RUC Make-Whole Payment Eligibility Period except as described in (1) below;

(1) As described under Section 4.5.9.8(3)(h), to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the adjacent RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the adjacent Day-Ahead Make-Whole Payment Eligibility Period.

(ii) Any DA Market Make-Whole Payment Eligibility Period resulting from a DA Market Commitment Period that contains a DA Market Self-Commit Hour; and

(iii) Any DA Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s DA Market Commit Time less the Resource’s Sync-To-Min Time.

(c) For each DA Market Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s DA Market Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time rounded down to the nearest hour or (2) 24 Hours, and that portion of the Start-Up Offer is included as a cost in each hour of the DA Market Make-Whole Payment Eligibility Period until the sum of these hourly costs are equal to the DA Market Start-Up Offer or until the end of the DA Market Make-Whole Payment Eligibility Period, whichever occurs first.

(d) To the extent that the full amount of the DA Market Start-Up Offer is not accounted for in the last DA Market Make-Whole Payment Eligibility Period in the Operating Day, any remaining DA Market Start-Up Offer costs are carried forward for recovery in the first DA Market Make-Whole Payment Eligibility Period of the following Operating Day. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $10,000. The DA Market Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For DA Market Make-Whole Payment calculation purposes, the DA Market


Commitment Period is split into two separate DA Market Make-Whole Payment Eligibility Periods as described in (2).b above. The first DA Market Make-Whole Payment Eligibility Period will include $1000/hour of Start-Up Offer costs ($10,000 / 10 Hours) in hours 23 and 24. The second DA Market Make-Whole Payment Eligibility Period will include $1000/hour of Start-Up Offer costs in hours 1 through 8.

(e) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at an average Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, such cost is not due to any independent action of the Market Participant and such cost is not incurred during a RUC Make-Whole Payment Eligibility Period. In such cases, the additional costs are equal to the difference between the Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs is limited to the time period defined as the Transition State Time submitted in the Resource Offer.

(4) The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for each hour in a given DA Market Make-Whole Payment Eligibility Period is calculated as follows:

#DaMwpCpAmt a, s, c =

Max (0, ∑h

( DaMwpCostHrlyAmt a, h, s, c + DaMwpRevHrlyAmt a, h, s, c ) ) * (-1)

(a) DaMwpCostHrlyAmt a, h, s, c =

DaStartUpEligHrlyFlg a, h, s, c * DaStartUpHrlyAmt a, h, s, c

+ DaClrdComStatHrlyFlg h, s, c

* [ DaRucRmndrStartUpHrlyAmt a, s, h, c + DaTransitionHrlyAmt a, s, h, c



+ DaCcSpinAdjHrlyAmt a, s, h + DaCcSuppAdjHrlyAmt a, s, h

+ DaNoLoadHrlyAmt a, h, s, c + DaIncrEnHrlyAmt a, h, s, c

+ DaRegUpAvailHrlyAmt a, h, s, c + DaRegDnAvailHrlyAmt a, h, s, c

+ PotDaRegUpMileMwp5minAmt a, s, i

+ PotDaRegDnMileMwp5minAmt a, s, i

+ DaSpinAvailHrlyAmt a, h, s, c + DaSuppAvailHrlyAmt a, h, s, c ]

Where,

#DaIncrEnHrlyAmt a, h, s, c = ∫) s h, a,yQty (DaClrdHlr ABS

0

CurveOffer Energy Market DA

(a.1) IF RtTranistionStateFlg a, s, i = 1 THEN

DaCcSpinAdj5minAmt a, s, i =

IF (RtRucComStat5minFlg a, s, i >= 0, THEN 0, ELSE 1 )

* (DaSpinHrlyAmt a, s, h / 12 + RtSpin5minAmt a, s, i )

ELSE

DaCcSpin5minAmt a, s, h = 0

∑i

∑i


Formatted: Font: Times New Roman Bold,Lowered by 14 pt

Comment [CD32]: Sum to hourly totals. Order 755 Compliance.


Comment [CD33]: Sum to hourly totals

Comment [CD34]: Including these terms (as well as the mileage MWP) accounts for margin already used to diminish the need for a mileage MWP. Order 755 Compliance.


(a.1.1) DaCcSpinAdjHrlyAmt a, s, h =

Max ( 0, ∑i

DaCcSpinAdj5minAmt a, s, i )

(a.2) IF RtTranistionStateFlg a, s, i = 1 THEN

DaCcSuppAdj5minAmt a, s, i =

IF (RtRucComStat5minFlg a, s, i >= 0, THEN 0, ELSE 1 )

* (DaSuppHrlyAmt a, s, h / 12 + RtSupp5minAmt a, s, i )

ELSE

DaCcSupp5minAmt a, s, h = 0

(a.2.1) DaCcSuppAdjHrlyAmt a, s, h =

Max ( 0, ∑i

DaCcSuppAdj5minAmt a, s, i )

(b) DaMwpRevHrlyAmt a, h, s, c = DaClrdComStatHrlyFlg h, s, c

* [ ( DaLmpHrlyPrc s, h * DaClrdHrlyQty a, s, h )

+ DaRegUpHrlyAmt a, h, s + DaRegDnHrlyAmt a, h, s

+ DaRegUpUnusedMileMwp5minAmt a, s, i

+ DaRegDnUnusedMileMwp5minAmt a, s, i

∑i

∑i







+ DaSpinHrlyAmt a, h, s + DaSuppHrlyAmt a, h, s ]


DaMwpDlyAmt a, s, d = ∑c

DaMwpCpAmt a, s, c


DaMwpAoAmt a, m, d = ∑s

DaMwpDlyAmt a, s, d


DaMwpMpAmt m, d = ∑a

DaMwpAoAmt a, m, d

(8) For FERC Electric Quarterly Reporting (EQR) purposes, SPP calculates DA Market Make-Whole Payment $ per DA Market Make-Whole-Payment Eligibility Period for each Asset Owner as follows:

(a) #EqrDaMwpHrlyPrc a, s, c = (-1) * DaMwpCpAmt a, s, c

(b) IF #EqrDaMwpHrlyPrc a, s, c > 0 THEN #EqrDaMwpHrlyQty a, s, c = 1




Definition

DaMwpCpAmt a, s, c $ Eligibility Period

Day-Ahead Make-Whole-Payment Amount per AO per Settlement Location per DA Market Make-Whole-Payment Eligibility Period - The DA Market make-whole amount to AO a for DA Market Make-Whole-Payment Eligibility Period c at Resource Settlement Location s.

DaStartUpHrlyAmt a h, s, c $ Hour Day-Ahead Start-Up Cost Amount per AO per Settlement Location per Hour Per DA Market Make-Whole-Payment Eligibility Period - The DA Market Start-Up Offer associated with AO a’s eligible Resource at Settlement Location s for DA Market Make-Whole-Payment Eligibility Period c that is included in each Hour h of the DA Market Make-Whole-Payment Eligibility Period. This value is calculated by dividing DaStartUpAmt a s, c by the lesser of the Resource’s (DaMinRunTime a, h, s, c ) /60, rounded down to the nearest whole number of hours or 24 hours, except that, if DaMinRunTime a, h, s, c is less than 60 minutes, then DaStartUpAmt a, s, c is divided by 1. These hourly values are carried forward into the following Operating Day, if needed, to ensure recovery of any remaining DaStartUpAmt a s, c.

DaStartUpAmt a s, c


$ Eligibility Period

Day-Ahead Start-Up Cost Amount per AO per Settlement Location per DA Market Make-Whole-Payment Eligibility Period - The DA Market Start-Up Offer associated with AO a’s eligible Resource at Settlement Location s for DA Market Make-Whole-Payment Eligibility Period c.

DaStartUpEligHrlyFlg a, h, s, c None Hour Day-Ahead Start-Up Recovery Eligibility Flag per Resource Settlement Location per DA Market Make-Whole-Payment Eligibility Period – This flag is set equal to 1 in each hour of a DA Market Make-Whole-Payment Eligibility Period where the Resource is eligible to recover start-up costs, or 0 in each hour of the DA Market Make-Whole-Payment Eligibility Period where the Resource is not eligible to recover start-up costs.



Definition

DaClrdComStatHrlyFlg h, s, c None Hour Day-Ahead Commitment Status Hourly Flag per Resource Settlement Location per DA Market Make-Whole-Payment Eligibility Period – This flag is set equal to 1 for each hour of a DA Market Make-Whole-Payment Eligibility Period in which its Commitment Status was “Market” or “Reliability, or 0 if its Commitment Status was “Self”.

DaRucRmndrStartUpHrlyAmt a, s, h, c $ Hour Day-Ahead RUC Remaining Start-Up Offer Amount per Hour per DA Market Make-Whole Payment Eligibility Period - the amount of Start-Up Offer recovery remaining associated with an adjacent RUC Make-Whole Payment Eligibility Period.

DaTransitionHrlyAmt a, s, h, c $ Eligibility Period

Day-Ahead Transition Cost Amount per AO per Settlement Location per Hour in DA Market Make-Whole-Payment Eligibility Period - The DA Market Transition State Offer associated with AO a’s eligible combined cycle Resource at Settlement Location s in Hour h of DA Market Make-Whole-Payment Eligibility Period c.

DaCcSpinAdjHrlyAmt a, s, h $ Hour Day-Ahead Combined Cycle Spinning Reserve Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Spinning Reserve position during transitions between configurations for Hour h.

DaCcSuppAdjHrlyAmt a, s, h $ Hour Day-Ahead Combined Cycle Supplemental Reserve Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Supplemental Reserve position during transitions between configurations for Hour h.






Definition

DaCcSpinAdj5minAmt a, s, i $ Dispatch Interval

Day-Ahead Combined Cycle Spinning Reserve Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Spinning Reserve position during transitions between configurations for Dispatch Interval i.

DaCcSuppAdj5minAmt a, s, i $ Dispatch Interval

Day-Ahead Combined Cycle Supplemental Reserve Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Supplemental Reserve position during transitions between configurations for Dispatch Interval i.

RtTranistionStateFlg a, s, i None Dispatch Interval

Real-Time Transition State Flag per AO per Settlement Location in DA Make-Whole-Payment Eligibility Period – The value defined under Section 4.5.9.8.

RtRucComStat5minFlg a, s, i, c None Dispatch Interval

RUC Commitment Status Flag per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The value defined under Section 4.5.9.8.

DaMinRunTime a, h, s, c

Time Hour Day-Ahead Minimum Run Time per AO per Settlement Location Per Hour – The Minimum Run Time, in minutes, associated with AO a’s eligible Resource at Settlement Location s for DA Market Make-Whole-Payment Eligibility Period c as submitted as part of the DA Market Offer.

DaMwpCostHrlyAmt a, h, s, c $ Hour Day-Ahead Make-Whole Payment Cost Amount per AO per Settlement Location per Hour in the DA Market Make-Whole-Payment Eligibility Period - The hourly cost associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c.

PotDaRegUpMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Day-Ahead Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.28







Definition

PotDaRegDnMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Day-Ahead Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.29

DaMwpRevHrlyAmt a, h, s, c $ Hour Day-Ahead Make-Whole Payment Revenue Amount per AO per Settlement Location per Hour in the DA Market Make-Whole-Payment Eligibility Period – The hourly revenue associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c.

DaRegUpUnusedMileMwp5minAmt a, s, i $ Dispatch Interval

Day-Ahead Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.28

DaRegDnUnusedMileMwp5minAmt a, s, i $ Dispatch Interval

Day-Ahead Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.29

DaNoLoadHrlyAmt a, h, s, c $ Hour Day-Ahead No-Load Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The No-Load Offer, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c.

DaIncrEnHrlyAmt a, h, s, c $ Hour Day-Ahead Incremental Energy Cost Amount per AO per Settlement Location per Hour in the DA Market Make-Whole-Payment Eligibility Period - The average incremental energy offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c at an output level equal to DaClrdHrlyQty a, s, h.



Definition

DaRegUpAvailHrlyAmt a, h, s, c $ Hour Day-Ahead Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The Regulation-Up Service Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Regulation-Up Service Offer cost in the Hour is equal to the Resources DaRegUpHrlyQty a, z, s, h multiplied by the Resource’s Regulation-Up Service Offer, in $/MW.

DaRegDnAvailHrlyAmt a, h, s, c $ Hour Day-Ahead Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The Regulation-Down Service Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Regulation-Down Service Offer cost in the Hour is equal to the Resources DaRegDnHrlyQty a, z, s, h, multiplied by the Resource’s Regulation-Down Service Offer, in $/MW.

DaSpinAvailHrlyAmt a, h, s, c $ Hour Day-Ahead Spin Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The Spinning Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Spinning Reserve Offer cost in the Hour is equal to the Resource’s DaSpinHrlyQty a, z, s, h multiplied by the Resource’s Spinning Reserve Offer, in $/MW.











Definition

DaSuppAvailHrlyAmt a, h, s, c $ Hour Day-Ahead Supplemental Offer Cost Amount per AO per Settlement Location per Hour per DA Market Make-Whole-Payment Eligibility Period - The Supplemental Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Hour h in DA Market Make-Whole-Payment Eligibility Period c. The Resource’s Supplemental Reserve Offer cost in the Hour is equal to the Resources DaSuppHrlyQty a, z, s, h multiplied by the Resource’s Supplemental Reserve Offer, in $/MW.

DaLmpHrlyPrc s, h,

$/MWh Hour Day-Ahead LMP - The DA Market LMP at Resource Settlement Location s for Hour h.

DaClrdHrlyQty a, s, h MWh Hour Day-Ahead Cleared Energy Quantity per AO per Resource Settlement Location per Hour – The value described under Section 4.5.8.1 for AO a’s eligible Resource Settlement Location s.

DaRegUpHrlyAmt a, h, s $ Hour Day-Ahead Regulation-Up Service Amount per AO per Settlement Location per Hour – The DaRegUpHrlyAmt a, s h, calculated under Section 4.5.8.4 associated with AO a’s eligible Resource at Settlement Location s for Hour h.

DaRegDnHrlyAmt a, h, s $ Hour Day-Ahead Regulation-Down Service Amount per AO per Settlement Location per Hour– The DaRegDnHrlyAmt a, s h, calculated under Section 4.5.8.5 associated with AO a’s eligible Resource at Settlement Location s for Hour h.

DaSpinHrlyAmt a, h, s $ Hour Day-Ahead Spinning Reserve Amount per AO per Settlement Location per Hour– The DaSpinHrlyAmt a, s, h calculated under Section 4.5.8.6 associated with AO a’s eligible Resource at Settlement Location s for Hour h.

DaSuppHrlyAmt a, h, s $ Hour Day-Ahead Supplemental Reserve Amount per AO per Settlement Location per Hour - The DaSuppHrlyAmt a, s, h calculated under Section 4.5.8.7 associated with AO a’s eligible Resource at Settlement Location s for Hour h.





Definition

DaMwpDlyAmt a, s, d $ Operating Day

Day-Ahead Make-Whole-Payment Amount per AO per Settlement Location per Operating Day - The DA Market make-whole amount to AO a for Operating Day d at Resource Settlement Location s.

DaMwpAoAmt a, m, d $ Operating Day

Day-Ahead Make-Whole-Payment Amount per AO per Operating Day - The DA Market make-whole amount to AO a associated with Market Participant m for Operating Day d.

DaMwpMpAmt m, d $ Operating Day

Day-Ahead Make-Whole-Payment Amount per MP per Operating Day - The DA Market make-whole amount to Market Participant m for Operating Day d.

EqrDaMwpHrlyPrc a, s, c $ Eligibility

Period Day-Ahead Electric Quarterly Reporting Make-Whole-Payment Amount per AO per Settlement Location per DA Market Make-Whole-Payment Eligibility Period - The DA Market make-whole amount to AO a for DA Market Make-Whole-Payment Eligibility Period c at Resource Settlement Location s for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements..

EqrDaMwpHrlyQty a, s, c MWh Eligibility Period

Day-Ahead Electric Quarterly Reporting Make-Whole-Payment Quantity per AO per Settlement Location per DA Market Make-Whole-Payment Eligibility Period – This value is set equal to 1 if EqrDaMwpHrlyPrc a, s, c > 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. h none none An Hour in a DA Market Make-Whole-Payment Eligibility

Period. s none none A Resource Settlement Location. c none none A DA Market Make-Whole-Payment Eligibility Period. d none none An Operating Day. m none none A Market Participant.


4.5.9 Real-Time Balancing Market Settlement

Settlement calculations for the Real-Time Balancing Market are performed on a Dispatch Interval basis for each Operating Day and are based upon the difference between the results of the RTBM process and the DA Market clearing for that Operating Day. To calculate RTBM actual Energy in a Dispatch Interval for Asset Owners that have not directly submitted 5-minute interval meter data, SPP allocates the submitted hourly meter data for Resources and loads into 5-minute values using 5-minute telemetered or State Estimator profiles for the corresponding hour. The profiling of the hourly meter data maintains the shape of the 5-minute telemetered or State Estimator values even if there are both positive and negative values contained within the 12 intervals. All Dispatch Interval values are expressed in MW, not MWh. Exhibit 4-24 shows an example of how the profiling will work for a Resource that submits an actual hourly meter amount of -80 MWh.

Exhibit 4-2: Meter Profiling Example

Interval (1) State Estimator

MW

(2) Absolute Value of

Column (1)

(3) Normalize Column (2)

[Col (2) MW / Total Col (2)

MW]

(4) Profiled Hourly

Meter (-80 – (-66.25)) * 12 * Col (3) + Col

(1) 1 10 10 0.012 8 2 5 5 0.006 4 3 0 0 0.000 0 4 -50 50 0.061 -60 5 -60 60 0.073 -72 6 -70 70 0.085 -84 7 -80 80 0.097 -96 8 -90 90 0.109 -108 9 -100 100 0.121 -120

10 -110 110 0.133 -132 11 -120 120 0.145 -144 12 -130 130 0.158 -156

-66.25 MWh 825 (total) 1.000

-80 MWh (Meter) (submitted)

RTBM results are presented on an hourly basis but Market Participants and Asset Owners have access to the 5 minute data for verification purposes.


(1) Each Market Participant with actual Resource output is charged or paid for each Settlement Location for the difference between the amount of actual RTBM physical Energy sold and the amount of physical Energy sold in the DA Market, net of Bilateral Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.1);

(2) Each Market Participant with Import Interchange Transactions or Through Interchange Transactions (Resource Node) is charged or paid for each Settlement Location for the difference between the amount of actual RTBM physical import Energy scheduled and the amount of physical Energy sold in the DA Market, net of Bilateral Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.2);

(3) Each Market Participant with virtual Energy purchased in the DA Market is paid for the amount of virtual Energy purchased in the DA Market at the associated RTBM LMP (see Section 4.5.9.3);

(4) Each Market Participant with cleared Operating Reserve Offers is:

(a) charged or paid for each Settlement Location for the difference between the amount of Regulation-Up Service sold in the RTBM and the amount of Regulation-Up Service sold in the DA Market at the associated RTBM Regulation-Up Service MCP (see Section 4.5.9.4);

(b) paid for each Settlement Location for Excess Regulation-Up Mileage at the associated Expected Regulation-Up Mileage MCP (see Section 4.5.9.4);

(c) charged for each Settlement Location for Unused Regulation-Up Mileage at the associated Expected Regulation-Up Mileage MCP (see Section 4.5.9.4);

(d) charged or paid for each Settlement Location for the difference between the amount of Regulation-Down Service sold in the RTBM and the amount of Regulation-Up Service sold in the DA Market at the associated RTBM Regulation-Down Service MCP (see Section 4.5.9.5);

(e) paid for each Settlement Location for Excess Regulation-Down Mileage at the associated Expected Regulation-Down Mileage MCP (see Section 4.5.9.5);

(f) charged for each Settlement Location for Unused Regulation-Down Mileage at the associated Expected Resource’s Regulation-Down Mileage MCP (see Section 4.5.9.5);

(g) charged or paid for each Settlement Location Ffor the difference between the amount of Spinning Reserve sold in the RTBM and the amount of Spinning












Reserve sold in the DA Market at the associated RTBM Spinning Reserve MCP (see Section 4.5.9.6); and

(h) charged or paid for each Settlement Location Ffor the difference between the amount of Supplemental Reserve sold in the RTBM and the amount of Supplement Reserve sold in the DA Market at the associated RTBM Supplemental Reserve MCP (see Section 4.5.9.7).

(5) Each Market Participant with actual load consumption is charged or paid for each Settlement Location for the difference between the amount of actual physical load purchased and the amount of physical Energy purchased in the DA Market, net of Bilateral Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.1);

(6) Each Market Participant with Export Interchange Transactions or Through Interchange Transactions (Load Node) is charged or paid for each Settlement Location for the difference between the amount of actual physical export Energy scheduled and the amount of physical export Energy purchased in the DA Market, net of Bilateral Settlement Schedules for Energy, at the associated RTBM LMP (see Section 4.5.9.2);

(7) Market Participants with SPP committed Resources in any of the RUC processes that were not committed in the DA Market and combined cycle Resources that were committed in the DA Market and committed by SPP into a higher configuration as part of the RUC processes may receive a make whole-payment if the total revenues received for Energy and Operating Reserve sales in the RTBM settlement are less than the Resource’s Offer costs. See Section 4.5.9.8 for calculation details. Certain costs are not eligible for recovery as follows:

(a) If the Resource operates outside of its Operating Tolerance in a Dispatch Interval, costs associated with Energy provided in excess of the Resource’s Desired Dispatch are not eligible for recovery in that Dispatch Interval;

(b) If Resource is in “Manual” Control Status in a Dispatch Interval, costs associated with Energy provided in excess of the Resource’s Desired Dispatch are not eligible for recovery in that Dispatch Interval; and

(c) If the Resource increases its minimum limits in a Dispatch Interval above the minimum limits used by SPP to make the commitment decision by more than the Resource’s Operating Tolerance, costs associated with Energy provided in excess





of the Resource’s Desired Dispatch are not eligible for recovery in that Dispatch Interval.

(8) Make-Whole payments for SPP committed Resources as described in (7) above are collected on a daily basis from Market Participants based upon their pro-rata share of the sum of following quantities for the Operating Day as described in detail under Section 4.5.9.10:

(a) The absolute value of the net Settlement Location deviations from DA Market cleared amounts for load, virtual transactions and interchange transactions – excluding deviations resulting from actual load consumption that is less than DA Market cleared load MWh during capacity shortage condition Emergencies;

(b) The positive difference between RTBM Resource minimum limits and DA Market Resource cleared Energy amount, subject to exclusion if certain criteria are met. Special rules apply if a Resource cleared regulation in real-time but did not clear regulation in the Day-Ahead Market;

(c) The positive difference between the DA Market Resource cleared Energy amount and the RTBM Resource maximum limits, subject to exclusion if certain criteria are met. Special rules apply if a Resource cleared regulation in real-time but did not clear regulation in the Day-Ahead Market;

(d) A Resource’s DA Market cleared amount if that Resource is off-line in the RTBM, subject to exclusion if certain criteria are met;

(e) The absolute value of the difference between a Resource’s actual output and the Resource’s Desired Dispatch quantity if Resource is in “Manual” Control Status;

(f) The actual Resource output for Resources that self-committed following the close of the DA Market, subject to exclusion if certain criteria are met;

(g) A Resource’s Desired Dispatch quantity for Resources that were committed following the close of the DA Market if that Resource is off-line in the RTBM, subject to exclusion if certain criteria are met; and

(h) The absolute value of a Resource’s Uninstructed Resource Deviation if that Resource operated outside of its Operating Tolerance, subject to exclusion if certain criteria are met.


(9) In addition, Resources may receive a make-whole payment related to a Manual Dispatch Instruction as described under Section 4.5.9.9, subject to certain eligibility requirements, as follows:

(a) If the Resource is issued a Manual Dispatch Instruction 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 Manual Dispatch Instruction MW) and (ii) the Resource’s Desired Dispatch);

(b) If the Manual Dispatch Instruction 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. 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 Manual Dispatch Instruction MW)); and

(c) If during the Manual Dispatch Instruction, 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.

(10) Charges for failure to deploy Regulation-Up Service or Regulation-Down Service and charges for failure to deploy the specified amount of cleared Spinning Reserve or Supplemental Reserve are collected from Market Participants as part of the RTBM settlement as described under Sections 4.5.9.15 and 4.5.9.17 are distributed to Market Participants on a load ratio share basis as described under Sections 4.5.9.16 and 4.5.9.18;




(11) Charges to Market Participants for RTBM Operating Reserve procurement costs are collected on a Real-Time load ratio share basis as described under Sections 4.5.9.11, 4.5.9.12, 4.5.9.13 and 4.5.9.14;

(12) Resources providing Regulation-Up Service and/or Regulation-Down Service will receive a credit or charge associated with the regulation deployment energy as described under Section 4.5.9.19 such that Resources maintain Energy margins that are equal to the Energy margins that would have been attained absent the regulation deployment;

(a) For Regulation-Up Service, a credit is calculated if the cost rate of the Regulation-Up Service Energy is greater than the associated LMP and a charge is calculated if the associated LMP is greater the Regulation-Up Service Energy cost rate;2

(b) For Regulation-Down Service, a credit is calculated if the associated LMP is greater than cost rate of the Regulation-Down Service Energy and a charge is calculated if the cost rate of the Regulation-Down Energy is greater than the associated LMP.3

(13) Settlement associated with revenue mismatch due to the impact of marginal losses on the RTBM LMPs is also performed as part of the RTBM settlement as follows. See Section 4.5.9.20 for calculation details;

(a) For each Loss Pool, a proxy loss charge contribution amount is developed for each Settlement Location with a net RTBM withdrawal (RTBM actual – DA Market cleared amount) that is equal to the sum of i) the positive difference between the MLC at the net withdrawal Settlement Location and the weighted average MLC of all net injections (RTBM actual – DA Market cleared amount) assumed to be serving the net withdrawal, multiplied by that Settlement Location’s net withdrawal, and ii) the sum of charges for Real-Time pseudo-tie Losses at the Settlement Location of the Sink of the pseudo-tie path. These values are then summed to calculate a Loss Pool proxy loss charge contribution.

(i) The net injections assumed to be serving the net withdrawal are the net injections at the Settlement Locations included in that the Loss Pool. To the extent that the net injections in the Loss Pool are not sufficient to serve the net withdrawals in the Loss Pool, net injections from an injection exchange are included to make up the difference. To the extent that the

2 A charge is calculated here because this difference (opportunity cost) has already been included in the Regulation-Up MCP. 3 A charge is calculated here because this difference has already been included in the Regulation-Down MCP.









net injections in the Loss Pool are greater than the net withdrawals in the Loss Pool, the excess is added to the injection exchange;

(ii) The injection exchange is comprised of quantities from Loss Pools in which injection exceeds withdrawal. A weighted average of the MLC at the source of these quantities establishes a reference for the component of the loss charge contributions at Settlement Locations with net withdrawal met from outside the Loss Pool.

(b) The Loss Pool proxy loss charge contribution calculated in (a) above are then used to allocated to the total DA Market loss over-collections dollars to each Loss Pool on a pro rata basis.

(c) Each Asset Owner’s credit or charge (all Asset Owner net withdrawals at Settlement Location participate) in each Loss Pool at each withdrawal Settlement Location within that Loss Pool is then equal a pro-rata share of the total marginal losses over collection or under collection allocated to that Loss Pool. The pro-rata share is calculated as an Asset Owner’s Settlement Location withdrawal divided by the sum of all Asset Owner Settlement Location withdrawals within that Loss Pool. Settlement Location withdrawal is equal to the maximum of (1) zero or (2) the sum of the (i) the difference between Real-Time metered load and DA Market cleared Demand Bids, (ii) the difference between Real-Time metered generation and Day-Ahead Market cleared Resource Offers, (iii) the difference between Real-Time and Day-Ahead Export Interchange Transactions, (iv) the difference between Real-Time and Day-Ahead Import Interchange Transactions and (v) Bilateral Settlement Schedules for Energy at that Settlement Location.

(14) Settlement (charges or credits) associated with services provided under Joint Operating Agreements are described under Section 4.5.9.21. These Charges or credits are collected or distributed as part of revenue neutrality uplift as described under Section 4.5.12;

(15) Settlement (charges or credits) associated with Contingency Reserve deployment involving Reserve Sharing Group members is accounted for as described under Section 4.5.9.22. These charges or credits are collected or distributed on a load ratio share as described under Section 4.5.9.23.

(16) Demand reduction credits to Market Participants associated with a load Settlement Location that contains a Demand Response Resource are calculated as part of the RTBM settlement in order to ensure that, on a net settlement basis, the RTBM charge associated


with that load Settlement Location is reflective of the net load (i.e. the load including the impact of a cleared Demand Response Resource).

For example, consider a load Settlement Location that consists of a single PNode and that PNode also represents a Demand Response Load that is associated with a Dispatchable Demand Response (DDR) Resource. The Market Participant for the load Settlement Location submits a fixed Demand Bid in the Day-Ahead Market of 100 MW, which is reflective of that location’s actual load consumption in real-time, assuming that there is no load reduction (i.e. this value represents the baseline value for the DRL that will be submitted for use in real-time). The Market Participant for the DDR Resource submits a Resource Offer that results in the DDR clearing for 20 MWs of Energy (resulting in a net Day-Ahead Market cleared load of 80 MW).

For the corresponding hour in real-time, the DDR actual output was 25 MWs and the actual submitted meter value of the DRL was 75 MW. However, to ensure proper accounting for deviations in real-time load from cleared Day-Ahead Market amounts and calibration calculations, the submitted DRL actual meter value must be grossed up by the amount of DDR output. If we assume that RTBM LMP is $50/MWh, the net settlement at the load Settlement Location would be:

Load Settlement: {(75 MW + 25 MW) – (100 MW (DA Market)} * $50/MWh = $0

Demand Reduction Amount (Credit) =

(-25 MW – (-20 MW (DA Market)) * $50/MWh = ($250)

Net Load Settlement Location Settlement = ($250)

The net ($250) credit is the same as the credit that would have been calculated using the net RTBM load of 75 MW and the net cleared Day-Ahead Market load of 80 MW in the RTBM settlement ((75 MW – 80 MW) multiplied by the $50/MWh LMP). However, in order to ensure proper deviation and calibration accounting in real-time, the 100 MW of cleared load and the 25 MW of cleared DDR output is used to calculate real-time deviations from cleared Day-Ahead Market amounts and calibration energy amounts. See Section 4.5.9.24 for additional calculation details.

(17) Charges or credits to Market Participants for allocation of RTBM demand reduction amounts are calculated on a system-wide basis by multiplying the demand reduction rate by each Market Participant’s RTBM demand reduction obligation. See Sections 4.5.9.25 for additional details;


(a) The demand reduction rate is equal to the total of demand reduction amounts calculated for load divided by the system-wide total actual withdrawals (real-time metered load and export transactions).

(b) Each Market Participant’s demand reduction obligation is equal to that Market Participant’s total actual withdrawals (real-time metered load and export transactions).

(18) Settlements (charges or credits) for congestion and losses associated with Resources or load internal to the SPP footprint that has pseudo-tied out of the SPP Balancing Authority, is accounted for as described under Sections 4.5.9.26 and 4.5.9.27.

(19) Resources with cleared Regulation-Up Service in either the Day-Ahead Market and/or RTBM may be eligible to receive an Unused Regulation-Up Mileage Make Whole Payment as described under Sections 4.5.9.28 under the following conditions:

(a) The Resource must have been charged for Unused Regulation-Up Mileage at a Regulation-Up Mileage MCP that is greater than the Resource’s Regulation-Up Mileage Offer;

(b) The Resource’s cleared Regulation-Up Service Margin must be less than or equal to the Resource’s Potential Unused Regulation-Up Mileage Make Whole Payment;

(i) For Regulation-Up Service MWs cleared in the Day-Ahead Market, Day-Ahead Market Regulation-Up Service Margin is equal to the cleared Regulation-Up Service MWs multiplied by the difference between the Resource’s Regulation-Up Service MCP and the Resource’s Regulation-Up Service Offer. This Day-Ahead Market Regulation-Up Service Margin is adjusted downward to account for any portion of the cleared Day-Ahead Regulation-Up Service MWs that are bought back in the RTBM (i.e. if cleared RTBM Regulation-Up Service MWs are less than cleared Day-Ahead Market Regulation-Up Service MWs);

(ii) For Regulation-Up Service MWs cleared in the RTBM in excess of those cleared in the Day-Ahead Market, Real-Time Regulation-Up Service Margin is equal to the (cleared Regulation-Up Service MWs minus cleared Day-Ahead Market Regulation-Up Service MWs) multiplied by the difference between the Resource’s Regulation-Up Service MCP and the Resource’s Regulation-Up Service Offer;


(iii) Potential Unused Regulation-Up Mileage Make Whole Payment is equal to the sum of the Resource’s Day-Ahead Potential Unused Regulation-Up Mileage Make Whole Payment and Real-Time Potential Unused Regulation-Up Mileage Make Whole Payment. A Resource’s Day-Ahead Potential Unused Regulation-Up Mileage Make Whole Payment is equal to the portion of the Resource’s Unused Regulation-Up Mileage allocated to the Day-Ahead Market multiplied by the difference between the Regulation-Up Mileage MCP and the Resource’s RTBM Regulation-Up Mileage Offer. A Resource’s Real-Time Potential Unused Regulation-Up Mileage Make Whole Payment is equal to the portion of the Resource’s Unused Regulation-Up Mileage allocated to the RTBM multiplied by the difference between the Regulation-Up Mileage MCP and the Resource’s RTBM Regulation-Up Mileage Offer;

(c) A Resource’s Unused Regulation-Up Mileage Make Whole Payment is equal to the sum of the Resource’s Day-Ahead Market Unused Regulation-Up Mileage Make Whole Payment and Real-Time Unused Regulation-Up Mileage Make Whole Payment.

(i) A Resource’s Day-Ahead Market Unused Regulation-Up Mileage Make Whole Payment is equal to the Resource’s Day-Ahead Market Potential Unused Regulation-Up Mileage Make Whole Payment minus the Resource’s Day-Ahead Market Regulation-Up Service Margin.

(ii) A Resource’s Real-Time Market Unused Regulation-Up Mileage Make Whole Payment is equal to the Resource’s Real-Time Potential Unused Regulation-Up Mileage Make Whole Payment minus the Resource’s Real-Time Regulation-Up Service Margin.

(20) Resources with cleared Regulation-Down Service in either the Day-Ahead Market and/or RTBM may be eligible to receive an Unused Regulation-Down Mileage Make Whole Payment as described under Sections 4.5.9.29 under the following conditions:

(a) The Resource must have been charged for Unused Regulation-Down Mileage at a Regulation-Down Mileage MCP that is greater than the Resource’s Regulation-Down Mileage Offer;

(b) The Resource’s cleared Regulation-Down Service Margin must be less than or equal to the Resource’s Potential Unused Regulation-Down Mileage Make Whole Payment;


(i) For Regulation-Down Service MWs cleared in the Day-Ahead Market, Day-Ahead Market Regulation-Up Service Margin is equal to the cleared Regulation-Down Service MWs multiplied by the difference between the Resource’s Regulation-Down Service MCP and the Resource’s Regulation-Down Service Offer. This Day-Ahead Market Regulation-Down Service Margin is adjusted downward to account for any portion of the cleared Day-Ahead Regulation-Down Service MWs that are bought back in the RTBM (i.e. if cleared RTBM Regulation-Down Service MWs are less than cleared Day-Ahead Market Regulation-Down Service MWs);

(ii) For Regulation-Down Service MWs cleared in the RTBM in excess of those cleared in the Day-Ahead Market, Real-Time Regulation-Down Service Margin is equal to the (cleared Regulation-Down Service MWs minus cleared Day-Ahead Market Regulation-Down Service MWs) multiplied by the difference between the Resource’s Regulation-Down Service MCP and the Resource’s Regulation-Down Service Offer;

(iii) Potential Unused Regulation-Down Unused Mileage Make Whole Payment is equal to the sum of the Resource’s Day-Ahead Potential Unused Regulation-Down Mileage Make Whole Payment and Real-Time Potential Unused Regulation-Down Mileage Make Whole Payment. A Resource’s Day-Ahead Potential Unused Regulation-Down Mileage Make Whole Payment is equal to the portion of the Resource’s Unused Regulation-Down Mileage allocated to the Day-Ahead Market multiplied by the difference between the Regulation-Down Mileage MCP and the Resource’s RTBM Regulation-Down Mileage Offer. A Resource’s Real-Time Potential Unused Regulation-Down Mileage Make Whole Payment is equal to the portion of the Resource’s Unused Regulation-Down Mileage allocated to the RTBM multiplied by the difference between the Regulation-Down Mileage MCP and the Resource’s RTBM Regulation-Down Mileage Offer;

(c) A Resource’s Unused Regulation-Down Mileage Make Whole Payment is equal to the sum of the Resource’s Day-Ahead Market Unused Regulation-Down Mileage Make Whole Payment and Real-Time Unused Regulation-Down Mileage Make Whole Payment.

(i) A Resource’s Day-Ahead Market Unused Regulation-Down Mileage Make Whole Payment is equal to the Resource’s Day-Ahead Market


Potential Unused Regulation-Down Mileage Make Whole Payment minus the Resource’s Day-Ahead Market Regulation-Down Service Margin.

(ii) A Resource’s Real-Time Market Unused Regulation-Down Mileage Make Whole Payment is equal to the Resource’s Real-Time Potential Unused Regulation-Down Mileage Make Whole Payment minus the Resource’s Real-Time Regulation-Down Service Margin.

The following subsections describe the RTBM settlement charge types in more detail. For each charge type, the initial calculation is performed either at the Dispatch Interval level or hourly level for each Asset Owner at each Settlement Location. In addition to the Dispatch Interval and hourly values, hourly and daily values will be accessible on the Settlement Statement for all charge types.

4.5.9.4 Real-Time Regulation-Up Service Amount

(1) A RTBM charge or credit for deviations between cleared RTBM Regulation-Up Service and cleared DA Market Regulation-Up Service and deviations between Expected Regulation-Up Mileage and the Actual Regulation-Up Mileage provided will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval. The amount will be calculated as follows:

#RtRegUp5minAmt a, s, i = ( ∑z

( RtRegUpMcp5minPrc z, i

* ( RtRegUp5minQty a, z, s, i - ∑z

DaRegUpHrlyQty a, z, s, h ) / 12 )

- RtRegUpUnusedMile5minAmt a, s, i - RtRegUpExcessMile5minAmt a, s, i ) * (-1)

Where,

(a) #RtRegUpUnusedMile5minAmt a, s, i =

RtRegUpUnusedMile5minQty a, z, s, i * RtRegUpMileMcp5minPrc i / 12

(a.1) #RtRegUpUnusedMile5minQty a, z, s, i =

∑z






Formatted: Font: Times New Roman Bold, 11pt, Lowered by 14 pt


Max ( 0, ( RtRegUp5minQty a, z, s, i * RtRegUpMile5minFct i )

- RtRegUpMile5minQty a, z, s, i )

(b) #RtRegUpExcessMile5minAmt a, s, i =

RtRegUpExcessMile5minQty a, s, i Min ( 0, ( ( RtRegUp5minQty a, z, s, i *

RtRegUpMile5minFct i )

- RtRegUpMile5minQty a, z, s, i )

* RtRegUpMileMcp5minPrc i ) / 12

(b.1) #RtRegUpExcessMile5minQty a, s, i =

Min ( 0, ( RtRegUp5minQty a, s, i * RtRegUpMile5minFct i )

- RtRegUpMile5minQty a, s, i )

(c) IF

RtRegUpActMile5minQty a, z, s, i >= (1 - RtRegMileOpTolPct a, z, s, i ) *

RtRegUpInstrMile5minQty a, z, s, i )

THEN

RtRegUpMile5minQty a, z, s, i = RtRegUpInstrMile5minQty a, z, s, i

ELSE

RtRegUpMile5minQty a, z, s, i = RtRegUpActMile5minQty a, z, s, i

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

RtRegUpHrlyAmt a, s, h = ∑i

RtRegUp5minAmt a, s, i

∑z




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

RtRegUpDlyAmt a, s, d = ∑h

RtRegUpHrlyAmt a, s, h


RtRegUpAoAmt a, m, d = ∑s

RtRegUpDlyAmt a, s, d


RtRegUpMpAmt m, d = ∑a

RtRegUpAoAmt a, m, d

(6) 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) RTBM Regulation-Up Service

(a.1) #EqrRtRegUp5minQty a, s, i =

∑z

Max ( 0, ( RtRegUp5minQty a, z, s, i - ∑z

DaRegUpHrlyQty a, z, s, h ) / 12 )

+

{ IF #EqrDaRegUpHrlyQty a, s, h > 0 THEN

∑z

Min ( 0, ( RtRegUp5minQty a, z, s, i - ∑z

DaRegUpHrlyQty a, z, s, h ) / 12 ) }

(a.2b) IF EqrRtRegUp5minQty a, s, i < > 0


THEN

#EqrRtRegUp5minPrc a, s, i = RtRegUpMcp5minPrc z, i

(b) RTBM Excess Regulation-Up Mileage

(b.1) EqrRtRegUpExcessMile5minQty a, s, i = RtRegUpExcessMile5minQty a, s, i

(b.2) EqrRtRegUpExcessMileMcp5minPrc a, s, i =

( 0 * EqrRtRegUpExcessMile5minQty a, s, i + RtRegUpMileMcp5minPrc i )

(c) RTBM Unused Regulation-Up Mileage

(c.1) EqrRtRegUpUnusedMile5minQty a, s, i = RtRegUpUnusedMile5minQty a, s, i

(c.2) EqrRtRegUpUnusedMileMcp5minPrc a, s, i =

( 0 * EqrRtRegUpUnusedMile5minQty a, s, i + RtRegUpMileMcp5minPrc


The above variables are defined as follows: Variable

Unit

Settlement Interval

Definition

RtRegUp5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation-Up Service Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Up Service Offers Unused Regulation-Up Mileage and Excess Regulation-Up Mileage at Resource Settlement Location s for the Dispatch Interval.

RtRegUpMcp5minPrc z, i $/MW Dispatch Interval

Real-Time MCP for Regulation-Up Service per Reserve Zone - The RTBM MCP for Regulation-Up Service in Reserve Zone z for Dispatch Interval i.

RtRegUpMileMcp5minPrc i $/MW Dispatch Interval

Real-Time MCP for Regulation-Up Mileage - The RTBM MCP for Expected Regulation-Up Mileage for Dispatch Interval i.

RtRegUpUnusedMile5minAmt a, s, i

$ Dispatch Interval

Real-Time Unused Regulation-Up Mileage Amount per AO per Settlement Location per Dispatch Interval - The charge to AO a for Unused Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i.

RtRegUpExcessMile5minAmt a, s, i

$ Dispatch Interval

Real-Time Excess Regulation-Up Mileage Amount per AO per Settlement Location per Dispatch Interval - The payment to AO a for Excess Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i.

RtRegUpMile5minFct i Ratio Dispatch Interval

Real-Time Regulation-Up Mileage Factor Dispatch Interval - The Regulation-Up Mileage Factor for Dispatch Interval i.

RtRegUpActMile5minQty a, z,

s, i MW Dispatch

Interval Real-Time Actual Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Actual Regulation-Up Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z. This value is calculated using 4-second data and represents the sum of the actual up and down Resource movement in response to Regulation-Up deployment instructions in Dispatch Interval i.

RtRegUpMile5minQty a, z, s, i MW Dispatch Interval

Real-Time Regulation-Up Mileage Settlement Quantity per AO per Settlement Location per Dispatch Interval - AO a’s settled Actual Regulation-Up Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z used for Settlement that includes the impact of the Resource Regulating Mileage Operating Tolerance.













Variable

Unit

Settlement Interval

Definition

RtRegUpInstrMile5minQty a,

z, s, i MW Dispatch

Interval Real-Time Instructed Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Instructed Regulation-Up Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z. This value is calculated using 4-second data and represents the sum of the instructed up and down Resource movement received through Regulation-Up deployment instructions in Dispatch Interval i.

RtRegUpUnusedMile5minQty a, z, s, i

MW Dispatch Interval

Real-Time Unused Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i.

RtRegUpExcessMile5minQty a, s, i


Real-Time Excess Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Excess Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i.

RtRegMileOpTolPct a, z, s, i Percent Dispatch Interval

Resource Mileage Operating Tolerance per AO per Settlement Location per Dispatch Interval – The Resource Regulating Mileage Operating Tolerance associated with AO a’s Resource at Settlement Location s in Reserve Zone z in Dispatch Interval i.


Real-Time Cleared Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Regulation-Up Service MW represented by AO a’s cleared Regulation-Up Service Offers in RTBM in the Reserve Zone z that includes Resource Settlement Location s, for Dispatch Interval i.

RtRegUpHrlyAmt a, s, h $ Hour Real-Time Regulation-Up Service Amount per AO per Settlement Location per Hour - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Up Service Offers at Resource Settlement Location s for the Hour.

RtRegUpDlyAmt a, s, d $ Operating Day

Real-Time Regulation-Up Service Amount per AO per Settlement Location per Operating Day - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Up Service Offers at Resource Settlement Location s for the Operating Day.













Variable

Unit

Settlement Interval

Definition

RtRegUpAoAmt a, m, d $ Operating Day

Real-Time Regulation-Up Service Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for deviations between cleared RTBM and DA Market Regulation-Up Service Offers for the Operating Day.

RtRegUpMpAmt m, d $ Operating Day

Real-Time Regulation-Up Service Amount per MP per Operating Day - The amount to MP m for deviations between cleared RTBM and DA Market Regulation-Up Service Offers for the Operating Day.

EqrRtRegUp5minQty a, s, i

MWh Dispatch

Interval Real-Time Electric Quarterly Reporting net Regulation-Up Service Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM Regulation-Up Service sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead in Dispatch Interval i or AO a’s RTBM Regulation-Up Service purchase at Resource Settlement Location s created when the cleared Real-Time Regulation-Up Service is less than the amount cleared Day-Ahead in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.

EqrRtRegUp5minPrc a, s, i

$/MWh Dispatch

Interval Real-Time Electric Quarterly Reporting net Regulation Up Transactions Prices per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegUp5minQty 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.

EqrRtRegUpExcessMile5minQty a, s, i


Real-Time Electric Quarterly Reporting Excess Regulation-Up Mileage Transaction Quantity per AO per Settlement Location per Dispatch Interval– AO a’s Excess Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.

EqrRtRegUpExcessMile5minPrc a, s, i


Real-Time Electric Quarterly Reporting Excess Regulation-Up Mileage Transaction Price per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegUpExcessMile5minQty 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.










Variable

Unit

Settlement Interval

Definition

EqrRtRegUpUnusedMile5minQty a, s, i


Real-Time Electric Quarterly Reporting Unused Regulation-Up Mileage Transaction Quantity per AO per Settlement Location per Dispatch Interval– AO a’s Unused Regulation-Up Mileage at Resource Settlement Location s for Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.

EqrRtRegUpUnusedMile5minPrc a, s, i


Real-Time Electric Quarterly Reporting Unused Regulation-Up Mileage Transaction Price per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegUpUnusedMile5minQty 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.

DaRegUpHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Regulation-Up Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.4

a none none An Asset Owner. s none none A Resource Settlement Location. h none none An Hour. i none none A Dispatch Interval. d none none An Operating Day. z none none A Reserve Zone. m none none A Market Participant.


4.5.9.5 Real-Time Regulation-Down Service Amount

(1) A RTBM charge or credit for deviations between cleared RTBM Regulation-Down Service and cleared DA Market Regulation-Down Service and deviations between Expected Regulation-Down Mileage and Actual Regulation-Down Mileage provided will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval. The amount will be calculated as follows:

#RtRegDn5minAmt a, s, i = ( ∑z

( RtRegDnMcp5minPrc z, i

* ( RtRegDn5minQty a, z, s, i - ∑z

DaRegDnHrlyQty a, z, s, h ) /12 )

- RtRegDnUnusedMile5minAmt a, s, i - RtRegDnExcessMile5minAmt a, s, i )

* (-1)

Where,

(a) #RtRegDownUnusedMile5minAmt a, s, i =

RtRegDownUnusedMile5minQty a, z, s, i * RtRegDownMileMcp5minPrc i /

12

(a.1) #RtRegDownUnusedMile5minQty a, z, s, i =

Max ( 0, ( RtRegDown5minQty a, z, s, i * RtRegDownMile5minFct i )

- RtRegDownMile5minQty a, z, s, i )

(b) #RtRegDnExcessMile5minAmt a, s, i =

RtRegDnExcessMile5minQty a, s, i Min ( 0, ( ( RtRegDn5minQty a, z, s, i *

RtRegDnMile5minFct i )

∑z

∑z









- RtRegDnMile5minQty a, z, s, i )

* RtRegDnMileMcp5minPrc i ) / 12

(b.1) #RtRegDnExcessMile5minQty a, s, i =

Min ( 0, ( RtRegDn5minQty a, s, i * RtRegDnMile5minFct i )

- RtRegDnMile5minQty a, s, i )

(c) IF

RtRegDnActMile5minQty a, z, s, i >= (1 - RtRegMileOpTolPct a, z, s, i ) *

RtRegDnInstrMile5minQty a, z, s, i )

THEN

RtRegDnMile5minQty a, z, s, i = RtRegDnInstrMile5minQty a, z, s, i

ELSE

RtRegDnMile5minQty a, z, s, i = RtRegDnActMile5minQty a, z, s, i


RtRegDnHrlyAmt a, s, h = ∑i

RtRegDn5minAmt a, s, i


RtRegDnDlyAmt a, s, d = ∑h

RtRegDnHrlyAmt a, s, h




RtRegDnAoAmt a, m, d = ∑s

RtRegDnDlyAmt a, s, d


RtRegDnMpAmt m, d = ∑a

RtRegDnAoAmt a, m, d

(6) 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) RTBM Regulation-Down Service

(a.1) #EqrRtRegDn5minQty a, s, i =

∑z

Max ( 0, ( RtRegDn5minQty a, z, s, i - ∑z

DaRegDnHrlyQty a, z, s, h ) / 12 )

+

{ IF #EqrDaRegDnHrlyQty a, s, h > 0 THEN

∑z

Min ( 0, ( RtRegDn5minQty a, z, s, i - ∑z

DaRegDnHrlyQty a, z, s, h ) / 12 ) }

(a.2b) IF EqrRtRegDn5minQty a, s, i < > 0

THEN

#EqrRtRegDn5minPrc a, s, i = RtRegDnMcp5minPrc z, i

(b) RTBM Excess Regulation-Down Mileage

(b.1) EqrRtRegDnExcessMile5minQty a, s, i = RtRegDnExcessMile5minQty a, s, i


(b.2) EqrRtRegDnExcessMileMcp5minPrc a, s, i =

( 0 * EqrRtRegDnExcessMile5minQty a, s, i + RtRegDnMileMcp5minPrc i )

(c) RTBM Unused Regulation-Down Mileage

(c.1) EqrRtRegDnUnusedMile5minQty a, s, i = RtRegDnUnusedMile5minQty a, s, i

(c.2) EqrRtRegDnUnusedMileMcp5minPrc a, s, i =

( 0 * EqrRtRegDnUnusedMile5minQty a, s, i + RtRegDnMileMcp5minPrc i )



Unit

Settlement Interval

Definition

RtRegDn5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation-Down Service Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Down Service Offers , Unused Regulation-Up Mileage and Excess Regulation-Up Mileage at Resource Settlement Location s for the Dispatch Interval.

RtRegDnMcp5minPrc z, i $/MW Dispatch Interval

Real-Time MCP for Regulation-Down Service per Reserve Zone - The RTBM MCP for Regulation-Down Service in Reserve Zone z for Dispatch Interval i.

RtRegDnMileMcp5minPrc i $/MW Dispatch Interval

Real-Time MCP for Regulation-Down Mileage - The RTBM MCP for Excess Expected Regulation-Down Mileage for Dispatch Interval i.

RtRegDnUnusedMile5minAmt a, s, i

$ Dispatch Interval

Real-Time Unused Regulation-Down Mileage Amount per AO per Settlement Location per Dispatch Interval - The charge to AO a for Unused Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i.

RtRegDnExcessMile5minAmt a, s, i

$ Dispatch Interval

Real-Time Excess Regulation-Down Mileage Amount per AO per Settlement Location per Dispatch Interval - The payment to AO a for Excess Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i.

RtRegDnMile5minFct i Ratio Dispatch Interval

Real-Time Regulation-Down Mileage Factor Dispatch Interval - The Regulation-Down Mileage Factor for Dispatch Interval i.

RtRegDnActMile5minQty a, z,

s, i MW Dispatch

Interval Real-Time Actual Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - The AO a’s Actual Regulation-Down Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z. This value is calculated using 4-second data and represents the sum of the actual up and down Resource movement in response to Regulation-Down deployment instructions in Dispatch Interval i.












Variable

Unit

Settlement Interval

Definition

RtRegDnMile5minQty a, z, s, i MW Dispatch Interval

Real-Time Regulation-Down Mileage Settlement Quantity per AO per Settlement Location per Dispatch Interval - AO a’s settled Actual Regulation-Down Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z used for Settlement that includes the impact of the Regulating Mileage Operating Tolerance.

RtRegDnInstrMile5minQty a,

z, s, i MW Dispatch

Interval Real-Time Instructed Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Instructed Regulation-Down Mileage at Settlement Location s for Dispatch Interval i in Reserve Zone z. This value is calculated using 4-second data and represents the sum of the instructed up and down Resource movement received through Regulation-Down deployment instructions in Dispatch Interval i.

RtRegDnUnusedMile5minQty a, z, s, i


Real-Time Unused Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i.

RtRegDnExcessMile5minQty a, s, i


Real-Time Excess Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i.

RtRegMileOpTolPct a, z, s, i Percent Dispatch Interval

Resource Mileage Operating Tolerance per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.4.

RtRegDn5minQty a, z, s, i MW Dispatch Interval

Real-Time Cleared Regulation-Down Service Quantity per AO per Settlement Location per Dispatch Interval - The total amount of Regulation-Down Service represented by AO a’s cleared Regulation-Down Service Offers in the RTBM in the Reserve Zone z that includes Resource Settlement Location s, for Dispatch Interval i.

RtRegDnHrlyAmt a, s, h $ Hour Real-Time Regulation-Down Service Amount per AO per Settlement Location per Hour - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Down Service Offers at Resource Settlement Location s for the Hour.











Variable

Unit

Settlement Interval

Definition

RtRegDnDlyAmt a, s, d $ Operating Day

Real-Time Regulation-Down Service Amount per AO per Settlement Location per Operating Day - The amount to AO a for deviations between cleared RTBM and DA Market Regulation-Down Resource Offers at Resource Settlement Location s for the Operating Day.

RtRegDnAoAmt a, m, d $ Operating Day

Real-Time Regulation-Down Service Amount per AO per Operating Day - The amount to AO a associated with Market Participant m for deviations between cleared RTBM and DA Market Regulation-Down Service Offers for the Operating Day.

RtRegDnMpAmt m, d $ Operating Day

Real-Time Regulation-Down Service Amount per MP per Operating Day - The amount to MP m for deviations between cleared RTBM and DA Market Regulation-Down Service Offers for the Operating Day.

EqrRtRegDn5minQty a, s, i

MWh Dispatch

Interval Real-Time Electric Quarterly Reporting net Regulation-Down Service Transactions per AO per Settlement Location per Dispatch Interval– AO a’s RTBM Regulation-Down Service sale at Resource Settlement Location s in excess of the amount cleared Day-Ahead in Dispatch Interval i or AO a’s RTBM Regulation-Down Service purchase at Resource Settlement Location s created when the cleared Real-Time Regulation-Down Service is less than the amount cleared Day-Ahead in Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.

EqrRtRegDn5minPrc a, s, i

$/MWh Dispatch

Interval Real-Time Electric Quarterly Reporting net Regulation-Down Service Transactions Prices per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegDn5minQty 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.

EqrRtRegDnExcessMile5minQty a, s, i


Real-Time Electric Quarterly Reporting Excess Regulation-Down Mileage Transaction Quantity per AO per Settlement Location per Dispatch Interval– AO a’s Excess Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.













Variable

Unit

Settlement Interval

Definition

EqrRtRegDnExcessMile5minPrc a, s, i


Real-Time Electric Quarterly Reporting Excess Regulation-Down Mileage Transaction Price per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegDnExcessMile5minQty 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.

EqrRtRegDnUnusedMile5minQty a, s, i


Real-Time Electric Quarterly Reporting Unused Regulation-Down Mileage Transaction Quantity per AO per Settlement Location per Dispatch Interval– AO a’s Unused Regulation-Down Mileage at Resource Settlement Location s for Dispatch Interval i, for use by AO a in reporting such sales/purchases to FERC in accordance with FERC EQR requirements.

EqrRtRegDnUnusedMile5minPrc a, s, i


Real-Time Electric Quarterly Reporting Unused Regulation-Down Mileage Transaction Price per AO per Settlement Location per Dispatch Interval – AO a’s prices associated with non-zero EqrRtRegDnUnusedMile5minQty 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.

DaRegDnHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Regulation-Down Service Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.8.5

a none none An Asset Owner. s none none A Resource Settlement Location. h none none An Hour. i none none A Dispatch Interval. d none none An Operating Day. z none none A Reserve Zone. m none none A Market Participant.




(1) The RUC Make-Whole-Payment Amount is a credit or charge4 to a Resource Asset Owner and is calculated for each Resource with a RUC Commitment Period that was committed by SPP with an RTBM Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1. Asset Owners of Resources committed by a local transmission operator to address a Local Emergency Condition are eligible to receive a RUC make whole payment, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a RUC make whole payment. For such eligible local transmission operator commitments, a manual process is employed for the calculations and the make-whole-payments will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The RUC Make-Whole-Payment Amount is also calculated for combined cycle Resources with a RUC Commitment Period during which the Resource is moved into a configuration that incurs additional costs over the Resource configuration used in the DA Market Commitment Period for the corresponding time period. A payment is made to the Resource Asset Owner when the sum of the Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy Offer Curve, Transition State Offer costs and Operating Reserve Offer costs associated with actual MWh amounts for Energy and cleared RTBM Operating Reserve is greater than the Energy and Operating Reserve RTBM revenues received for that Resource over the Resource’s RUC Make-Whole-Payment Eligibility Period. Recovery of such compensation shall be collected in accordance with Section 8.6.7 of Attachment AE.

(2) A Resource’s RUC Make-Whole-Payment Eligibility Period is equal to the Resource’s RUC Commitment Period except as described below:

(a) As shown in Exhibit 4-25, for Resources with a RUC Commitment Period that begins in one Operating Day and ends in the next Operating Day, two RUC Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last Dispatch Interval of the first Operating Day. The second period begins in the first





Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated with the Resource’s RUC De-Commit Time.


(b) If the Resource is a combined cycle Resource committed in the DA Market and then, during an RTBM hour within the DA Market Commitment Period, the Resource is moved into a configuration that is different from the configuration used in the DA Market Commitment period and such configuration incurs a Transition State Offer cost and/or a No-Load Offer cost that is higher than the No-Load Offer cost associated with the configuration used in the DA Market, that RTBM hour will be considered the start of a RUC Make-Whole-Payment Eligibility Period. The end of this RUC Make-Whole-Payment Eligibility Period will be defined by the RTBM hour when the configuration in that RTBM hour is the same configuration as the configuration used in the corresponding DA Market Commitment Period hour, the Resource’s De-Commit Time or the end of the Operating Day, whichever is less.

(3) The following cost recovery eligible rules apply to each RUC Make-Whole-Payment Eligibility Period. Resource production costs are calculated using the RTBM Offer prices in effect at the time the commitment decision was made for start-up, no-load, and minimum-energy; and the RTBM Offer prices in effect at the solving of a dispatch interval for incremental energy, Regulation-Up, Regulation-Down, Spin, and Supplement Reserves.

(a) If SPP cancels a start-up order prior to the start of the associated RUC Make-Whole-Payment Eligibility Period and the Resource is not a Synchronized Resource, the Asset Owner will receive reimbursement for a time-based pro-rata share of the Resource’s


RUC Commitment

Period

Time





RTBM Start-Up Offer. Asset Owners may request additional compensation through submittal of actual cost documentation to the 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.

(b) In order to receive Start-Up Offer recovery within a RUC Make-Whole-Payment Eligibility Period, the Resource must be a Synchronized Resource for at least one Dispatch Interval in the RUC Make-Whole Payment Eligibility Period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the RUC Make-Whole Payment Eligibility Period, the Resource must be a Synchronized Resource in that Dispatch Interval.

(d) There may be more than one RUC Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single RUC Make-Whole Payment Eligibility Period is contained within a single Operating Day.

(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the following RUC Make-Whole Payment Eligibility Periods:

(i) Any RUC Make-Whole Payment Eligibility Period that is adjacent to the end of a DA Market Make-Whole Payment Eligibility Period;

(ii) Any RUC Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s RUC Commit Time less the Resource’s Sync-To-Min Time; and

(iii) Any RUC Make-Whole Payment Eligibility Period resulting from a RUC Commitment Period that contains an hour for which the Resource Commitment Status is Self-Commit.

(f) For each RUC Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time multiplied by 12 rounded down to the nearest whole interval or (2) 24 Hours multiplied by 12, and that portion of the Start-Up Offer is included as a cost in each interval of the RUC Make-Whole Payment Eligibility Period until the sum of these interval costs are equal to the RTBM Start-Up Offer or until the end of the RUC Make-Whole Payment Eligibility Period, whichever occurs first.


(g) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the last RUC Make-Whole Payment Eligibility Period in the Operating Day, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the first RUC Make-Whole Payment Eligibility Period of the following Operating Day provided that the Resource has not been committed in the DA Market in any hour of the first RUC Make-Whole Payment Eligibility Period as described in (h) below. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $12,000. The RUC Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For RUC Make-Whole Payment calculation purposes, the RUC Commitment Period is split into two separate RUC Make-Whole Payment Eligibility Periods as described in (2).a above. The first RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs ($12,000 / 120 intervals) in hour 23 and 24 intervals. The second RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs in hours 1 through 8 intervals.

(h) If the Resource has been committed in the DA Market in a period adjacent to and following a RUC Make-Whole Payment Eligibility Period to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the Day-Ahead Make-Whole Payment Eligibility Period.

(i) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at a Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, and such cost is not due to any independent action of the Market Participant. In such cases, the additional costs are equal to the difference between the average Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs associated with Contingency Reserve is limited to the time period defined as the Transition State Time submitted in the Resource Offer. Recovery of these costs associated with Regulation-Up and/or Regulation-Down is limited to all Dispatch Intervals within the transition hour.

(4) The amount to each Asset Owner (AO) for each eligible Resource Settlement Location for a given RUC Make-Whole Payment Eligibility Period is calculated as follows:



#RtMwpCpAmt a, s, c = ( CncldStartAmt a, s, c

+ Max (0, ( { IF ( CncldStartRatio a, s, c = 0, THEN 1, ELSE 0) }

* ∑i

{ RtStartUpElig5minFlg a, s, i, c * RtStartUp5minAmt a, s, i, c

+ RtRucComStat5minFlg a, s, i, c * [ RtMwpCost5minAmt a, s, i, c

+ RtTransition5minAmt a, s, i, c + RtMwpRev5minAmt a, s, i, c

+ RtOom5minAmt a, s, i + RtRegAdj5minAmt a, s, i

– RtURDAdj5minAmt a, s, i, c – RtStatusAdj5minAmt a, s, i, c

– RtLimitAdj5minAmt a, s, i, c ] }

+∑h

( RtCcRegUpAdjHrlyAmt a, s, h, c + RtCcRegDnAdjHrlyAmt a, s, h, c

+ RtCcSpinAdjHrlyAmt a, s, h, c + RtCcSuppAdjHrlyAmt a, s, h, c ) ) ) ) * (-1)

Where,

(a) #RtMwpCost5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c *

( RtIncrEn5minAmt a, s, i

+ Max ( 0, [ RtNoLoad5minAmt a, s, i, c

- IF (DaClrdHrlyQty a, s, h < 0, THEN DaNoLoadHrlyAmt a, s, h, c , ELSE 0 ) ] )

+ RtMinEn5minAmt a, s, i, c

+ RtRegUpAvail5minAmt a, s, i, c +

RtRegDnAvail5minAmt a, s, i, c

+ PotRtRegUpMileMwp5minAmt a, s, i + PotRtRegDnMileMwp5minAmt a, s, i

+ RtSpinAvail5minAmt a, s, i, c + RtSuppAvail5minAmt a, s, i, c ) / 12



Comment [CD156]: Including these terms (as well as the mileage MWP) accounts for margin already used to offset the need for a mileage MWP. Order 755 Compliance.


(a.1) IF ABS (DaClrdHrlyQty a, s, h ) > = ABS ( RtBillMtr5minQty a, s, i )

THEN

RtIncrEn5minAmt a, s, i = 0

ELSE

#RtIncrEn5minAmt a, s, i = ∫y

x


Where:

X = Max (ABS (DaClrdHrlyQty a, s, h ), RtEffMin5minQty a, s, i )

AND

IF ControlStatus5minFlg a, s, i = “Regulating”

THEN


RtComMinRegCapOL5minQtya, s, i ,

RtDispMinRegCapOL5minQtya, s, i ,


ELSE


RtComMinEconCapOL5minQtya, s, i ,


RtDispMinEconCapOL5minQtya, s, i ,


AND

Y = Max ( (-1) * RtBillMtr5minQtya, s, i , 0)

(a.2) IF ABS (DaClrdHrlyQty a, s, h ) < RtEffMin5minQty a, s, i

THEN

#RtMinEn5minAmt a, s, i = ∫y

x

CurveOffer Energy Committed As RTBM

Where:

X = DaClrdHrlyQty a, s, h

Y = RtEffMin5minQty a, s, i

ELSE

RtMinEn5minAmt a, s, i, c = 0

(a.3) If RtRegUp5minQty a, s, i > RtFixedRegUp5minQty a, s, c, i

THEN


( Max ( 0, [ RtRegUp5minQty a, z, s, i - ∑z


* RtRegUpOffer a, s, i, c ) + RtRegUpUnusedMile5minAmt a, s, i

- ( RtRegUpMileOffer5minPrc a, s, i * RtRegUpExcessMile5minQty a, s, i )






ELSE

RtRegUpAvail5minAmt a, s, i, c =0

IF RtTranistionStateFlg a, s, i, c = 1 THEN


∑z

DaRegUpHrlyQty a, z, s, h

* Max ( 0, RtRegUpMcp5minPrc z, i - DaRegUpMcpHrlyPrc z, h )

ELSE

RtRegUpAvail5minAmt a, s, i, c = RtRegUpAvail5minAmt a, s, i = 0

(a.4) If RtRegDn5minQty a, s, i > RtFixedRegDn5minQty a, s, c, i

THEN

RtRegDnAvail5minAmt a, s, i, c =

( Max ( 0, [ RtRegDn5minQty a, z, s, i - ∑z


* RtRegDnOffer a, s, i, c ) + RtRegDnUnusedMile5minAmt a, s, i

- ( RtRegDnMileOffer5minPrc a, s, i, * RtRegDnExcessMile5minQty a, s, i )

ELSE

RtRegDnAvail5minAmt a, s, i, c =0






(a.5) If RtSpin5minQty a, s, i > RtFixedSpin5minQty a, s, c, i

THEN

RtSpinAvail5minAmt a, s, i, c =

Max ( 0, [ RtSpin5minQty a, z, s, i - ∑z

DaSpinHrlyQty a, z, s, h] )

* RtSpinOffer a, s, i, c

ELSE

RtSpinAvail5minAmt a, s, i, c =0

(a.6) If RtSupp5minQty a, s, i > RtFixedSupp5minQty a, s, c, i

THEN

RtSuppAvail5minAmt a, s, i, c =

Max ( 0, [ RtSupp5minQty a, z, s, i - ∑z

DaSuppHrlyQty a, z, s, h] )

* RtSuppOffer a, s, i, c

ELSE

RtSuppAvail5minAmt a, s, i, c =0

(b) #RtMwpRev5minAmt a, s, i, c =

RtRucComStat5minFlg a, s, i, c * [ ( ( RtLmp5minPrc s, i




* Min (0, [ RtBillMtr5minQty a, s, i - DaClrdHrlyQty a, s, h ] ) ) / 12 )

+ RtRegUpRev5minAmt a, s, i, c + RtRegDnRev5minAmt a, s, i, c

+ RegUpUnusedMileMwp5minAmt a, s, i

+ RegDnUnusedMileMwp5minAmt a, s, i

+ RtSpinRev5minAmt a, s, i, c + RtSuppRev5minAmt a, s, i, c ]

(b.1) RtRegUpRev5minAmt a, s, i, c =


* ( ( Max ( 0, [ RtRegUp5minQty a, z, s, i - ∑z


* RtRegUpMcp5minPrc z, i ) / 12 ) - + RtRegUpExcessMile5minAmt a, s, i

- RtRegUpUnusedMileMwp5minAmt a, s, i

(b.2) RtRegDnRev5minAmt a, s, i, c =


*( ( Max ( 0, [ RtRegDn5minQty a, z, s, i - ∑z


* RtRegDnMcp5minPrc z, i ) / 12 ) - + RtRegDnExcessMile5minAmt a, s, i

- RtRegDnUnusedMileMwp5minAmt a, s, i

(b.3) RtSpinRev5minAmt a, s, i, c =


Comment [CD167]: Order 755 Compliance.

Comment [CD168]: Removing this filter makes the determinant available for Mileage MWP later. Order 755 Compliance.


Comment [WRC170]: Order 755 Compliance.

Comment [CD171]: Removing this filter makes the determinant available for Mileage MWP later. Order 755 Compliance


Comment [WRC173]: Order 755 Compliance.


*( Max ( 0, [ RtSpin5minQty a, z, s, i - ∑z

DaSpinHrlyQty a, z, s, h ] )

* RtSpinMcp5minPrc z, i ) / 12

(b.4) RtSuppRev5minAmt a, s, i, c =


*( Max ( 0, [ RtSupp5minQty a, z, s, i - ∑z

DaSuppHrlyQty a, z, s, h ] )

* RtSuppMcp5minPrc z, i ) / 12

(c) #CncldStartAmt a, s, c =

∑i

( RtStartUp5minAmt a, s, i, c * RtStartUpElig5minFlg a, s, i, c )

* CncldStartRatio a, s, c

CncldStartRatio a, s, c = (ElapsedTime a, s, c / StartUpTime a, s, c )

(d) In any Dispatch Interval in which the Resource has operated outside of its Operating Tolerance and that Resource has not been exempted from URD per Section 4.4.4.1, any incremental Energy costs associated with actual Energy output above the Resource’s Desired Dispatch is not eligible for recovery. The URD adjustment is calculated as follows:

IF ABS (URD5minQty a, s, i ) > ResOpTol5minQty a, s, i AND

( XmptDev5minFlg a, s, i = 0 )

THEN


#RtURDAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c


ELSE

RtURDAdj5minAmt a, s, i, c = 0

(d.1) URD5minQty a, s, i =

Max ( RtBillMtr5minQty a, s, i * (-1), 0 ) - RtAvgSetPoint5minQty a, s, i

(d.2) ResOpTol5minQty a, s, i =

Min ( URDMaxTol5minQty i , Max (URDMinTol5minQty i ,

URDTol5minPct i * RtDispMaxEmerCapOL5minQty a, s, i ) )

(d.3) IF RtDesiredEn5minQty a, s, i < ABS (DaClrdHrlyQty a, s, h )

THEN

#RtDesiredEn5minAmt a, s, i = RtIncrEn5minAmt a, s, i

ELSE

#RtDesiredEn5minAmt a, s, i = ∫y

x


Where:

X = Max (ABS (DaClrdHrlyQty a, s, h ) , RtEffMin5minQty a, s, i )

Y = Max ( X, RtDesiredEn5minQtya, s, i )

(e) In any Dispatch Interval in which a Resource is in “Manual” status, any incremental Energy costs associated with actual Energy output above the Resource’s Desired Dispatch is not eligible for recovery. The status change adjustment is calculated as follows:


IF ControlStatus5minFlg a, s, i = “Manual”

AND ABS (URD5minQty a, s, i ) <= ResOpTol5minQty a, s, i

THEN

#RtStatusAdj5minAmt a, s, i, c = RtRucComStat5minFlg a, s, i, c


ELSE

RtStatusAdj5minAmt a, s, i, c = 0

(f) In any Dispatch Interval in which a Resource has increased its Minimum Economic Capacity Operating Limit (or its Minimum Regulation Capacity Operating Limit if the Resource has cleared for Regulation-Up Service or Regulation-Down Service) above the Resource’s minimum limits used by SPP in the commitment decision or the minimum limits used to move from one configuration to another in the case of a combined cycle Resource, the Resource is not in “Manual” status and the increase in minimum limit is greater than the Resource’s Operating Tolerance, any incremental Energy costs associated with actual Energy output above the Resource’s Desired Dispatch is not eligible for recovery. The limit change adjustment is calculated as follows:

IF ControlStatus5minFlg a, s, i < > “Regulating” AND

ControlStatus5minFlg a, s, i < > “Manual” AND

( RtDispMinEconCapOL5minQty a, s, i

- RtComMinEconCapOL5minQty a, s, i ) > ResOpTol5minQty a, s, i AND

ABS (URD5minQty a, s, i ) <= ResOpTol5minQty a, s, i

THEN







ELSE IF

ControlStatus5minFlg a, s, i = “Regulating” AND

( RtDispMinRegCapOL5minQty a, s, i

- RtComMinRegCapOL5minQty a, s, i ) > ResOpTol5minQty a, s, i AND

ABS (URD5minQty a, s, i ) < =ResOpTol5minQty a, s, i

THEN



ELSE

RtLimitAdj5minAmt a, s, i, c = 0

(g) If ∑i

RtTranistionStateFlg a, s, i, c > = 1 THEN

RtCcRegUpAdjHrlyAmt a, s, h, c =

* Max ( 0, ∑i

( RtCcRegUpAdj5minAmt a, s, i c * RtRucComStat5minFlg a, s,

i, c )

ELSE

RtCcRegUpAdjHrlyAmt a, s, h, c = 0

(g.1) RtCcRegUpAdj5minAmt a, s, i, c =


(DaRegUpHrlyAmt a, s, h / 12 + RtRegUp5minAmt a, s, i )

ELSE

RtCcRegUpAdj5minAmt a, s, i, c = 0

(h) If ∑i

RtTranistionStateFlg a, s, i, c > = 1 THEN

RtCcRegDnAdjHrlyAmt a, s, h, c =

* Max ( 0, ∑i

( RtCcRegDnAdj5minAmt a, s, i c * RtRucComStat5minFlg a, s,

i, c )

ELSE

RtCcRegDnAdjHrlyAmt a, s, h, c = 0

(h.1) RtCcRegDnAdj5minAmt a, s, i, c =

(DaRegDnHrlyAmt a, s, h / 12 + RtRegUp5minAmt a, s, i )

ELSE

RtCcRegDnAdj5minAmt a, s, i, c = 0

(i) IF RtTranistionStateFlg a, s, i, c = 1 THEN

RtCcSpinAdj5minAmt a, s, i, c =

RtRucComStat5minFlg a, s, i, c * (DaSpinHrlyAmt a, s, h / 12 + RtSpin5minAmt a, s, i )


ELSE

RtCcSpin5minAmt a, s, i, c = 0

(i.1) RtCcSpinAdjHrlyAmt a, s, h, c =

Max ( 0, ∑i

RtCcSpinAdj5minAmt a, s, i, c )

(j) IF RtTranistionStateFlg a, s, i = 1 THEN

RtCcSuppAdj5minAmt a, s, i, c =

RtRucComStat5minFlg a, s, i, c * (DaSuppHrlyAmt a, s, h / 12 + RtSupp5minAmt a, s, i )

ELSE

RtCcSupp5minAmt a, s, i, c = 0

(j.1) RtCcSuppAdjHrlyAmt a, s, h, c =

Max ( 0, ∑i

RtCcSuppAdj5minAmt a, s, i, c


RtMwpDlyAmt a, s, d = ∑c

RtMwpCpAmt a, s, c


RtMwpAoAmt a, m, d = ∑s

RtMwpDlyAmt a, s, d




RtMwpMpAmt m, d = ∑a

RtMwpAoAmt a, m, d

(8) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates RUC Make-Whole Payment $ per RUC Make-Whole-Payment Eligibility Period for each Asset Owner as follows:

(a) #EqrRtMwp5minPrc a, s, c = (-1) * RtMwpCpAmt a, s, c

(b) IF #EqrRtMwp5minPrc a, s, c > 0 THEN #EqrRtMwp5minQty a, s, c = 1



Variable

Unit

Settlement Interval

Definition

RtMwpCpAmt a, s, c $ Eligibility Period

RUC Make-Whole-Payment Amount per AO per Settlement Location per RUC Make-Whole-Payment Eligibility Period - The amount to AO a for RUC Make-Whole-Payment Eligibility Period c at Resource Settlement Location s..

DaClrdHrlyQty a, s, h MWh

Hour Day-Ahead Cleared Energy Quantity per AO per Settlement Location per Hour - The value described under Section 4.5.8.1 for AO a’s combined cycle resource at Settlement Location s for the Hour.

RtTransition5minAmt a, s, i, c $ Eligibility Period

Real-Time Transition Cost Amount per AO per Settlement Location in RUC Make-Whole-Payment Eligibility Period - The RTBM Transition State Offer associated with AO a’s eligible combined cycle Resource at Settlement Location s in Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtTransitionStateFlg a, s, i, c Flag Dispatch Interval

Real-Time Transition State Flag per AO per Settlement Location in RUC Make-Whole-Payment Eligibility Period – This flag is set to 1 in Dispatch Interval i for Asset Owner a when a combined cycle Resource at Settlement Location s is transitioning from one configuration to another in RUC Make-Whole-Payment Eligibility Period c.




Variable

Unit

Settlement Interval

Definition

RtStartUp5minAmt a s, i, c $ Eligibility Period

Real-Time Start-Up Cost Amount per AO per Settlement Location per Dispatch Interval per RUC Make-Whole-Payment Eligibility Period - The RTBM Start-Up Offer associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c in Dispatch Interval i. This value is calculated by dividing RtStartUpAmt a s, c by the lesser of the Resource’s (RtMinRunTime a, i, s, c /5), rounded down to the nearest whole number of intervals or 288 intervals, except that, if RtMinRunTime a, i, s, c is less than 5 minutes, then RtStartUpAmt a s, c is divided by 1. These interval values are carried forward into the following Operating Day, if needed, to ensure recovery of any remaining RtStartUpAmt a s, c.

RtStartUpAmt a s, c


$ Eligibility Period

Real-Time Start-Up Cost Amount per AO per Settlement Location per RUC Make-Whole-Payment Eligibility Period - The RTBM Start-Up Offer used in the commitment decision, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c.

RtStartUpElig5minFlg a, s, i, c None Dispatch Interval

RUC Start-Up Recovery Eligibility Flag per AO per Resource Settlement Location per Dispatch Interval per RUC Make-Whole-Payment Eligibility Period – This flag is set equal to 1 in each Dispatch Interval of a RUC Make-Whole-Payment Eligibility Period where the Resource is eligible to recover start-up costs, or 0 where the Resource is not eligible to recover start-up costs.


Variable

Unit

Settlement Interval

Definition

RtRucComStat5minFlg a, s, i, c None Dispatch Interval

RUC Commitment Status Flag per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – This flag is set equal to 1 for each Dispatch Interval of a RUC Make-Whole-Payment Eligibility Period in which a Resource’s Commitment Status was “Market” or “Reliability”, or 0 if its Commitment Status was “Self”.

CncldStartRatio a, s, c None Canceled Start Ratio per Resource Settlement Location in RUC Make-Whole-Payment Eligibility Period – The ratio of ElapsedTime a, s, c to StartUpTime a, s, c as calculated for each Dispatch Interval in RUC Make-Whole-Payment Eligibility Period c.

RtMinRunTime a, i, s, c

Time Dispatch

Interval Real-Time Minimum Run Time per AO per Settlement Location Per Dispatch Interval per RUC Make-Whole-Payment Eligibility Period – The Minimum Run Time, in minutes, used in the commitment decision, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c as submitted as part of the RTBM Market Offer.

RtSynchToMinTime a, i, s, c Time Dispatch Interval

Real-Time Synch To Minimum Time per AO per Settlement Location Per Dispatch Interval per RUC Make-Whole-Payment Eligibility Period – The Synch To Minimum Time, in minutes, used in determining Start-Up Recovery Eligibility, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c as submitted as part of the RTBM Market Offer.


Variable

Unit

Settlement Interval

Definition

RtNoLoad5minAmt a, i, s, c $ Dispatch Interval

Real-Time No-Load Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The No-Load Offer used in the commitment decision, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtMwpCost5minAmt a, s, i, c $ Dispatch Interval

RUC Make-Whole-Payment Cost per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The total Energy and Operating Reserve cost at actual Resource output, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

PotRtRegUpMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.28

PotRtRegDnMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.29

RtMwpRev5minAmt a, s, i, c $ Dispatch Interval

RUC Make-Whole-Payment Revenue per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The total Energy and Operating Reserve revenue at actual Resource output, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.


Variable

Unit

Settlement Interval

Definition

RtRegUpUnusedMileMwp5minAmt a, s, i $ Dispatch Interval

Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.28

RtRegDnUnusedMileMwp5minAmt a, s, i $ Dispatch Interval

Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.29

RtRegUpMileOffer5minPrc a, s, i $/MW Dispatch Interval

Real-Time Regulation-Up Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - The value described under Section 4.5.9.28

RtRegUpExcessMile5minQty a, s, i MW Dispatch Interval

Real-Time Excess Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.4

RtRegDnMileOffer5minPrc a, s, i $/MW Dispatch Interval

Real-Time Regulation-Down Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - The value described under Section 4.5.9.29

RtRegDnExcessMile5minQty a, s, i MW Dispatch Interval

Real-Time Excess Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.5

CncldStartAmt a, s, c $ Eligibility Period

Real-Time Cancelled Start Amount per AO per Settlement Location per for the RUC Make-Whole-Payment Eligibility Period – The Start-Up Offer cost reimbursement for an SPP cancelled start-up, in dollars, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c.


Variable

Unit

Settlement Interval

Definition

ElapsedTime a, s, c Time Eligibility Period

Elapsed Time per AO per Settlement Location per for the RUC Make-Whole-Payment Eligibility Period – The elapsed time, in minutes, between the start of a Resource’s StartUpTime a, s, c and the time SPP cancelled the start-up, in dollars, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c.

StartUpTime a, s, c Time Eligibility Period

Start-up Time per AO per Settlement Location for the RUC Make-Whole-Payment Eligibility Period – The Start-Up Time, in minutes, used in the commitment decision associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c as specified in the RTBM Offer submitted prior to the RUC Make-Whole-Payment Eligibility Period.

RtURDAdj5minAmt a, s, i, c $ Dispatch Interval

URD Adjustment per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The reduction in RUC Make-Whole Payment Amount associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c when the Resource’s URD5minQty a, s, i is outside of the Resource’s ResOpTol5minQty a, s, i.

URD5minQty a, s, i MW Dispatch Interval

Uninstructed Resource Deviation per AO per Settlement Location per Dispatch Interval – The Uninstructed Resource Deviation associated with AO a’s Resource at Settlement Location s in Dispatch Interval i.

ResOpTol5minQty a, s, i MW Dispatch Interval

Resource Operating Tolerance per AO per Settlement Location per Dispatch Interval – The Resource Operating Tolerance associated with AO a’s Resource at Settlement Location s in Dispatch Interval i.


Variable

Unit

Settlement Interval

Definition

URDMaxTol5minQty i MW Dispatch Interval

Uninstructed Resource Deviation Maximum Tolerance per Dispatch Interval – The maximum value of ResOpTol5minQty a, s, i that is currently set at 20 MW.

URDMinTol5minQty i MW Dispatch Interval

Uninstructed Resource Deviation Minimum Tolerance per Dispatch Interval – The minimum value of ResOpTol5minQty a, s, i that is currently set at 5 MW.

URDTol5minPct i Percent Dispatch Interval

Uninstructed Resource Deviation Tolerance Percentage per Dispatch Interval – The percentage used to calculate the value of ResOpTol5minQty a, s, i that is currently set at 5%.

RtAvgSetPoint5minQty a, s, i MW Dispatch Interval

Real-Time Average Setpoint Instruction MW per AO per Settlement Location per Dispatch Interval – The average Setpoint Instruction over Dispatch Interval i for AO a’s Resource at Settlement Location s.

XmptDev5minFlg a, s, i none Dispatch Interval

URD Exemption Flag per AO per Resource Settlement Location per Dispatch Interval – A flag associated with AO a’s eligible Resource at Settlement Location s indicating that a Resource that has operated outside of its Operating Tolerance is or is not exempt from any associated penalty charges in Dispatch Interval i. If the flag is equal to zero, the Resource is not exempt. Otherwise, the flag will be set to a positive integer number which will indicate the reason of the exemption as specified under Section 4.4.4.1.1

RtStatusAdj5minAmt a, s, i, c $ Dispatch Interval

Resource Status Change Adjustment per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The reduction in RUC Make-Whole Payment Amount associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c when the Resource’s Control Status is set to “Manual”.


Variable

Unit

Settlement Interval

Definition

ControlStatus5minFlg a, s, i None Dispatch Interval

Control Status per AO per Settlement Location per Dispatch Interval – A Resource status indicator associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as set by SPP operators that indicates the current dispatchable status of the Resource.

RtDispMaxEmerCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Maximum Emergency Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Maximum Emergency Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i.

RtEffMin5minQty a, s, i MW Dispatch Interval

Real-Time Effective Minimum Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Effective Minimum Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i.

RtDispMinEconCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Minimum Economic Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Minimum Economic Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i.

RtDispMinRegCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Minimum Regulation Capacity Operating Limit Quantity per AO per Settlement Location per Dispatch Interval – The Minimum Regulation Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i.


Variable

Unit

Settlement Interval

Definition

RtLimitAdj5minAmt a, s, i, c $ Dispatch Interval

Resource Limit Change Adjustment per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period – The reduction in RUC Make-Whole Payment Amount associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c for a Real-Time increase in minimum limit.

RtComMinEconCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Minimum Economic Capacity Operating Limit Quantity per AO per Settlement Location – The Minimum Economic Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as submitted in an RTBM Offer prior to the RUC Make-Whole-Payment Eligibility Period that was used in making the initial Resource commitment decision or was used in making the decision to move from one configuration to another in the case of a combined cycle Resource.

RtComMinRegCapOL5minQty a, s, i MW Dispatch Interval

Real-Time Minimum Regulation Capacity Operating Limit Quantity per AO per Settlement Location– The Minimum Regulation Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i as submitted in an RTBM Offer prior to the RUC Make-Whole-Payment Eligibility Period that was used in making the initial Resource commitment decision or was used in making the decision to move from one configuration to another in the case of a combined cycle Resource.

Comment [MPRR101.180]:



Variable

Unit

Settlement Interval

Definition

RtIncrEn5minAmt a, s, i $ Dispatch Interval

Real-Time 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 from the Effective Minimum Capacity Operating Limit to RtBillMtr5minQty a, s, i.

RtMinEn5minAmt a, s, i, c $ Dispatch Interval

Real-Time Energy Cost at Minimum Limit per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The average incremental energy offer cost at the Effective Minimum Capacity Operating Limit associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c

RtDesiredEn5minAmt a, s, i $ Dispatch Interval

Real-Time Energy Cost at Desired Dispatch Quantity per AO per Settlement Location per Dispatch Interval - The average incremental energy offer cost associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i, in dollars, from the Effective Minimum Capacity Operating Limit to RtDesiredEn5minQty a, s, i.

RtDesiredEn5minQty a, s, i MW Dispatch Interval

Real-Time 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-Committed Minimum Capacity Limit (Economic or Regulating, as applicable) as an output floor and the As-Committed Maximum Capacity Limit (Economic or Regulating, as applicable) as an output ceiling.


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 value calculated under Section 4.5.9.9.

RtRegAdj5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation Deployment Adjustment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.19.

RtRegUpOffer a, s, i, c



Real-Time Regulation-Up Service Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Regulation-Up Service Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.

RtRegDnOffer a, s, i, c (Not Available on Settlement Statement)


Real-Time Regulation-Down Service Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Regulation-Down Service Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.

RtSpinOffer a, s, i, c (Not Available on Settlement Statement)


Real-Time Spinning Reserve Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Spinning Reserve Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.

RtSuppOffer a, s, i, c (Not Available on Settlement Statement)


Real-Time Supplemental Reserve Offer per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Supplemental Reserve Offer associated with AO a’s Resource Settlement Location s for Dispatch Interval i for RUC Make-Whole-Payment Eligibility Period c.






Variable

Unit

Settlement Interval

Definition

RtFixedRegUp5minQty a, s, c, i

MW Dispatch

Interval Real-Time Fixed Regulation-Up Quantity per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Fixed Regulation-Up MW specified in the Regulation-Up Offer associated with AO a’s Resource Settlement Location s at the time the commitment decision was made for RUC Make-Whole-Payment Eligibility Period c of the RTBM in Dispatch Interval i.

RtFixedRegDn5minQty a, s, c, i

MW Dispatch

Interval Real-Time Fixed Regulation-Down Quantity per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Fixed Regulation-Down MW specified in the Regulation-Down Offer associated with AO a’s Resource Settlement Location s at the time the commitment decision was made for RUC Make-Whole-Payment Eligibility Period c of the RTBM in Dispatch Interval i.

RtFixedSpin5minQty a, s, c, i

MW Dispatch

Interval Real-Time Fixed Spinning Reserve Quantity per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Fixed Spinning Reserve MW specified in the Spinning Reserve Offer associated with AO a’s Resource Settlement Location s at the time the commitment decision was made for RUC Make-Whole-Payment Eligibility Period c of the RTBM in Dispatch Interval i.

RtFixedSupp5minQty a, s, c, i

MW Dispatch

Interval Real-Time Fixed Supplemental Reserve Quantity per AO per Resource Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Fixed Supplemental Reserve MW specified in the Supplemental Reserve Offer associated with AO a’s Resource Settlement Location s at the time the commitment decision was made for RUC Make-Whole-Payment Eligibility Period c of the RTBM in Dispatch Interval i.


Variable

Unit

Settlement Interval

Definition

RtRegUpAvail5minAmt a, s, i, c $ Dispatch Interval

Real-Time Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The Regulation-Up Service Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtRegDnAvail5minAmt a, s, i, c $ Dispatch Interval

Real-Time Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval in the RUC Make-Whole-Payment Eligibility Period - The Regulation-Down Service Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in DA Market Commitment Period c.

RtRegUpUnusedMile5minAmt a, s, i $ Dispatch Interval

Real-Time Unused Regulation-Up Mileage Amount per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.4.

RtRegUpExcessMile5minAmt a, s, i $ Dispatch Interval

Real-Time Excess Regulation-Up Mileage Amount per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.4.

RtRegDnUnusedMile5minAmt a, s, i $ Dispatch Interval

Real-Time Unused Regulation-Down Mileage Amount per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.5.

RtRegDnExcessMile5minAmt a, s, i $ Dispatch Interval

Real-Time Excess Regulation-Down Mileage Amount per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.5.


Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.24.











Variable

Unit

Settlement Interval

Definition


Real-Time Unused Regulation-Dn Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The value calculated under Section 4.5.9.25.

RtSpinAvail5minAmt a, s, i, c $ Dispatch Interval

Real-Time Spin Offer Cost Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period - The Spinning Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtSuppAvail5minAmt a, s, i, c $ Dispatch Interval

Real-Time Supplemental Offer Cost Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period - The Supplemental Reserve Offer cost, in dollars, associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtLmp5minPrc s, i

$/MWh

Dispatch Interval

Real-Time LMP - The value defined under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i.

RtBillMtr5minQty a, s, i MW Dispatch Interval

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.


Real-Time MCP for Regulation-Up per Reserve Zone - The value defined under Section 4.5.9.4.


Real-Time MCP for Regulation-Down per Reserve Zone - The value defined under Section 4.5.9.5.

RtSpinMcp5minPrc z, i $/MW Dispatch Interval

Real-Time MCP for Spinning Reserve per Reserve Zone - The value defined under Section 4.5.9.6.

RtSuppMcp5minPrc z, i $/MW Dispatch Interval

Real-Time MCP for Supplemental Reserve per Reserve Zone - The value defined under Section 4.5.9.7.







Variable

Unit

Settlement Interval

Definition

RtCcRegUpAdjHrlyAmt a, s, h, c $ Hour Real-Time Combined Cycle Regulation-Up Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Regulation-Up positions during transitions between configurations for Hour h.

RtCcRegDnAdjHrlyAmt a, s, h, c $ Hour Real-Time Combined Cycle Regulation-Down Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Regulation-Down positions during transitions between configurations for Hour h.

RtCcSpinAdjHrlyAmt a, s, h, c $ Hour Real-Time Combined Cycle Spinning Reserve Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Spinning Reserve position during transitions between configurations for Hour h.

RtCcSuppAdjHrlyAmt a, s, h, c $ Hour Real-Time Combined Cycle Supplemental Reserve Cost Adjustment per AO per Settlement Location per Hour – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Supplemental Reserve position during transitions between configurations for Hour h.

RtCcRegUpAdj5minAmt a, s, i, c $ Dispatch Interval

Real-Time Combined Cycle Regulation-Up Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Regulation-Up position during transitions between configurations for Dispatch Interval i.







Variable

Unit

Settlement Interval

Definition

RTCcRegDnAdj5minAmt a, s, i, c $ Dispatch Interval

Real-Time Combined Cycle Regulation-Down Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Regulation-Down position during transitions between configurations for Dispatch Interval i.

RtCcSpinAdj5minAmt a, s, i, c $ Dispatch Interval

Real-Time Combined Cycle Spinning Reserve Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Spinning Reserve position during transitions between configurations for Dispatch Interval i.

RTCcSuppAdj5minAmt a, s, i, c $ Dispatch Interval

Real-Time Combined Cycle Supplemental Reserve Cost Adjustment per AO per Settlement Location per Dispatch Interval – the additional cost incurred by AO a at Combined Cycle Settlement Location s associated with the buying back of Day-Ahead Market Supplemental Reserve position during transitions between configurations for Dispatch Interval i.

RtRegUpRev5minAmt a, s, i, c $ Dispatch Interval

Real-Time Regulation-Up Service Revenue Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Real-Time incremental Regulation-Up Service revenue associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtRegDnRev5minAmt a, s, i, c $ Dispatch Interval

Real-Time Regulation-Down Service Revenue Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Real-Time incremental Regulation-Down Service revenue associated









Variable

Unit

Settlement Interval

Definition

with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtSpinRev5minAmt a, s, i, c $ Dispatch Interval

Real-Time Spinning Reserve Revenue Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Real-Time incremental Spinning Reserve associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtSuppRev5minAmt a, s, i, c $ Dispatch Interval

Real-Time Supplemental Reserve Revenue Amount per AO per Settlement Location per Dispatch Interval in RUC Make-Whole-Payment Eligibility Period – The Real-Time incremental Supplemental Reserve revenue associated with AO a’s eligible Resource at Settlement Location s for Dispatch Interval i in RUC Make-Whole-Payment Eligibility Period c.

RtMwpDlyAmt a, s, d $ Operating Day RUC Make-Whole-Payment Amount per AO per Settlement Location per Operating Day - The RUC Make-whole amount to AO a for Operating Day d at Resource Settlement Location s.

RtMwpAoAmt a, m, d $ Operating Day RUC Make-Whole-Payment Amount per AO per Operating Day - The RUC Make-whole amount to AO a associated with Market Participant m for Operating Day d.

RtMwpMpAmt m, d $ Operating Day RUC Make-Whole-Payment Amount per MP per Operating Day - The RUC Make-whole amount to Market Participant m for Operating Day d.


Variable

Unit

Settlement Interval

Definition

EqrRtMwp5minPrc a, s, c $ Eligibility Period

RUC Electric Quarterly Reporting Make-Whole-Payment Amount per AO per Settlement Location per RUC Make-Whole-Payment Eligibility Period - The RUC make-whole amount to AO a for RUC Make-Whole-Payment Eligibility Period c at Resource Settlement Location s for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements..

EqrRtMwp5minQty a, s, c MWh Eligibility Period

RUC Electric Quarterly Reporting Make-Whole-Payment Quantity per AO per Settlement Location per RUC Make-Whole-Payment Eligibility Period – This value is set equal to 1 if EqrRtMwp5minPrc a, s, c > 0 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements.


Real-Time Cleared Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.4

DaRegUpHrlyAmt a, s, h $ Hour Day-Ahead Regulation-Up Service Amount per AO per Settlement Location per Hour – The amount calculated under Section 4.5.8.4

DaRegDnHrlyAmt a, s, h $ Hour Day-Ahead Regulation-Down Service Amount per AO per Settlement Location per Hour – The amount calculated under Section 4.5.8.5


Real-Time Cleared Regulation-Down Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.5


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.

DaSpinHrlyQty a, z, s, h MW Hour Day-Ahead Spinning Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.6.


Variable

Unit

Settlement Interval

Definition


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.

DaSuppHrlyQty a, z, s, h MW Hour Day-Ahead Supplemental Reserve Hourly Quantity per Asset Owner per Settlement Location per Reserve Zone per Hour – The value described under Section 4.5.8.7.

a none none An Asset Owner. i none none A Dispatch Interval. h none none An Hour. d An Operating Day. s none none A Settlement Location. c none none A RUC Make-Whole-Payment Eligibility Period. m none none A Market Participant.


4.5.9.11 Real-Time Regulation-Up Service Distribution Amount

(1) A RTBM charge or credit will be calculated for each Asset Owner for each hour. The Asset Owner amount will be equal to the Asset Owner’s real-time load ratio share of the net RTBM Regulation-Up Service procurement costs. The amount to each Asset Owner is calculated as follows:

#RtRegUpDistHrlyAmt a, s, h =

RtRegUpSppHrlyAmt h * RtLoadRatioShareHrlyFct a, s, h * (-1)

Where,

(a) RtRegUpSppHrlyAmt h = ∑a∑

s RtRegUpHrlyAmt a, s, h

+ RtRegUpUnusedMileMwpHrlyAmt a, s, h

(b) #RtLoadRatioShareHrlyFct a, s, h = [ [ Max ( 0, ∑i

RtBillMtr5minQty a, s, i )

+ Max ( 0, ∑i∑

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

/ RtLoadSppHrlyQty h


RtRegUpDistDlyAmt a, s, d = ∑h

RtRegUpDistHrlyAmt a, s, h


RtRegUpDistAoAmt a, m, d = ∑s

RtRegUpDistDlyAmt a, s, d

∑a

∑s



Comment [MCB214]: Order 755 Compliance




RtRegUpDistMpAmt m, d = ∑a

RtRegUpDistAoAmt a, m, d



Unit

Settlement Interval

Definition

RtRegUpDistHrlyAmt a, s, h $ Hour Real-Time Regulation-Up Service Distribution Amount per AO per Settlement Location per Hour - The amount to AO a for AO a’s share of the total of RtRegUpHrlyAmt a, s, h in Hour h.

RtLoadRatioShareHrlyFct a, s, h Ratio Hour Real-Time Load Ratio Share Factor per AO per Settlement Location per Hour – AO a’s percentage share of total SPP actual real-time load plus Export Interchange Transactions at Settlement Location s in Hour h.

RtRegUpHrlyAmt a, s, h $ Hour Real-Time Regulation-Up Service Amount per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.4.

RtRegUpUnusedMileMwpHrlyAmt a,

s, h $ Hour Real-Time Unused Regulation-Up Mileage Make Whole Payment

Amount per AO per Settlement Location per Hour - The value described under Section 4.5.9.23.

RtRegUpSppHrlyAmt h $ Hour Real-Time Regulation-Up Service Amount per Hour – The SPP total amount of the values calculated under Section 4.5.9.4 in Hour h.


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.

RtLoadSppHrlyQty h MWh Hour Real-Time SPP Load per Hour – SPP total actual load and Export Interchange Transactions in Hour h as calculated under Section 4.5.8.8.

RsgCrdFlg t


none none Reserve Sharing Group Contingency Reserve Deployment Flag per Event – The value described under Section 4.5.8.8.

RtRegUpDistDlyAmt a, s, d $ Operating Day

Real-Time Regulation-Up Service Distribution Amount per AO Operating Day. The amount to AO a for total net Regulation-Up Service procurement costs in Operating Day d.








Variable

Unit

Settlement Interval

Definition

RtRegUpDistAoAmt a, m, d $ Operating Day

Real-Time Regulation-Up Service Distribution Amount per AO per Operating Day The amount to AO a associated with Market Participant m for total net Regulation-Up Service procurement costs in Operating Day d.

RtRegUpDistMpAmt m, d $ Operating Day

Real-Time Regulation-Up Service Distribution Amount per MP per Operating Day The amount to MP m for total net Regulation-Up Service procurement costs in Operating Day d.

a none none An Asset Owner. s none none A 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.

d none none An Operating Day. m none none A Market Participant.






4.5.9.12 Real-Time Regulation-Down Service Distribution Amount

(1) A RTBM charge or credit will be calculated for each Asset Owner for each hour. The Asset Owner amount will be equal to the Asset Owner’s real-time load ratio share of the net RTBM Regulation-Down Service procurement costs. The amount to each Asset Owner is calculated as follows:

#RtRegDnDistHrlyAmt a, s, h =

RtRegDnSppHrlyAmt h * RtLoadRatioShareHrlyFct a, s, h * (-1)

Where,

RtRegDnSppHrlyAmt h = ∑a∑

s RtRegDnHrlyAmt a, s, h

+ RtRegDnUnusedMileMwpHrlyAmt a, s, h


RtRegDnDistDlyAmt a, s, d = ∑h

RtRegDnDistHrlyAmt a, s, h


RtRegDnDistAoAmt a, m, d = ∑s

RtRegDnDistDlyAmt a, s, d


RtRegDnDistMpAmt m, d = ∑a

RtRegDnDistAoAmt a, m, d

∑a

∑s



Comment [MCB228]: Order 755 Compliance.




Unit

Settlement Interval

Definition

RtRegDnDistHrlyAmt a, s, h $ Hour Real-Time Regulation-Down Service Distribution Amount per AO per Settlement Location per Hour - The amount to AO a for AO a’s share of the total of RtRegDnHrlyAmt a, s, h in Hour h.

RtLoadRatioShareHrlyFct a, s, h Ratio Hour Real-Time Load Ratio Share Factor per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.11.

RtRegDnHrlyAmt a, s, h $ Hour Real-Time Regulation-Down Service Amount per AO per Settlement Location per Hour – The value calculated under Section 4.5.9.5.

RtRegDnUnusedMileMwpHrlyAmt a,

s, h $ Hour Real-Time Unused Regulation-Down Mileage Make Whole Payment

Amount per AO per Settlement Location per Hour - The value described under Section 4.5.9.24.

RtRegDnSppHrlyAmt h $ Hour Real-Time Regulation-Down Service Amount per Hour – The SPP total amount of the values calculated under Section 4.5.9.5 in Hour h.

RtRegDnDistDlyAmt a, s, d $ Operating Day

Real-Time Regulation-Down Service Distribution Amount per AO per Operating Day The amount to AO a for total net Regulation-Down Service procurement costs in Operating Day d.

RtRegDnDistAoAmt a, m, d $ Operating Day

Real-Time Regulation-Down Service Distribution Amount per AO per Operating Day The amount to AO a associated with Market Participant m for total net Regulation-Down Service procurement costs in Operating Day d.

RtRegDnDistMpAmt m, d $ Operating Day

Real-Time Regulation-Down Service Distribution Amount per MP per Operating Day The amount to MP m for total net Regulation-Down Service procurement costs in Operating Day d.

a none none An Asset Owner. s none none A Settlement Location. h none none An Hour. d none none An Operating Day. m none none A Market Participant.












4.5.9.28 Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount

(1) A RTBM credit will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval when that Asset Owner is charged for Unused Regulation-Up Mileage at a rate that is in excess of the Asset Owner’s Regulation-Up Mileage Offer to the extent the Resource’s Regulation-Up Service margin is not sufficient to offset the charge induced by the difference in the two rates. The amount will be calculated as follows:

#RtRegUpUnusedMileMwp5minAmt a, s, i =

DaRegUpUnusedMileMwp5minAmt a, s, i

+ RtRegUpUnusedMileMwp5minAmt a, s, i

Where,

(a) DaRegUpUnusedMileMwp5minAmt a, s, i =

[ Max ( 0, DaRegUpMargin5minAmt a, s, i

+ PotDaRegUpMileMwp5minAmt a, s, i ) ] *(-1)

(a.1) #DaRegUpMargin5minAmt a, s, i = Min { 0,

Cast h to i [ ( DaRegUpHrlyAmt a, h, s

+ IF { (DaClrdComStatHrlyFlg h, s, c = 0 ) AND

(∑z

DaRegUpHrlyQty a, z, s, h <= DaFixedRegUpHrlyQty a, s, h)

THEN 0

ELSE DaRegUpAvailHrlyAmt a, h, s } ) / 12 ]

- ∑z

[ Min [ 0, ( RtRegUp5minQty a, z, s, i


Comment [MCB240]: Order 755 Compliance

Field Code Changed

Field Code Changed


- ∑z

IF { (DaClrdComStatHrlyFlg h, s, c = 0 ) AND

(∑z

DaRegUpHrlyQty a, z, s, h <= DaFixedRegUpHrlyQty a, s, h)

THEN 0

ELSE ∑z

DaRegUpHrlyQty a, z, s, h } ) ]

* ( RtRegUpMcp5minPrc z, i - DaRegUpOffer a, s, i ) / 12 ] }

(a.2) #PotDaRegUpMileMwp5minAmt a, s, i = Max [ 0,

( ( RtRegUpMileMcp5minPrc i - DaRegUpMileOffer5minPrc a, s, i )

* DaRegUpUnusedMile5minQty a, s, i ) ] / 12

(a.2.1) DaRegUpUnusedMile5minQty a, s, i =

Max ( 0, RtRegUpUnusedMile5minQty a, s, i

* { IF RtRegUp5minQty a, s, i = 0 THEN 1

ELSE

- Minax ( 10, ∑z

RtDaRegUp5minHrlyQty a, s, h -/ ∑z

DaRtRegUpHrly5minQty a, z,s, ih ) })

Field Code Changed

Field Code Changed

Field Code Changed

Comment [CD241]: New Input determinant

Comment [CD242]: New input determinant

Comment [WRC243]: Splits back all or a portion of the RT Unused Mileage back to the DA Market.

Comment [MCB244]: New redline language from comments


(b) RtRegUpUnusedMileMwp5minAmt a, s, i =

[ Max (0, RtRegUpMargin5minAmt a, s, i

+ PotRtRegUpMileMwp5minAmt a, s, i ] * (-1)

(b.1) #RtRegUpMargin5minAmt a, s, i = Min { 0,

( RtRegUpRev5minAmt a, s, i + RtRegUpAvail5minAmt a, s, i ) / 12 ) }

(b.3) #PotRtRegUpMileMwp5minAmt a, s, i =

Max( 0, RtRegUpMileMcp5minPrc i

- RtRegUpMileOffer5minPrc a, s, i )

*

( RtRegUpUnusedMile5minQty a, s, i

- DaRegUpUnusedMile5minQty a, s, i ) / 12

Min ( 0, RtRegUpMileOffer5minPrc a, z, s, i - RtRegUpMileMcp5minPrc i )

* RtRegUpUnusedMile5minQty a, z, s, i


RtRegUpUnusedMileMwpHrlyAmt a, s, h = RtRegUpUnusedMileMwp5minAmt a, s,

i (3) For each Asset Owner, a daily amount is calculated at each Settlement Location. The

amount is calculated as follows:

RtRegUpUnusedMileMwpDlyAmt a, s, d = RtRegUpUnusedMileMwpHrlyAmt a, s, h

∑z

∑i

∑h




RtRegUpUnusedMileMwpAoAmt a, m, d = RtRegUpUnusedMileMwpDlyAmt a, s, d


RtRegUpUnusedMileMwpMpAmt m, d = RtRegUpUnusedMileMwpAoAmt a, m, d

(6) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates Real-Time Unused Regulation-Up Mileage Make Whole Payment quantity and Real-Time Unused Regulation-Up Mileage Make Whole Payment $ per Dispatch Interval for each Asset Owner as follows:

(a) EqrRtRegUpUnusedMileMwp5minPrc a, s, i = (-1) * RtRegUpUnusedMileMwp5minAmt a, s, i

(b) EqrRtRegUpUnusedMileMwp5minPrc a, s, i > 0 THEN EqrRtRegUpUnusedMileMwp5minQty a, s, i = 1

∑s

∑a



Unit

Settlement

Interval Definition


Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval.

DaRegUpUnusedMileMwp5minAmt a, s, i $ Dispatch Interval

Day-Ahead Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i.


Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i.

PotDaRegUpMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Day-Ahead Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The potential amount to AO a for Day-Ahead Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i

PotRtRegUpMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The potential amount to AO a for Real-Time Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i.

DaRegUpMargin5minAmt a, s, i $ Dispatch Interval

Day-Ahead No Regulation-Up Service Margin Amount per AO per Settlement Location per Dispatch Interval – The amount of net revenue vs. cost from Energy and Operating Reserve Regulation-Up Service cleared in the Day-Ahead for Market AO a at Resource Settlement Location s for Dispatch Interval i


Variable

Unit

Settlement Interval

Definition

DaFixedRegUpHrlyQty a, s, h

MW Hour Day-Ahead Fixed Regulation-Up Quantity per AO per Resource Settlement Location per Hour – The Fixed Regulation-Up MW specified in the Regulation-Up Offer associated with AO a’s Resource Settlement Location s in Hour h.

DaClrdComStatHrlyFlg h, s, c Hour Day-Ahead Commitment Status Hourly Flag per Resource Settlement Location per DA Market Make-Whole-Payment Eligibility Period – The value described under Section 4.5.8.12

DaRegUpHrlyAmt a, s, h $ Hour Day-Ahead Regulation-Up Service Amount per AO per Settlement Location per Hour – The amount calculated under Section 4.5.8.4

DaRegUpAvailHrlyAmt a, s, h $ Hour Day-Ahead Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Hour - The value described under Section 4.5.8.12

RtRegUpMargin5minAmt a, s, h $ Dispatch Interval

Real-Time No Regulation-Up Service Margin Amount per AO per Settlement Location per Dispatch Interval – The amount of net revenue vs. cost from Energy and Operating Reserve net Regulation-Up Service cleared in the RTBM for Market AO a at Resource Settlement Location s for Dispatch Interval i

RtRegUpRev5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation-Up Service Revenue Amount per AO per Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.8

RtRegUpAvail5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation-Up Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval - The amount calculated under Section 4.5.9.8

RtRegUpMileMcp5minPrc i $/MW Dispatch Interval

Real-Time MCP for Regulation-Up Mileage - The RTBM MCP for Excess Regulation-Up Mileage for Dispatch Interval i.

RtRegUpMileOffer5minPrc a, z, s, i $/MW Dispatch Interval

Real-Time Regulation-Up Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s Regulation-Up Mileage Offer for Resource Settlement Location s for Dispatch Interval i in Reserve Zone z.

DaRegUpOffer a, s, i $/MW Dispatch Interval

Day-Ahead Regulation-Up Service Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s Regulation-


Variable

Unit

Settlement Interval

Definition

Up Service Offer for Resource Settlement Location s for Dispatch Interval i


Real-Time MCP for Regulation-Up Service per Reserve Zone - The value described under Section 4.5.9.4

DaRegUpMileOffer5minPrc a, s, i $/MW Dispatch Interval

Day-Ahead Regulation-Up Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s Regulation-Up Mileage Offer for Resource Settlement Location s for Dispatch Interval i.

RtRegUpUnusedMile5minQty a, z, s, i


Real-Time Unused Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.4.

DaRegUpUnusedMile5minQty a, s, i


Day-Ahead Unused Regulation-Up Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused Regulation-Up Mileage associated with the Day-Ahead Market at Resource Settlement Location s for Dispatch Interval i.


Real-Time Cleared Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.4

DaRegUpHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Regulation-Up Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.9.5

RtRegUpUnusedMileMwpHrlyAmt a, s, h $ Hour Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Settlement Location per Hour - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the hour.

RtRegUpUnusedMileMwpDlyAmt a, s, d $ Operating Day

Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Settlement Location per Operating Day - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole Payments at Resource Settlement Location s for the Operating Day.


Variable

Unit

Settlement Interval

Definition

RtRegUpUnusedMileMwpAoAmt a, m, d $ Operating Day

Real-Time Unused Regulation-Up Make Whole Payment Amount per AO per Operating Day - The amount to AO a for Undeployed Regulation-Up Mileage Make Whole for the Operating Day.

RtRegUpUnsedMileMwpMpAmt m, d $ Operating Day

Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per MP per Operating Day - The amount to Mp m for Undeployed Regulation-Up Mileage Make Whole Payments for the Operating Day.

EqrRtRegUpUnusedMileMwp5minQty a, s, i

MW Dispatch

Interval Real-Time Electric Quarterly Reporting Unused Regulation-Up Mileage Make Whole Payment Quantity per AO per Settlement Location per Dispatch Interval– This value is set equal to 1 if EqrRtRegUpUnusedMileMwp5minPrc a, s, i > 0 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements..

EqrRtRegUpUnsedMileMwp5minPrc a, s, i

$/MW Dispatch

Interval Real-Time Electric Quarterly Reporting Unused Regulation-Up Mileage Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval – The Unused Regulation-Up Mileage 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.

a none none An Asset Owner. s none none A Resource Settlement Location. h none none An Hour. i none none A Dispatch Interval. Cast h to i none none A function which places the value of an hourly determinant into

each of the intervals within the hour. d none none An Operating Day. z none none A Reserve Zone. m none none A Market Participant.


4.5.9.29 Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount

(1) A RTBM credit will be calculated at each Settlement Location for each Asset Owner for each Dispatch Interval when that Asset Owner is charged for Unused Regulation-Down Mileage at a rate that is in excess of the Asset Owner’s Regulation-Down Mileage Offer to the extent the Resource’s Regulation-Down Service margin is not sufficient to offset the charge induced by the difference in the two rates. The amount will be calculated as follows:

#RtRegDnUnusedMileMwp5minAmt a, s, i =

DaRegDnUnusedMileMwp5minAmt a, s, i

+ RtRegDnUnusedMileMwp5minAmt a, s, i

Where,

(a) DaRegDnUnusedMileMwp5minAmt a, s, i =

[ Max ( 0, DaRegDnMargin5minAmt a, s, i

+ PotDaRegDnMileMwp5minAmt a, s, i ) ] * (-1)

(a.1) #DaRegDnMargin5minAmt a, s, i = Min { 0,

Cast h to i [ ( DaRegDnHrlyAmt a, h, s

+ IF { (DaClrdComStatHrlyFlg h, s, c = 0 ) AND

(∑z

DaRegDnHrlyQty a, z, s, h <= DaFixedRegDnHrlyQty a, s, h)

THEN 0

ELSE DaRegDnAvailHrlyAmt a, h, s } ) / 12 ]

- ∑z

[ Min [ 0, ( RtRegDn5minQty a, z, s, i

Comment [MCB245]: Order 755 Compliance.

Field Code Changed

Field Code Changed


- ∑z

IF { (DaClrdComStatHrlyFlg h, s, c = 0 ) AND

(∑z

DaRegDnHrlyQty a, z, s, h <= DaFixedRegDnHrlyQty a, s, h)

THEN 0

ELSE ∑z

DaRegDnHrlyQty a, z, s, h } ) ]

* ( RtRegDnMcp5minPrc z, i - DaRegDnOffer a, s, i ) / 12 ] }

(a.2) #PotDaRegDnMileMwp5minAmt a, s, i = Max [ 0,

( ( RtRegDnMileMcp5minPrc i - DaRegDnMileOffer5minPrc a, s, i )

* DaRegDnUnusedMile5minQty a, s, i ) ] / 12

(a.2.1) DaRegDnUnusedMile5minQty a, s, i =

Max ( 0, RtRegDnUnusedMile5minQty a, s, i

* { IF RtRegDn5minQty a, s, i =0, THEN 1

ELSE

- Minax ( 01, ∑z

RtDaRegDn5minHrlyQty a, s, h -/ ∑z

DaRtRegDn5minHrlyQty a, z, s, ih ) })

(b) RtRegDnUnusedMileMwp5minAmt a, s, i =

[ Max (0, RtRegDnMargin5minAmt a, s, i

+ PotRtRegDnMileMwp5minAmt a, s, i ] * (-1)

(b.1) #RtRegDnMargin5minAmt a, s, i = Min { 0,

( RtRegDnRev5minAmt a, s, i + RtRegDnAvail5minAmt a, s, i ) / 12 ) }

Field Code Changed

Field Code Changed

Field Code Changed

Comment [CD246]: New Input determinant

Comment [CD247]: New input determinant

Comment [WRC248]: Splits back all or a portion of the RT Unused Mileage back to the DA Market.

Comment [MCB249]: New redline language from comments


(b.3) #PotRtRegDnMileMwp5minAmt a, s, i =

Max( 0, RtRegDnMileMcp5minPrc i

- RtRegDnMileOffer5minPrc a, s, i )

*

( RtRegDnUnusedMile5minQty a, s, i

- DaRegDnUnusedMile5minQty a, s, i ) / 12

Min ( 0, RtRegDnMileOffer5minPrc a, z, s, i - RtRegDnMileMcp5minPrc i )

* RtRegDnUnusedMile5minQty a, z, s, i


RtRegDnUnusedMileMwpHrlyAmt a, s, h = RtRegDnUnusedMileMwp5minAmt a, s,

i (6) For each Asset Owner, a daily amount is calculated at each Settlement Location. The

amount is calculated as follows:

RtRegDnUnusedMileMwpDlyAmt a, s, d = RtRegDnUnusedMileMwpHrlyAmt a, s, h


RtRegDnUnusedMileMwpAoAmt a, m, d = RtRegDnUnusedMileMwpDlyAmt a, s, d


RtRegDnUnusedMileMwpMpAmt m, d = RtRegDnUnusedMileMwpAoAmt a, m, d

∑z

∑i

∑h

∑s

∑a



(6) For FERC Electric Quarterly Reporting (“EQR”) purposes, SPP calculates Real-Time Unused Regulation-Down Mileage Make Whole Payment quantity and Real-Time Unused Regulation-Up Mileage Make Whole Payment $ per Dispatch Interval for each Asset Owner as follows:

(a) EqrRtRegDnUnusedMileMwp5minPrc a, s, i = (-1) * RtRegDnUnusedMileMwp5minAmt a, s, i

(b) EqrRtRegDnUnusedMileMwp5minPrc a, s, i > 0 THEN EqrRtRegDnUnusedMileMwp5minQty a, s, i = 1



Unit

Settlement

Interval Definition


Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval.

DaRegDnUnusedMileMwp5minAmt a, s, i $ Dispatch Interval

Day-Ahead Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i.


Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i.

PotDaRegDnMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Day-Ahead Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The potential amount to AO a for Day-Ahead Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i

PotRtRegDnMileMwp5minAmt a, s, i $ Dispatch Interval

Potential Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Resource Settlement Location per Dispatch Interval - The potential amount to AO a for Real-Time Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Dispatch Interval i.


Variable

Unit

Settlement Interval

Definition

DaRegDnMargin5minAmt a, s, i $ Dispatch Interval

Day-Ahead No Regulation-Down Service Margin Amount per AO per Settlement Location per Dispatch Interval – The amount of net revenue vs. cost from Energy and Operating Reserve Regulation-Down Service cleared in the Day-Ahead for Market AO a at Resource Settlement Location s for Dispatch Interval i

DaClrdComStatHrlyFlg h, s, c None Hour Day-Ahead Commitment Status Hourly Flag per Resource Settlement Location per DA Market Make-Whole-Payment Eligibility Period – The value described under Section 4.5.8.12

DaFixedRegDnHrlyQty a, s, h

MW Hour Day-Ahead Fixed Regulation-Down Quantity per AO per Resource Settlement Location per Hour – The Fixed Regulation-Down MW specified in the Regulation-Down Offer associated with AO a’s Resource Settlement Location s in Hour h.

DaRegDnHrlyAmt a, s, h $ Hour Day-Ahead Regulation-Down Service Amount per AO per Settlement Location per Hour – The amount calculated under Section 4.5.8.5

DaRegDnAvailHrlyAmt a, s, h $ Hour Day-Ahead Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Hour - The value described under Section 4.5.8.12

RtRegDnMargin5minAmt a, s, h $ Dispatch Interval

Real-Time No Regulation-Down Service Margin Amount per AO per Settlement Location per Dispatch Interval – The amount of net revenue vs. cost from Energy and Operating Reserve net Regulation-Down Service cleared in the RTBM for Market AO a at Resource Settlement Location s for Dispatch Interval i

RtRegDnRev5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation-Down Service Revenue Amount per AO per Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.8

RtRegDnAvail5minAmt a, s, i $ Dispatch Interval

Real-Time Regulation-Down Service Offer Cost Amount per AO per Settlement Location per Dispatch Interval - The amount calculated under Section 4.5.9.8

RtRegDnMileMcp5minPrc i $/MW Dispatch Interval

Real-Time MCP for Regulation-Down Mileage - The RTBM MCP for Excess Regulation-Down Mileage for Dispatch Interval i.


Variable

Unit

Settlement Interval

Definition

RtRegDnMileOffer5minPrc a, z, s, i $/MW Dispatch Interval

Real-Time Regulation-Down Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s Regulation-Down Mileage Offer for Resource Settlement Location s for Dispatch Interval i in Reserve Zone z.

DaRegDnOffer a, s, i $/MW Dispatch Interval

Day-Ahead Regulation-Down Service Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s Regulation-Down Service Offer for Resource Settlement Location s for Dispatch Interval i


Real-Time MCP for Regulation-Down Service per Reserve Zone - The value described under Section 4.5.9.5

DaRegDnMileOffer5minPrc a, s, i $/MW Dispatch Interval

Day-Ahead Regulation-Down Mileage Offer per AO per Resource Settlement Location per Dispatch Interval - AO a’s Regulation-Down Mileage Offer for Resource Settlement Location s for Dispatch Interval i.

RtRegDnUnusedMile5minQty a, z, s, i


Real-Time Unused Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval – The value calculated under Section 4.5.9.5.

DaRegDnUnusedMile5minQty a, s, i


Day-Ahead Unused Regulation-Down Mileage Quantity per AO per Settlement Location per Dispatch Interval - AO a’s Unused Regulation-Down Mileage associated with the Day-Ahead Market at Resource Settlement Location s for Dispatch Interval i.


Real-Time Cleared Regulation-Down Service Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.5

DaRegDnHrlyQty a, z, s, h MW Hour Day-Ahead Cleared Regulation-Down Quantity per AO per Settlement Location per Hour – The value described under Section 4.5.9.5.

RtRegDnUnusedMileMwpHrlyAmt a, s, h $ Hour Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Settlement Location per Hour - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the hour.


Variable

Unit

Settlement Interval

Definition

RtRegDnUnusedMileMwpDlyAmt a, s, d $ Operating Day

Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Settlement Location per Operating Day - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole Payments at Resource Settlement Location s for the Operating Day.

RtRegDnUnusedMileMwpAoAmt a, m, d $ Operating Day

Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Operating Day - The amount to AO a for Undeployed Regulation-Down Mileage Make Whole for the Operating Day.

RtRegDnUnsedMileMwpMpAmt m, d $ Operating Day

Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per MP per Operating Day - The amount to Mp m for Undeployed Regulation-Down Mileage Make Whole Payments for the Operating Day.

EqrRtRegDnUnusedMileMwp5minQty a, s, i

MW Dispatch

Interval Real-Time Electric Quarterly Reporting Unused Regulation-Down Mileage Make Whole Payment Quantity per AO per Settlement Location per Dispatch Interval– This value is set equal to 1 if EqrRtRegDnUnusedMileMwp5minPrc a, s, i > 0 for use by AO a in reporting such make-whole-payments to FERC in accordance with FERC EQR requirements..

EqrRtRegDnUnsedMileMwp5minPrc a, s, i

$/MW Dispatch

Interval Real-Time Electric Quarterly Reporting Unused Regulation-Down Mileage Make Whole Payment Amount per AO per Settlement Location per Dispatch Interval – The Unused Regulation-Down Mileage 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.

a none none An Asset Owner. s none none A Resource Settlement Location. h none none An Hour. i none none A Dispatch Interval. Cast h to i none none A function which places the value of an hourly determinant into

each of the intervals within the hour.


Variable

Unit

Settlement Interval

Definition

d none none An Operating Day. z none none A Reserve Zone. m none none A Market Participant.


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 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.

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

#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 ) / 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

+ 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

+ DaOclDistMpAmt m, d + TcrAucTxnMpAmt m, d + ArrAucTxnMpAmt m, d

+ ArrUpliftMpAmt m, d + DaDRMpAmt m, d + DaDRDistMpAmt m, d ) - ECFDlyAmt d - ARFDlyAmt d + GFARevInadqcSppAmt spp, d

(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

+ RtRegUpUnusedMileMwpMpAmt m, d

+ RtRegDnUnusedMileMwpMpAmt m, d

+ RtSpinDistMpAmt m, d + RtSuppDistMpAmt m, d

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

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

RtNetInadvertentSpp5minAmt 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



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



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.


Variable

Unit

Settlement Interval

Definition

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 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.


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.






Variable

Unit

Settlement Interval

Definition

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.

DaOclDistMpAmt m, d $ Operating Day

Day-Ahead Over Collected Losses Distribution Amount per MP per Operating Day - The value calculated under Section 4.5.8.19.

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.

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.





RsgCrdFlg t




Variable

Unit

Settlement Interval

Definition

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.


Real-Time Regulation-Up Service Amount per MP per Operating Day – The value described under Section4.5.9.4.


Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.284.


Real-Time Regulation-Down Service Amount per MP per Operating Day – The value described under Section 4.5.9.5.


Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.295.

RtSpinMpAmt m, d $ Operating Day

Real-Time Spinning Reserve Amount per MP per Operating Day – The value described under Section 4.5.9.6.






Variable

Unit

Settlement Interval

Definition

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.

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.


Variable

Unit

Settlement Interval

Definition

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.


Real-Time Regulation-Up Service Distribution Amount – The value calculated under Section 4.5.9.11.


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.




Variable

Unit

Settlement Interval

Definition

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.

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.

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

a none none An Asset Owner. s none none A Resource Settlement Location. h none none An Hour. i none none A Dispatch Interval.


Variable

Unit

Settlement Interval

Definition

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.


8.2.5 Offer Caps and Floors

Submission of Energy Offer Curves and Operating Reserve Offers by Market Participants for use in the DA Market and the RTBM will be limited by the following offer caps and floors.

(1) Safety-Net Energy Offer Cap = $1000/MWh;

(2) Regulation-Up Service Offer Cap = (Regulation-Up Offer + Regulation-Up Mileage Offer) = $500/MW;

(3) Regulation-Down Service Offer Cap = (Regulation-Down Offer + Regulation-Down Mileage Offer) = $500/MW;

(4) Contingency Reserve Offer Cap = $100/MW;

(5) Energy Offer Floor = Negative $500/MWh;

(6) Regulation-Up Service Offer Floor = (Regulation-Up Offer + Regulation-Up Mileage Offer) = Negative $500/MW;

(7) Regulation-Down Service Offer Floor = (Regulation-Down Offer + Regulation-Down Mileage Offer) = Negative $500/MW;

(8) Regulation-Up Mileage Offer Floor = $0;

(9) Regulation-Down Mileage Offer Floor = $0;

(10) Contingency Reserve Offer Floor = Negative $100/MW;

(11) Start-Up Offer Floor = $0.0;

(12) No-Load Offer Floor = $0.0.









Attachment AE

1.1 Definitions A

Actual Regulation-Down Mileage

The sum of the absolute values of actual movements by a Resource with cleared Regulation-Down

Service MW in response to Regulation Deployment instructions for Regulation-Down Service.

Actual Regulation-Up Mileage

The sum of the absolute values of actual movements by a Resource with cleared Regulation-Up Service

MW in response to Regulation Deployment instructions for Regulation-Up Service.

1.1 Definitions I

Instructed Regulation-Down Mileage

The sum of the absolute values of instructed movements to a Resource with cleared Regulation-Down

Service through Regulation Deployment instructions for Regulation-Down Service.

Instructed Regulation-Up Mileage

The sum of the absolute values of instructed movements to a Resource with cleared Regulation-Up

Service MW through Regulation Deployment instructions for Regulation-Up Service.

1.1 Definitions R

Regulation-Down Mileage Factor

A factor determined through historical Regulation Deployment analysis that represents the ratio of the

Transmission Provider’s total Instructed Regulation-Down Mileage to the Transmission Provider’s total

cleared Regulation-Down Service. The Regulation-Down Mileage Factor shall initially be set equal to

1.0 and shall be updated periodically pursuant to the Market Protocols.

Regulation-Up Mileage Factor

A factor determined through historical Regulation Deployment analysis that represents the ratio of the

Transmission Provider’s total Instructed Regulation-Up Mileage to the Transmission Provider’s total


cleared Regulation-Up Service. The Regulation-Up Mileage Factor shall initially be set equal to 1.0 and

shall be updated periodically pursuant to the Market Protocols.

4.1 Offer Submittal

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

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

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

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

following:

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

RTBM except that, if Regulation-Up Service and/or Regulation-Down Service is cleared

in the Day-Ahead Market, submitted Regulation-Up Mileage Offers and/or Regulation-

Down Mileage Offers for the associated Resources submitted for use in the RTBM must

beare 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 until changed

within each respective market;

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

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

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

roll forward in each hour until updated;

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

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

Interchange Transaction Offers may only be submitted at External Interface Settlement

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

including a Market Hub;


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

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

Reserve Offers and Supplemental Reserve Offers provided that if 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. Resource

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

as follows:

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

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

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

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

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

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

requirements specified in the Market Protocols.

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

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

Supplemental Reserve within the Contingency Reserve Deployment Period for a

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

meets the technical requirements specified in the Market Protocols.

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

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

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

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

meets the technical requirements specified in the Market Protocols.

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

Attachment AE;

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

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


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

defined in the Market Protocols):

• Resource Name

• Resource Type

• Start-up Offer

• No-Load Offer

• Energy Offer Curve

• Regulation–Up and Regulation-Down Offers

• 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

• Maximum and Minimum Run Times

• Minimum Down Time

• Minimum Emergency Capacity Operating Limit and Run Time

• Minimum Normal, Economic, and Regulation Capacity Operating Limits

• Maximum Normal, Economic, and Regulation Capacity Operating Limits

• Maximum Emergency Capacity Operating Limits and Run Time

• Maximum Quick-Start Response Limit

• Ramp-Rate-Up and Ramp-Rate-Down

• Turn-Around Ramp Rate Factor

• Regulation Ramp Rate

• Contingency Reserve Ramp Rate

• Resource Status

• JOU Ownership Share

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

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

Protocols. Market Participants use the commitment status to indicate;

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


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

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

alleviate an anticipated Emergency Condition or local reliability issue;

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

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

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

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

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

the Resource is:

(a) Eligible for Energy Dispatch;

(b) Eligible for Operating Reserve clearing; or

(c) Self-scheduled for Operating Reserve.

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.

8.3.4 Market Clearing Price 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 Day-Ahead Market and RTBM

MCPs at a Reserve Zone for Resources with cleared Regulation-Up Service, Regulation-Down

Service, Spinning Reserve and/or Supplemental Reserve in that Reserve Zone are equal to the

summation of the applicable Shadow Prices associated with the constraints as described in

subsections (1) and (2) below. Calculation of MCPs for Expected Regulation-Up Mileage and

Expected Regulation-Down Mileage are calculated as described in subsections (3) and (4) below:

(1) There are four sets of constraints which apply on both a system-wide basis and a Reserve

Zone basis:


(a) A contingency reserve plus regulation-up constraint is equal to the sum of the

Contingency Reserve requirement and the Regulation-Up requirement;

(b) A regulation-up plus spinning reserve constraint is equal to the sum of the

Regulation-Up requirement and the Spinning Reserve requirement;

(c) A regulation-up constraint is equal to the Regulation-Up requirement; and

(d) A regulation-down constraint is equal to the Regulation-Down requirement.

(2) Operating Reserve MCPs for each Reserve Zone are calculated as follows:

(a) The Regulation-Up Service MCP is equal to sum of the Shadow Prices for the

system-wide and zonal regulation-up constraints, system-wide and zonal

regulation-up plus spinning reserve constraints and the system-wide and zonal

contingency reserve plus regulation-up constraints;

(b) The Spinning Reserve MCP is equal to the sum of the Shadow Prices for the

system-wide and zonal regulation-up plus spinning reserve constraints and the

system-wide and zonal contingency reserve plus regulation-up constraints;

(c) The Supplemental Reserve MCP is equal to the sum of the Shadow Prices for the

system-wide and zonal contingency reserve plus regulation-up constraints; and

(d) The Regulation-Down Service MCP is equal to the Shadow Price for the system-

wide and zonal regulation-down constraint.

(3) RTBM MCPs for Expected Regulation-Up Mileage are set equal to the highest

Regulation-Up Mileage Offer of all Resources economically cleared to provide

Regulation-Up Service in a particular Dispatch Interval. For Resources submitting a

Regulation-Up Service dispatch status as described under Section 4.1(11)(c) of this

Attachment AE, the cleared amount of Regulation-Up Service MW must be greater than

the submitted self-schedule MW in order to be considered economically cleared;

(4) RTBM MCPs for Expected Regulation-Down Mileage are set equal to the highest

Regulation-Down Mileage Offer of all Resources economically cleared to provide

Regulation-Down Service in a particular Dispatch Interval. For Resources submitting a

Regulation-Down Service dispatch status as described under Section 4.1(11)(c) of this

Attachment AE, the cleared amount of Regulation-Down Service MW must be greater

than the submitted self-schedule MW in order to be considered economically cleared;

(5) In the event a system-wide failure of the RTBM systems results in a loss of the ability to

calculate MCPs, RTBM Operating Reserve will continue to be settled financially under


this Tariff based upon estimated MCPs. The Transmission Provider shall notify Market

Participants if RTBM Operating Reserve is to be settled using estimated prices.

(a) If the failure of the RTBM systems occurs for twelve (12) Dispatch Intervals or

less, the estimated MCPs shall be the most recently calculated MCPs for each

affected Reserve Zone and shall be utilized for settlement purposes for each of the

Dispatch Intervals in which MCP pricing data is missing.

(b) If the failure of the RTBM systems occurs for more than twelve (12) Dispatch

Intervals, the Transmission Provider shall calculate MCPs using mitigated Offers

for the RTBM in a manner that reflects, as closely as practicable, the MCPs that

would have resulted but for the RTBM systems failure, and shall use such MCPs

for settlement purposes for each of the Dispatch Intervals in which MCP pricing

data is missing. To the extent that the Transmission Provider is unable to

calculate RTBM MCPs, the Transmission Provide shall use the MCPs generated

in the Day-Ahead Market for RTBM settlement.

(6) If for any reason a portion of generation and load within the SPP Balancing Authority

Area becomes isolated from the rest of the SPP Balancing Authority Area (“Island”),

RTBM MCPs will not be calculated and procurement of Operating Reserve within the

Island will not be performed.

8.5.9 Day-Ahead Make Whole Payment Amount

(1) The Day-Ahead make whole payment amount is a payment to an Asset Owner and is

calculated for each Resource with an associated Day-Ahead Market Commitment Period

that was committed by the Transmission Provider with a Day-Ahead Market Resource

Offer commitment status as defined under Sections 4.1(10)(b) and (c) of this Attachment

AE, or was committed as part of the Multi-Day Reliability Assessment as defined under

Section 4.5.3 of this Attachment AE. A payment is made to the Asset Owner when the

sum of the Resource’s costs is greater than the Day-Ahead Market revenues received for

that Resource over the Resource’s Day-Ahead Market make whole payment eligibility

period. The make whole payment is equal to this difference between these costs and

revenues.

(2) A Resource’s Day-Ahead Market make whole payment eligibility period is equal to a

Resource’s Day-Ahead Market Commitment Period except as defined herein. For


Resources with an associated Day-Ahead Market Commitment Period that begins in one

Operating Day and ends in the next Operating Day, two (2) Day-Ahead Market make

whole payment eligibility periods are created. The first period begins in the first

Operating Day in the hour that the Day-Ahead Market Commitment Period begins and

ends in the last hour of the first Operating Day. The second period begins in the first

hour of the next Operating Day and ends in the last hour of the Day-Ahead Market

Commitment Period.

(3) The following cost recovery rules apply to each Day-Ahead Market make whole payment

eligibility period. Offer costs are calculated using the Day-Ahead Market Offer prices in

effect at the time the commitment decision was made except under the situation described

under Section (b)(i) below.

(a) There may be more than one Day-Ahead Market make whole payment eligibility

period for a Resource in a single Operating Day for which a charge or payment is

calculated. A single Day-Ahead Market make whole payment eligibility period is

contained within a single Operating Day.

(b) A Resource’s Day-Ahead Market Start-Up Offer costs are not eligible for

recovery in the following Day-Ahead Market make whole payment eligibility

periods:

(i) For any Day-Ahead Market make whole payment eligibility period that is

adjacent to the end of a RUC make whole payment eligibility period

except as described under Section 8.6.5(3)(h);

(ii) For any Day-Ahead Market make whole payment eligibility period

resulting from a Day-Ahead Market Commitment Period that contains a

Day-Ahead Market self-commit hour; or

(iii) For any Day-Ahead make whole payment eligibility period for which a

Resource is a Synchronized Resource prior to this commitment period at a

time one (1) hour prior to that Resource’s Day-Ahead Market Commit

Time less the Resource’s Sync-To-MinTime.

(c) For each Day-Ahead Market make whole payment eligibility period within an

Operating Day, a Resource’s Day-Ahead Market Start-Up Offer is divided by the

lesser of (1) the Resource’s Minimum Run Time rounded down to the nearest

hour or (2) twenty-four (24) hours, and that portion of the Start-Up Offer is

included as a cost in each hour of the Day-Ahead Market make whole payment


eligibility period until the sum of these hourly costs are equal to the Day-Ahead

Market Start-Up Offer or until the end of the Day-Ahead Market make whole

payment eligibility period, whichever occurs first.

(d) To the extent that the full amount of the Day-Ahead Market Start-Up Offer is not

accounted for in the last Day-Ahead Market make whole payment eligibility

period in the Operating Day, any remaining Day-Ahead Market Start-Up Offer

costs are carried forward for recovery in the first Day-Ahead Market make whole

payment eligibility period of the following Operating Day.

(4) The payment to each Asset Owner for each eligible Settlement Location for a given Day-

Ahead Market make whole payment eligibility period is calculated as follows:

Day-Ahead Make Whole Payment Amount =

Maximum of [Either Zero or Sum of ((Day-Ahead Make Whole Payment Cost

Amount in the Day-Ahead Market Make Whole Payment Eligibility Period) +

(Day-Ahead Make Whole Payment Revenue Amount in the Day-Ahead Market

Make Whole Payment Eligibility Period))] * (-1)

(a) An Asset Owner’s Day-Ahead Make Whole Payment Cost Amount for each

eligible Resource is equal to the sum for all hours in the Day-Ahead Market Make

Whole Payment Eligibility Period of:

(i) Day-Ahead Market Start-Up Offer,

(ii) Day-Ahead Market No-Load Offer,

(iii) Energy cost associated with cleared Resource Energy from Resource

Energy Offers as described under Section 5.1.3 of this Attachment AE, as

calculated by multiplying cleared Resource Energy by the cost of such

Energy as calculated from the Resource’s Day-Ahead Market Energy

Offer Curve,

(iv) Regulation-Up Service cost associated with cleared Regulation-Up

Service from Regulation-Up Service Offers as described under Section

5.1.3 of this Attachment AE, as calculated by multiplying Regulation-Up

Service by the cost of such Regulation-Up Service as calculated from the

Resource’s Day-Ahead Market Regulation-Up Service Offer,

(v) Regulation-Down Service cost, associated with cleared Regulation-Down

Service from Regulation-Down Service Offers as described under Section

5.1.3 of this Attachment AE, as calculated by multiplying Regulation-


Down Service by the cost of such Regulation-Down Service as calculated

from the Resource’s Day-Ahead Market Regulation-Down Service Offer,

(vi) Spinning Reserve cost, associated with cleared Spinning Reserve from

Spinning Reserve Offers as described under Section 5.1.3 of this

Attachment AE, as calculated by multiplying Spinning Reserve by the cost

of such Spinning Reserve as calculated from the Resource’s Day-Ahead

Market Spinning Reserve Offer,

(vii) Supplemental Reserve cost, associated with cleared Supplemental Reserve

from Supplemental Reserve Offers as described under Section 5.1.3 of this

Attachment AE, as calculated by multiplying Supplemental Reserve by the

cost of such Supplemental Reserve as calculated from the Resource’s Day-

Ahead Market Supplemental Reserve Offer,

(viii) Day-Ahead Potential Unused Regulation-Up Mileage Make Whole

Payment as calculated under Section 8.6.19(1)(b); and

(ix) Day-Ahead Potential Unused Regulation-Down Mileage Make Whole

Payment as calculated under Section 8.6.20(1)(b).

(b) An Asset Owner’s Day-Ahead Make Whole Payment Revenue Amount for each



(i) Energy revenue associated with cleared Resource Energy from Resource

Energy Offers as described under Section 5.1.3 of this Attachment AE,

calculated by multiplying Resource Energy by Day-Ahead LMP at that

Resource Settlement Location, and

(ii) The sum of the revenues calculated under Section 8.5.2, 8.5.3 and 8.5.4,

8.6.19(1) and 8.6.20(1) for that eligible Resource.


8.6.5 Reliability Unit Commitment Make Whole Payment Amount

(1) Asset Owners of Resources committed by the Transmission Provider with an RTBM

Resource Offer commitment status as defined under Sections 4.1(10)(b) and (c) of this

Attachment AE, are eligible to receive a RUC make whole payment. Asset Owners of

Resources committed by a local transmission operator to address a Local Emergency

Condition are eligible to receive a RUC make whole payment, except that, if the Market

Monitor determines such Resources were selected in a discriminatory manner by the local

transmission operator, as determined pursuant to Section 6.1.2.1 of this Attachment AE,

and such Resources were affiliated with the local transmission operator, then such

Resources are not eligible to receive a RUC make whole payment. A RUC make whole

payment is made to the Asset Owner when the sum of a Resource’s eligible RTBM Start-

Up Offer costs, No-Load Offer costs, Energy Offer Curve and Operating Reserve Offer

costs associated with actual Energy and cleared RTBM Operating Reserve is greater than

the Energy and Operating Reserve RTBM revenues received over the Resource’s RUC

make whole payment eligibility period. Recovery of such compensation shall be

collected in accordance with Section 8.6.7 of this Attachment AE.

(2) A Resource’s RUC make whole payment eligibility period is equal to that Resource’s

RUC Commitment Period. For Resources with a RUC Commitment Period that begins in

one Operating Day and ends in the next Operating Day, two RUC make whole payment

eligibility periods are created. The first period begins in the first Operating Day in the

Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last

Dispatch Interval of the first Operating Day. The second period begins in the first

Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated

with the Resource’s RUC De-Commit Time.

(3) The following cost recovery rules apply to each RUC make whole payment eligibility

period. Offer costs are calculated using the RTBM Offer prices in effect at the time the

commitment decision was made.

(a) If the Transmission Provider cancels a Commitment Instruction prior to the start

of the associated RUC make whole payment eligibility period and the Resource is

not a Synchronized Resource, the Asset Owner will receive reimbursement for a

time-based pro-rata share of the Resource’s RTBM Start-Up Offer. 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.

(b) In order to receive the full amount of Start-Up Offer recovery within a RUC make

whole payment eligibility period, the Resource must be a Synchronized Resource

in at least one Dispatch Interval in the RUC make whole payment eligibility

period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in

the RUC make whole payment eligibility period, the Resource must be a

Synchronized Resource in that Dispatch Interval.

(d) There may be more than one RUC make whole payment eligibility period for a

Resource in a single Operating Day. A single RUC make whole payment

eligibility period is contained within a single Operating Day.

(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the

following RUC make whole payment eligibility periods:

(i) Any RUC make whole payment eligibility period that is adjacent to the

end of a Day-Ahead Market make whole payment eligibility period;

(ii) Any RUC make whole payment eligibility period for which a Resource is

a Synchronized Resource prior to this commitment period at a time one (1)

hour prior to that Resource’s RUC Commit Time less the Resource’s

Sync-To-Min Time; and

(iii) Any RUC make whole payment eligibility period resulting from a RUC

Commitment Period that contains an hour for which the Resource was

self-committed.

(f) For each RUC make whole payment eligibility period within an Operating Day, a

Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s

Minimum Run Time multiplied by twelve (12), rounded down to the nearest

whole interval, or (2) twenty-four (24) hours multiplied by twelve (12), and that

portion of the Start-Up Offer is included as a cost in each interval of the RUC

make whole payment eligibility period until the sum of these interval costs are

equal to the RTBM Start-Up Offer or until the end of the RUC make whole



(g) To the extent that the full amount of the RTBM Start-Up Offer is not accounted

for in the last RUC make whole payment eligibility period in the Operating Day,

any remaining RTBM Start-Up Offer costs are carried forward for recovery in the

first RUC make whole payment eligibility period of the following Operating Day

provided that the Resource has not been committed in the Day-Ahead Market in

any hour of the first RUC make whole payment eligibility period as described in

(h) below.

(h) If the Resource has been committed in the Day-Ahead Market in a period adjacent

to and following a RUC make whole payment eligibility period to the extent that

the full amount of the RTBM Start-Up Offer is not accounted for in the RUC

make whole payment eligibility period, any remaining RTBM Start-Up Offer

costs are carried forward for recovery in the Day-Ahead make whole payment

eligibility period.

(i) If a Resource has operated outside of its Operating Tolerance in any Dispatch

Interval, any cost associated with energy output above the Resource’s economic

operating point is not eligible for recovery for that Dispatch Interval where such

cost is calculated as described under Subsection 4(c) below.

(j) If a Resource becomes non-dispatchable in any Dispatch Interval, any cost

associated with energy output above the Resource’s economic operating point is

not eligible for recovery for that Dispatch Interval where such cost is calculated as

described under Subsection 4(c) below.

(k) If a Resource’s minimum operating limit is increased above the Resource’s

minimum operating limit that was used to make the commitment decision, the

increase is greater than the Resource’s Operating Tolerance and the Resource

remains dispatchable in any Dispatch Interval, any cost associated with energy

output above the Resource’s economic operating point is not eligible for recovery

for that Dispatch Interval where such cost is calculated as described under

Subsection 4(c) below.

(4) The payment to each Asset Owner for each eligible Settlement Location for a given RUC

make whole payment eligibility period is calculated as follows:

RUC Make Whole Payment Amount =

Maximum of [Either Zero or (RUC Make Whole Payment Cost Amount in the RUC

Make Whole Payment Eligibility Period + RUC Make Whole Payment Revenue Amount


in the RUC Make Whole Payment Eligibility Period – Uninstructed Resource Deviation

Cost Disallowance – Non-Dispatchable Cost Disallowance – Minimum Limit Cost

Disallowance)]

(a) An Asset Owner’s RUC Make Whole Payment Cost Amount for each eligible

Resource is equal to the sum for all Dispatch Intervals in the RUC Make Whole

Payment Eligibility Period of:

(i) Start-Up Offer used to make commitment decision;,

(ii) No-Load Offer used to make commitment decision;,

(iii) Energy cost at minimum output as calculated from the Energy Offer Curve

used to make commitment decision;,

(iv) Energy cost above minimum output as calculated from the Energy Offer

Curve that applied to the current Dispatch Interval;,

(v) Operating Reserve cost associated with cleared Real-Time Operating Reserve,

Excess Regulation-Up Mileage and Excess Regulation-Down Mileage as

calculated from the Operating Reserve Offers except that Operating Reservewhen

those costs are associated with self-scheduled Operating Reserve which is where

such self-schedules are less than or equal to the amount of Operating Reserve

cleared, in which case all three of these costs shall be set equal to zero;, and

(vi) Real-Time Potential Regulation-Up Unused Mileage Make Whole Payment as

calculated under Section 8.6.19(2)(b) of this Attachment AE and (vii) Real-Time

Potential Regulation-Down Unused Mileage Make Whole Payment as calculated

under Section 8.6.20(2)(b) of this Attachment AE.

(b) An Asset Owner’s RUC Make Whole Payment Revenue Amount for each eligible

Resource is equal to the sum for all Dispatch Intervals in the RUC Make Whole

Payment Eligibility Period of (i) revenue associated with Energy calculated by

multiplying actual Energy by Real-Time LMP (ii) the sum of the revenues

calculated under Sections 8.6.3 and 8.6.4 of this Attachment AE for that eligible

Resource (iii) Energy revenue associated with payments made under Section

8.6.6 of this Attachment AE (iv) amounts associated with settlement made under

Section 8.6.15 of this Attachment AE (v) Real-Time Unused Regulation-Up

Mileage Make Whole Payment as calculated under Section 8.6.19(2) of this

Attachment AE (vi) Real-Time Unused Regulation-Down Mileage Make Whole

Payment as calculated under Section 8.6.20(2) of this Attachment AE (vii) Real-


Time Regulation-Up Service Revenue as calculated under Section 8.6.19(2)(a)(i)

of this Attachment AE (viii) Real-Time Regulation-Down Service Revenue as

calculated under Section 8.6.20(2)(a)(i) of this Attachment AE (ix) Excess

Regulation-Up Mileage Dispatch Interval Amount as calculated under Section

8.6.2(1)(a)(v) of this Attachment AE, multiplied by (-1), and (x) Excess

Regulation-Down Mileage Dispatch Interval Amount as calculated under Section

8.6.2(2)(a)(v) of this Attachment AE, multiplied by (-1).

(c) An Asset Owner’s Uninstructed Resource Deviation Cost Disallowance, Non-

Dispatchable Cost Disallowance, or Minimum Limit Cost Disallowance is equal

to the positive difference between the Resource’s Energy cost at actual output as

calculated from the Resource’s current Dispatch Interval Energy Offer Curve and

the Resource’s Energy cost at the Resource’s economic operating point as

calculated from the Resource’s current Dispatch Interval Energy Offer Curve.

(d) A Resource’s economic operating point is the MW output where the cost on the

Resource’s current Dispatch Interval Energy Offer Curve first exceeds the Real-

Time LMP for that Resource.

8.6.19 Unused Regulation-Up Mileage Make Whole Payment

A payment will be made to each Asset Owner with a Resource that is charged for Unused

Regulation-Up Mileage at a rate that is in excess of that Resource’s Regulation-Up Mileage

Offer to the extent that Regulation-Up Service margin is not sufficient to offset such excess. The

amount will be calculated on a Dispatch Interval basis as follows:

Unused Regulation-Up Mileage Make Whole Payment Amount =

Day-Ahead Unused Regulation-Up Mileage Make Whole Payment Amount + Real-Time

Unused Regulation-Up Mileage Make Whole Payment Amount

(1) Day-Ahead Unused Regulation-Up Mileage Make Whole Payment = Maximum of [zero

or (Day-Ahead Regulation-Up Service Margin + Day Ahead Potential Regulation-Up

Unused Make Whole Payment Amount)] * (-1)

(a) Day-Ahead Regulation-Up Service Margin = Minimum of [zero or [(Day- Ahead

Regulation-Up Service Hourly Amount (as calculated under Section 8.5.2 of this

Attachment AE) plus Day-Ahead Regulation-Up Service Cost), divided by 12]


minus

Minimum of [zero or (Real-Time Cleared Regulation-Up Service Dispatch

Interval Quantity (as defined under Section 8.6.2(1)(a)(ii) of this Attachment AE)

- Day-Ahead Regulation-Up Service Hourly Quantity)] * (Real- Time MCP (as

defined under Section 8.6.2(1)(a)(i) of this Attachment AE) – Day-Ahead

Regulation-Up Offer ), divided by 12]

(i) If the Resource has cleared Regulation-Up Service that is greater than the

amount of self-scheduled Regulation-Up Service on that Resource, then

Day-Ahead Regulation-Up Service Cost is equal to the cost calculated as

described under Section 8.5.9(4)(a)(iv) of this Attachment AE. If the

Resource is not eligible for a Day-Ahead Make Whole Payment Amount as

described under Section 8.5.9 of this Attachment AE and the Resource has

cleared Regulation-Up Service that is less than or equal to the amount of

self-scheduled Regulation-Up Service on that Resource then Day-Ahead

Regulation-Up Service Cost is equal zero for the purposes of this

calculation.

(ii) If the Resource has cleared Regulation-Up Service that is greater than the

amount of self-scheduled Regulation-Up Service on that Resource, then

Day-Ahead Regulation-Up Service Hourly Quantity is equal to the value

described under Section 8.6.2(1)(a)(iii) of this Attachment AE. If the





Regulation-Up Service Hourly Quantity is equal zero for the purposes of

this calculation.

(b) Day-Ahead Potential Regulation-Up Unused Mileage Make Whole Payment =

[Maximum of [zero or (Expected Regulation-Up Mileage MCP – Day-Ahead

Regulation-Up Mileage Offer)]] * Day-Ahead Unused Regulation-Up Mileage

divided by 12

(i) Regulation-Up Mileage Offer and Regulation–Up Offer are defined under

Section 1 of this Attachment AE. (Regulation-Up Mileage Offer for Day-


Ahead Market and Regulation-Up Offer for Day-Ahead Market are the

terms used here);

(ii) Expected Regulation-Up Mileage MCP is defined under Section 8.3.4(3)

of this Attachment AE;

(iii) If Real-Time Cleared Regulation-Up Service Dispatch Interval Quantity

(as described under Section 8.6.2(1)(a)(ii) of this Attachment AE) is equal

to zero , then Day-Ahead Unused Regulation-Up Mileage = Maximum of

[zero or (Regulation-Up Unused Mileage (as calculated under Section

8.6.2(1)(a)(iv) of this Attachment AE), otherwise Day_Ahead Unused

Regulation-Up Mileage = Regulation-Up Unused Mileage * – Maximum

Minimum of [zero one or (Day-AheadReal-Time Cleared Regulation-Up

Service Dispatch Hourly Interval Quantity (as described under Section

8.6.2(1)(a)(iii) of this Attachment AE) divided by Real-Time – Day-Ahead

Cleared Regulation-Up Service Dispatch Interval Hourly Quantity (as

described under Section 8.6.2(1)(a)(iii) of this Attachment AE))])].

(2) Real-Time Unused Regulation-Up Mileage Make Whole Payment = Maximum of [zero or

(Real-Time Regulation-Up Service Margin + Real-Time Potential Regulation-Up Unused

Make Whole Payment Amount)] * (-1)

(a) Real-Time Regulation-Up Service Margin = Minimum of [zero or Real-Time

Regulation-Up Service Revenue plus Real-Time Regulation-Up Service Cost]

divided by 12;

(i) Real-Time Regulation-Up Service Revenue = (Real-Time MCP as defined

under Section 8.6.2(1)(a)(i) of this Attachment AE) * Maximum of [ zero

or ((Real-Time Cleared Regulation-Up Service Dispatch Interval Quantity

as defined under Section 8.6.2(1)(a)(ii) of this Attachment AE) - (Day-

Ahead Regulation-Up Service Hourly Quantity as defined under Section

8.6.2(1)(a)(iii) of this Attachment AE)) ] / 12 * (-1);

(ii) Real-Time Regulation Up Service Cost = (Real-Time Regulation-Up

Service Offer) * ((Real-Time Cleared Regulation-Up Service Dispatch

Interval Quantity) - (Day-Ahead Regulation-Up Service Hourly Quantity))

/ 12; except that Real-Time Regulation-Up Service Costs associated with


self-scheduled Regulation-Up Service where such self-schedules are less

than or equal to the amount of Real-Time Regulation-Up Service cleared

shall be set equal to zero.

(b) Real-Time Potential Regulation-Up Unused Mileage Make Whole Payment =

[Maximum of [zero or (Expected Regulation-Up Mileage MCP – Real-Time

Regulation-Up Mileage Offer)]] * (Real-Time Unused Regulation-Up Mileage –

Day-Ahead Unused Regulation-Up Mileage), divided by 12

(i) Regulation-Up Mileage Offer is defined under Section 1 of this Attachment

AE. (Regulation-Up Mileage Offer for Real-Time Balancing Market is the

term used here);

(ii) Expected Regulation-Up Mileage MCP is defined under Section 8.3.4(3)

of this Attachment AE;

(iii) Real-Time Unused Regulation-Up Mileage is calculated under Section

8.6.2(1)(a)(iv) of this Attachment AE

(iv) Day-Ahead Unused Regulation-Up Mileage is calculated under Section

8.6.19(1)(b)(iii) of this Attachment AE.


8.6.20 Unused Regulation-Down Mileage Make Whole Payment

A payment will be made to each Asset Owner with a Resource that is charged for Unused

Regulation-Down Mileage at a rate that is in excess of that Resource’s Regulation-Up Mileage

Offer to the extent that Regulation-Down Service margin is not sufficient to offset such excess.

The amount will be calculated on a Dispatch Interval basis as follows:

Unused Regulation-Down Mileage Make Whole Payment Amount =

Day-Ahead Unused Regulation-Down Mileage Make Whole Payment Amount + Real-

Time Unused Regulation-Down Mileage Make Whole Payment Amount

(1) Day-Ahead Unused Regulation-Down Mileage Make Whole Payment = Maximum of

[zero or (Day-Ahead Regulation-Down Service Margin + Day Ahead Potential

Regulation-Down Unused Make Whole Payment Amount)] * (-1)

(a) Day-Ahead Regulation-Down Service Margin = Minimum of [ zero or [(Day-

Ahead Regulation-Down Service Hourly Amount (as calculated under Section

8.5.2 of this Attachment AE) plus Day-Ahead Regulation- Down Service Cost),

divided by 12],

minus

Minimum of [zero or (Real-Time Cleared Regulation-Down Service Dispatch

Interval Quantity (as defined under Section 8.6.2(1)(a)(ii) of this Attachment AE)

-Day-Ahead Regulation-Down Service Hourly Quantity ) ] * (Real-Time MCP (as

defined under Section 8.6.2(2)(a)(i) of this Attachment AE) – Day-Ahead

Regulation-Down Offer ), divided by 12]

(i) If the Resource has cleared Regulation-Down Service that is greater than

the amount of self-scheduled Regulation-Down Service on that Resource,

then Day-Ahead Regulation-Down Service Cost is equal to the cost

calculated as described under Section 8.5.9(4)(a)(v) of this Attachment

AE. If the Resource is not eligible for a Day-Ahead Make Whole Payment

Amount as described under Section 8.5.9 of this Attachment AE and the

Resource has cleared Regulation-Down Service that is less than or equal

to the amount of self-scheduled Regulation-Down Service on that


Resource then Day-Ahead Regulation-Down Service Cost is equal zero for

the purposes of this calculation.

(ii) If the Resource has cleared Regulation-Down Service that is greater than

the amount of self-scheduled Regulation-Down Service on that Resource,

then Day-Ahead Regulation-Down Service Hourly Quantity is equal to the

value described under Section 8.6.2(2)(a)(iii) of this Attachment AE. If the





Regulation-Up Service Hourly Quantity is equal zero for the purposes of

this calculation.

(b) Day-Ahead Potential Regulation-Down Unused Mileage Make Whole Payment =

[Maximum of [zero or (Expected Regulation-Down Mileage MCP – Day-Ahead

Regulation-Down Mileage Offer)]] * Day-Ahead Unused Regulation-Down

Mileage, divided by 12

(i) Regulation-Down Mileage Offer and Regulation-Down Offer are defined

under Section 1 of this Attachment AE. (Regulation-Down Mileage Offer

for Day-Ahead Market and Regulation-Down Offer for Day-Ahead Market

are the terms used here);

(ii) Expected Regulation-Down Mileage MCP is defined under Section

8.3.4(4) of this Attachment AE;

(iii) If Real-Time Cleared Regulation-Down Service Dispatch Interval

Quantity (as described under Section 8.6.2(2)(a)(ii) of this Attachment

AE) is equal to zero then Day-Ahead Unused Regulation-Down Mileage =

Maximum of [zero or (Regulation-Down Unused Mileage (as calculated

under Section 8.6.2(2)(a)(iv) of this Attachment AE), otherwise Day-

Ahead Unused Regulation-Down Mileage = Regulation-Down Unused

Mileage * – MinimumMaximum of [onezero or (Day-AheadReal-Time

Cleared Regulation-Down Service Dispatch Hourly Interval Quantity (as

described under Section 8.6.2(2)(a)(iii) of this Attachment AE) divided by

Real-Time – Day-Ahead Cleared Regulation-Down Service Hourly


Quantity (as described under Section 8.6.2(2)(a)(iii) of this Attachment

AE))])].

(2) Real-Time Unused Regulation-Down Mileage Make Whole Payment = Maximum of [zero

or (Real-Time Regulation-Down Service Margin + Real-Time Potential Regulation-

Down Unused Make Whole Payment Amount)] * (-1)

(a) Real-Time Regulation-Down Service Margin = Minimum of [zero or Real-Time

Regulation-Down Service Revenue plus Real-Time Regulation-Down Service

Cost], divided by 12;

(i) Real-Time Regulation-Down Service Revenue = (Real-Time MCP as

defined under Section 8.6.2(2)(a)(i) of this Attachment AE) * Maximum of

[ zero or ((Real-Time Cleared Regulation-Down Service Dispatch Interval

Quantity as defined under Section 8.6.2(2)(a)(ii) of this Attachment AE) -

(Day-Ahead Regulation-Down Service Hourly Quantity as defined under

Section 8.6.2(2)(a)(ii) of this Attachment AE)) ] / 12 * (-1);

(ii) Real-Time Regulation Down Service Cost = (Real-Time Regulation-Down

Service Offer) * ((Real-Time Cleared Regulation-Down Service Dispatch

Interval Quantity) - (Day-Ahead Regulation-Down Service Hourly

Quantity)) / 12; except that Real-Time Regulation-Down Service Costs

associated with self-scheduled Regulation-Down Service where such self-

schedules are less than or equal to the amount of Real-Time Regulation-

Down Service cleared shall be set equal to zero.

(b) Real-Time Potential Regulation-Down Unused Mileage Make Whole Payment =

[Maximum of [zero or (Expected Regulation-Down Mileage MCP – Real-Time

Regulation-Down Mileage Offer)]] * (Real-Time Unused Regulation-Down

Mileage – Day-Ahead Unused Regulation-Down Mileage), divided by 12

(i) Real-Time Regulation-Down Mileage Offer is defined under Section 1 of

this Attachment AE;

(ii) Expected Regulation-Down Mileage MCP is defined under Section

8.3.4(4) of this Attachment AE;

(iii) Real-Time Unused Regulation-Down Mileage is calculated under Section

8.6.2(2)(a)(iv) of this Attachment AE;


(iv) Day-Ahead Unused Regulation-Down Mileage is calculated under Section

8.6.20(1)(b)(iii) of this Attachment AE.




MPRR No. 212 PRR

Title Over Collected Losses Design Change

Timeline

Normal Expedited Urgent Action

Provide explanation if Expedited and/or Urgent Action is selected: This MPRR is expedited because Real-Time exports receive a larger than normal share of the Real-Time OCL distribution and this distribution has consistently been a charge instead of a credit.


Approve Reject


Defer Refer

Ranking High – 1

Impact Analysis Required Yes, Estimated Cost: $42,300 Duration: 7 months No

Cost impacts and duration includes vendor and SPP Rough Order of Magnitude estimates equal to +/- 50%.


Section No.: 4.5.8, 4.5.8.19; 4.5.8.23, 4.5.9, 4.5.9.20; 4.5.12 Title: Day-Ahead Market Settlement; Day-Ahead Over-Collected Losses Distribution Amount; Day-Ahead Grandfathered Agreement Carve-Out Daily Amount ; 4.5.9 Real-Time Balancing Market Settlement; Real-Time Over-Collected Losses Distribution Amount; Revenue Neutrality Uplift Distribution Amount Protocol Version: 20.b




A design change is needed for the allocation for Day-Ahead and Real-Time Over-Collected Losses (OCL). Today’s design for the Real-Time OCL puts a large percentage of the allocated charges/credits to the SPP Loss Pool. Hubs, Imports and Exports are included in the SPP Loss Pool. Since the Real-Time OCL is based on deviation between Real-Time Actual minus Day-Ahead Cleared, Real-Time exports receive a larger than normal share of the Real-Time OCL distribution. This MPRR proposes to net together Day-Ahead and Real-Time monies and then allocate it out based Real-Time withdrawals. This MPRR changes the design for Over-Collected Losses (OCL). This MPRR will take the charges/credits in the Day-Ahead OCL and net them together with Real-Time OCL. The netted monies will be distributed on a Real-Time withdrawal basis, where Real-Time withdrawals include metered load, exports, Pseudo-Tie Outs, and Bilateral Settlement Schedules.



Attachment AE Section; Section 8.5.16 Day-Ahead Over-Collected Losses Distribution Amount; Section 8.5.18 Day-Ahead GFA Carve Out Daily Amount; Section 8.6.16 Real-Time Over-Collected Losses Distribution Amount;


No



No


MWG


Opposed: N/A

Abstained: Xcel, OGE


Opposed: N/A

Abstained: Xcel

RTWG Date of Vote: 10/3/2014 Vote: Approved with modifications Opposed: N/A Abstained: Xcel


MOPC Date of Vote: 10/14/2014 Vote: Approved Opposed: N/A Abstained: 4


Date 9/5/2014

Sponsor Name Michelle Trenary E-mail Address [email protected] Company Tenaska Power Services Co. Phone Number 817-303-3613


Comment Description The original MPRR212 had the distribution into the loss pool and the allocation within those loss pools based on Day-Ahead Clear withdrawals amounts. MWG decided to change the distribution into the loss pools and allocation within those loss pools to Real-Time withdrawal amounts.




Comments Received


Comment Description RTWG corrected grammar errors in the Tariff. RTWG also corrected the formatting in Section 8.6.16 of the Tariff. The definition of “Loss Pool” was incorrectly deleted out of the Tariff. These comments put the definition back into the Tariff.

Comment Status


4.5.8 Day-Ahead Market Settlement

…

(6) Settlement associated with revenue over collection due to the impact of marginal losses on the DA Market LMPs is also performed as part of the Day-Ahead Market settlement as follows. See described under Section 4.5.89.1920 for calculation details.

(a) For each Loss Pool, a proxy loss charge contribution amount is developed for each Settlement Location with a net withdrawal that is equal to the positive difference between the MLC at the net withdrawal Settlement Location and the weighted average MLC of all net injections assumed to be serving the net withdrawal, multiplied by that Settlement Location’s net withdrawal. These values are then summed to calculate a Loss Pool proxy loss charge contribution.

(i) The net injections assumed to be serving the net withdrawal are the net injections at the Settlement Locations included in the Loss Pool. To the extent that the net injections in the Loss Pool are not sufficient to serve the net withdrawals in the Loss Pool, net injections from an injection exchange are included to make up the difference. To the extent that the net injections in the Loss Pool are greater than the net withdrawals in the Loss Pool, the excess is added to the injection exchange.

(ii) The injection exchange is comprised of quantities from Loss Pools in which injection exceeds withdrawal. A weighted average of the MLC at the source of these quantities establishes a reference for the


component of the loss charge contributions at Settlement Locations with net withdrawal met from outside the Loss Pool.

(b) The Loss Pool proxy loss charge contribution calculated in (a) above are then used to allocate the total DA Market loss over-collections dollars to each Loss Pool on a pro rata basis.

(c) Each Asset Owner’s credit for over collected losses in each Loss Pool at each withdrawal Settlement Location within that Loss Pool is then equal a pro-rata share of the total marginal losses over collection allocated to that Loss Pool. The pro-rata share is calculated as an Asset Owner’s Settlement Location withdrawal divided by the sum of all Asset Owner Settlement Location withdrawals within that Loss Pool. An Asset Owner’s Settlement Location withdrawal is equal to the maximum of (i) zero or (ii)the sum of cleared Demand Bids, cleared Resource Offers, cleared Export Interchange Transactions, cleared Import Interchange Transactions and Bilateral Settlement Schedules for Energy, including those associated with GFA Carve Outs, at that Settlement Location. Asset Owner credits associated with GFA Carve Outs are used to offset GFA Carve Out costs through inclusion of such credits under Section 4.5.8.23.

…

4.5.8.19 Day-Ahead Over-Collected Losses Distribution Amount

(1) The Marginal Losses Component of the DA Market LMP that results from the economic market solution which considers the cost of marginal losses, congestion costs and incremental Energy costs creates an over collection related to payment for losses (“DA Market Over-Collected Losses”) that must be refundedaccounted for. DA Market Over-Collected Losses are calculated and distributed as described under Section 4.5.9.20. A DA Market credit or charge1 is calculated for each hour at each Settlement Location for which an Asset Owner has a DA Market Energy withdrawal in a Loss Pool that contributed positively to the over collection. Each Loss Pool’s contribution to the DA Market Over-Collected Losses is calculated based upon the Settlement Locations contained within the Loss Pool.



There are two types of Loss Pools: (a) Loss Pools defined by all Settlement Locations within a Settlement Area (“Settlement Area Loss Pool”); and (b) a single Loss Pool defined by all Hub and External Interface Settlement Locations (“System-Wide Loss Pool”). Injection/withdrawal amounts associated with Settlement Locations spanning multiple Settlement Area Loss Pools are allocated pro rata using the billable metering values submitted at the associated Meter Data Submittal Locations. A loss rebate factor is calculated for each withdrawal Settlement Location as the difference between the Marginal Loss Component at a withdrawal Settlement Location and the injection weighted average Marginal Loss Component for the Loss Pool, multiplied by the net DA Market Energy withdrawal at that Settlement Location. The injection weighted average MLC for the Loss Pool is calculated assuming that injection in the Loss Pool first serves withdrawal in the Loss Pool and then goes to meet the withdrawal in Loss Pools which do not have sufficient injections to meet all withdrawals. The sum of the Settlement Location loss rebate factors (positive value only, negative values are ignored) in a Loss Pool is a measure of that Loss Pool’s payment for losses on a marginal basis. The Loss Pool sum of the Settlement Location loss rebate factors are then normalized to allocate a pro-rata portion of the total over collection in the hour to each Loss Pool. Within a Loss Pool, each Asset Owner is allocated a portion of the Loss Pool subtotal at each Settlement Location based on a ratio share of its DA Market Energy withdrawal (excluding Virtual Energy Bids and Virtual Energy Offers) to that of the Loss Pool in total. Asset Owners with GFA Carve Out energy transactions are not qualified to receive loss rebates associated with the GFA Carve Out transactions. The amount is calculated as follows:

#DaOclDistHrlyAmt a, s, lp, h = DaAoSlLpLrsHrlyFct a, s, lp, h * DaNormLpRbtHrlyFct lp, h * DaOclHrlyAmt h * (-1)

Where,

(a) DaOclHrlyAmt h = ∑a∑

s

[(DaLmpHrlyPrc s, h - DaMccHrlyPrc s, h )

* ( DaClrdHrlyQty a, s, h + ∑t

DaClrdVHrlyQty a, s, h, t

+ ∑i∑

t

DaImpExp5minQty a, s, i, t / 12 )]

(b) IF DaSppRbtHrlyFct h = 0

THEN


DaNormLpRbtHrlyFct lp, h = 0

ELSE

#DaNormLpRbtHrlyFct lp, h =

Max ( 0, DaLpRbtHrlyFct lp, h / DaSppRbtHrlyFct h )

(b.1) DaSppRbtHrlyFct h = ∑lp

DaLpRbtHrlyFct lp, h

(b.2) DaLpRbtHrlyFct lp, h = ∑s

Max ( 0, DaSlRbtHrlyFct s, lp, h )

(b.3) #DaSlRbtHrlyFct s, lp, h = [ DaLpIntSupplyHrlyFct lp, h

* ( DaMlcHrlyPrc s, h – DaLpIwaMlcHrlyPrc lp, h )

+ ( 1 – DaLpIntSupplyHrlyFct lp, h )

* ( DaMlcHrlyPrc s, h – DaSppIwaMlcHrlyPrc h ) ]

* DaSlWdrHrlyQty s, lp, h

(b.4) DaSlWdrHrlyQty s, lp, h =

Max ( 0, ∑a

SltoLpHrlyMap s, lp, h * [ DaClrdHrlyQty a, s, h + ∑t


+ ∑i∑

t

( DaImpExp5minQty a, s, i, t / 12 ) ] )

(b.5) DaLpWdrHrlyQty lp, h = ∑s

DaSlWdrHrlyQty s, lp, h

(b.6) IF DaLpWdrHrlyQty lp, h = 0

THEN

DaLpIntSupplyHrlyFct lp, h = 0

ELSE

DaLpIntSupplyHrlyFct lp, h =

Min [ 1, DaLpInjHrlyQty lp, h / DaLpWdrHrlyQty lp, h ]

(b.7) DaSlInjHrlyQty s, lp, h =


{ Min (0, ∑a

SltoLpHrlyMap s, lp, h * [ DaClrdHrlyQty a, s, h + ∑t


+ ∑i∑

t

( DaImpExp5minQty a, s, i, t / 12 ) ] ) } * (-1)

(b.8) DaLpInjHrlyQty lp, h = ∑s

DaSlInjHrlyQty s, lp, h

(b.9) IF DaLpInjHrlyQty lp, h = 0

THEN

DaLpExtSupplyHrlyFct lp, h = 0

ELSE

DaLpExtSupplyHrlyFct lp, h =

Max [ 0, ( 1 – (DaLpWdrHrlyQty lp, h

/ DaLpInjHrlyQty lp, h ) ) ]

(bc.10) IF DaLpInjHrlyQty lp, h = 0

THEN

DaLpIwaMlcHrlyPrc lp, h = 0

ELSE

DaLpIwaMlcHrlyPrc lp, h =

∑s

DaSlInjHrlyQty s, lp, h * DaMlcHrlyPrc s, h

/ DaLpInjHrlyQty lp, h

(b.11) DaSppIwaMlcHrlyPrc h = ∑lp

[ DaLpExtSupplyHrlyFct lp, h

* ∑s

( DaSlInjHrlyQty s, lp, h * DaMlcHrlyPrc s, h ) ]

/ ∑lp

[ DaLpExtSupplyHrlyFct lp, h * DaLpInjHrlyQty lp, h ]


(c) DaAoSlLpLrsHrlyFct a, s, lp, h =

DaAoSlWdrHrlyQty a, s, lp, h / DaAoLpWdrHrlyQty lp, h

(c.1) DaAoSlWdrHrlyQty a, s, lp, h =

SltoLpHrlyMap s, lp, h * [ Max (0, ( DaClrdHrlyQty a, s, h

- ∑t

DaEnFinHrlyQty a, s, h, t - ∑t

DaNEnFinHrlyQty a, s, h, t

+ ∑i∑

t

( DaImpExp5minQty a, s, i, t / 12 ) ) ) ]

(c.2) DaAoLpWdrHrlyQty lp, h = ∑a∑

s

DaAoSlWdrHrlyQty a, s, lp, h


DaOclDistDlyAmt a, s, lp, d = ∑h

DaOclDistHrlyAmt a, s, lp, h


DaOclDistAoAmt a, m, d = ∑s∑lp

DaOclDistDlyAmt a, s, lp, d


DaOclDistMpAmt m, d = ∑a

DaOclDistAoAmt a, m, d

Formatted: Don't keep with next, Tab stops:Not at 0.5"

Formatted: Indent: Left: 0", Hanging: 0.25",Space Before: 0 pt

Formatted: Tab stops: Not at 0.5"





Variable

Unit

Settlement

Interval

Definition

DaOclDistHrlyAmt a, s, lp, h $ Hour Day-Ahead Over Collected Losses Distribution Amount per AO per Settlement Location per Loss Pool per Hour - The amount to AO a for AO a’s share of total over collection due to marginal losses at Settlement Location s in Loss Pool lp for the Hour.

DaNormLpRbtHrlyFct lp, h none Hour Day-Ahead Normalized Loss Rebate Factor per Loss Pool per Hour – The percentage of DaOclHrlyAmt h allocated to Loss Pool lp for the Hour.

DaSlRbtHrlyFct s, lp, h $ Hour Day-Ahead Loss Rebate Factor per Settlement Location per Loss Pool per Hour – The amount of marginal loss dollars collected at Settlement Location s in Loss Pool lp for the Hour.

DaLpRbtHrlyFct lp, h $ Hour Day-Ahead Loss Rebate Factor per Loss Pool per Hour – the amount of marginal loss dollars collected in Loss Pool lp for the Hour.

DaSppRbtHrlyFct h $ Hour Day-Ahead Loss Rebate Factor per Hour – The SPP total of DaLpRbtHrlyFct lp, h for the Hour.

DaOclHrlyAmt h $ Hour Day-Ahead Over Collected Losses Amount per Hour – The amount of over collection in the DA Market due to marginal losses for the Hour.

RtIncrOclHrlyAmt h $ Hour Real-Time Incremental Over Collected Losses Amount per Hour – The sum of RtIncrOcl5minAmt i for the Hour.

RtIncrOcl5minAmt i $ Dispatch Interval

Real-Time Incremental Over Collected Losses Amount per Dispatch Interval – The amount of over/under collection in the RTBM due to marginal losses for the Dispatch Interval.

Formatted: ParaText, Left, Indent: Left: 0",Hanging: 0.25"

Formatted: ParaText, Indent: Left: 0",Hanging: 0.25"
















Variable

Unit

Settlement

Interval

Definition

RtLmp5minPrc s, i $/MWh Dispatch Interval

Real-Time LMP – The value described under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i.

RtMcc5minPrc s, i $/MWh Dispatch Interval

Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of Real-Time LMP at Settlement Location s for Dispatch Interval i.


Real-Time Interchange Transaction Quantity per AO per Settlement Location per Transaction per Dispatch Interval – The value described under Section 4.5.9.2 for AO a at Settlement Location s in for transaction t for Dispatch Interval i.

DaImpExp5minQty a, s, i, t MW Dispatch Interval

Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Transaction per Dispatch Interval – The value described under Section 4.5.8.2 for AO a at Settlement Location s in for transaction t for Dispatch Interval i.


Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for AO a at Settlement Location s in for Dispatch Interval i.


MW$ Dispatch Interval

Real-Time SPP Net Inadvertent Energy Amount per Dispatch Interval – The value calculated under Section 4.5.12.

RtPseudoTieLossSpp5minAmt i $ Dispatch Interval

Real-Time SPP Total Pseudo-Tie Losses Amount per Dispatch Interval - The total amount for losses on Pseudo-Ties in Dispatch Interval i.
















Variable

Unit

Settlement

Interval

Definition

RtPseudoTieLoss5minAmt a, source,

sink,(s), i $ Dispatch

Interval Real-Time Pseudo-Tie Losses Amount per Asset Owner per source-sink

path per Dispatch Interval - The value described under 4.5.9.27 for AO a on path source to sink in Dispatch Interval i. For the purpose of its inclusion in the calculation of the Loss Rebate Factor the sink (s) notation is an indication that value is collected at the sink Settlement Location.

RtEnFinHrlyQty a, s, t, h MWh Hour Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The value described under Section 4.5.9.1 for AO a at Settlement Location s for Hour h.

RtNEnFinHrlyQty a, s, t, h MWh Hour Non-Asset Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The value described under Section 4.5.9.2 for AO a at Settlement Location s for Hour h.

RsgCrdFlg t



DaLpIntSupplyHrlyFct lp, h none Hour Day-Ahead Loss Pool Internal Supply Factor per Loss Pool per Hour – A ratio indicating the percentage of Loss Pool lp’s net DA Market Energy withdrawals that are being served by net injections inside of Loss Pool lp.












Variable

Unit

Settlement

Interval

Definition

DaLpExtSupplyHrlyFct lp, h none Hour Day-Ahead Loss Pool External Supply Factor per Loss Pool per Hour – A ratio indicating the percentage of Loss Pool lp’s net DA Market Energy injections that are in excess of Loss Pool lp’s net withdrawals.

DaLpIwaMlcHrlyPrc lp, h $/MWh Hour Day-Ahead Loss Pool Injection Weighted Average Marginal Loss Component per Loss Pool per Hour - The weighted average DaMlcHrlyPrc s, h for all net DA Market Energy injections in loss pool lp in Hour h.

DaSppIwaMlcHrlyPrc h $/MWh Hour Day-Ahead SPP Injection Weighted Average Marginal Loss Component per Hour - The weighted average DaMlcHrlyPrc s, h for all loss pool DA Market Energy injections in excess of loss pool net DA Market Energy withdrawals in Hour h.

DaLpInjHrlyQty lp, h MWh Hour Day-Ahead Net Injection Quantity per Loss Pool per Hour –The net DA Market Energy injection quantity in Loss pool lp in Hour h.

DaSlInjHrlyQty s, lp, h MWh Hour Day-Ahead Net Injection Quantity per Settlement Location per Loss Pool per Hour – Settlement Location s’s net DA Market Energy injection quantity in Loss pool lp in Hour h.

DaLpWdrHrlyQty lp, h MWh Hour Day-Ahead Net Withdrawal Quantity per Loss Pool per Hour –The net DA Market Energy withdrawal in Loss pool lp in Hour h.

DaSlWdrHrlyQty s, lp, h MWh Hour Day-Ahead Net Withdrawal Quantity per Settlement Location per Loss Pool per Hour –Settlement Location s’s net DA Market Energy withdrawal quantity for Hour h.
















Variable

Unit

Settlement

Interval

Definition

DaLmpHrlyPrc s, h $/MWh Hour Day-Ahead LMP – The value described under Section 4.5.8.1 at Settlement Location s for Hour h.

DaMccHrlyPrc s, h $/MWh Hour Day-Ahead Marginal Congestion Component of Day-Ahead LMP – The value described under Section 4.5.8.14 at Settlement Location s for Hour h.

DaMlcHrlyPrc s, h $/MWh Hour Day-Ahead Marginal Losses Component of Day-Ahead LMP – The Marginal Losses Component of the Day-Ahead LMP at Settlement Location s for Hour h.

SltoLpHrlyMap s, lp, h none Hour Settlement Location to Loss Pool Map per Settlement Location per Loss Pool per Hour - The portion of injection or withdrawal at Settlement Location s associated with Loss Pool lp for the Hour.

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 for AO a at Settlement Location s in for Hour h.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Transaction per Hour in the DA Market – The value described under Section 4.5.8.3 for AO a at Settlement Location s in for transaction t for Hour h.


















Variable

Unit

Settlement

Interval

Definition

DaEnFinHrlyQty a, s, h, t MWh Hour Day-Ahead Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h

DaNEnFinHrlyQty a, s, h, t MWh Hour Day-Ahead Non-Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h

DaAoSlLpLrsHrlyFct a, s, lp, h none Hour Day-Ahead Loss Pool Load Ratio Share per AO per Settlement Location per Loss Pool per Hour – The ratio of AO a’s net DA Market Energy withdrawals at Settlement Location s to the total net DA Market Energy withdrawals in Loss Pool lp for Hour h.

DaAoSlWdrHrlyQty a, s, lp, h MWh Hour Day-Ahead Net Market Energy Asset Owner withdrawal per AO per Settlement Location per Loss Pool per Hour – The positive value of the net sum of AO a’s Day-Ahead Cleared Energy, Day-Ahead Interchange Transaction, Day-Ahead Asset Energy Bilateral Settlement Schedule and Day-Ahead Non-Asset Energy Bilateral Settlement Schedule Quantities at Settlement Location s in a Loss Pool lp for Hour h.

DaAoLpWdrHrlyQty lp, h MWh Hour Day-Ahead Net Market Asset Owner Energy withdrawal per Loss Pool per Hour – The sum of Day-Ahead Market Energy Asset Owner net DA Market Energy withdrawal in a Loss Pool lp for Hour h.












Variable

Unit

Settlement

Interval

Definition

DaOclDistDlyAmt a, s, lp, d $ Operating Day

Day-Ahead Over Collected Losses Distribution Amount per AO per Settlement Location per Loss Pool per Operating Day- The amount to AO a for AO a’s share of total over collection due to marginal losses at Settlement Location s in Loss Pool lp for the Operating Day.

DaOclDistAoAmt a, m, d $ Operating Day

Day-Ahead Over Collected Losses Distribution Amount per AO per Operating Day- The amount to AO a associated with Market Participant m for AO a’s share of total over collection due to marginal losses for the Operating Day.


Day-Ahead Over Collected Losses Distribution Amount per MP per Operating Day- The amount to MP m for MP m’s share of total over collection due to marginal losses for the Operating Day.

A none none An Asset Owner.

S none none A 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.

D none none An Operating Day.

Lp none none A Loss Pool.


















Formatted ...

Formatted ...

Formatted ...


Variable

Unit

Settlement

Interval

Definition

M none none A Market Participant. Formatted: ParaText, Left, Indent: Left: 0",Hanging: 0.25"



4.5.8.23 Day-Ahead Grandfathered Agreement Carve-Out Daily Amount

(1) A DA Market credit or charge for exclusion of transactions associated with Grandfathered Agreements from Market Settlement of congestion, losses and hedging instruments, is calculated each day for every Asset Owner modeled to represent a Grandfathered Agreement Carve-Out. The net amount is calculated as follows:

#DaGFAAoAmt a, m, d = -1 * [ DaEnergyAoAmt a, m, d + DaNEnergyAoAmt a, m, d

+ TcrFundAoAmt a, m, d + TcrUpliftDlyAmt a, m, d

+ DaRtOclDistAoAmt a, m, d

+ TcrAucTxnAoAmt a, m, d + ArrAucTxnAoAmt a, m, d

+ ArrUpliftAoAmt a, m, d ] * AoIsGFADlyFlg a, m, d

(2) For each Market Participant, a daily amount is calculated representing the sum of Grandfathered Agreement Carve-Out Asset Owner amounts associated with that Market Participant. The net amount is calculated as follows:

DaGFAMpAmt m, d = ∑a

DaGFAAoAmt a, m, d



Variable

Unit

Settlement Interval

Definition

DaGFAAoAmt a, m, d $

Operating Day

Day-Ahead Grandfathered Agreement Carve-Out Daily Amount per AO per Operating Day – The net reversal of charges and credits 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 to AO a modeled to represent a Grandfathered Agreement Carve-Out associated with Market Participant m for the Operating Day

DaEnergyAoAmt a, m, d $

Operating Day

Day-Ahead Asset Energy Amount per AO per Operating Day – The value as calculated under 4.5.8.1.

DaNEnergyAoAmt a, m, d $

Operating Day

Day-Ahead Non-Asset Energy Amount per AO per Operating Day – The value as calculated under 4.5.8.2.

TcrFundAoAmt a, m, d $

Operating Day

Transmission Congestion Rights Funding Amount per AO per Operating Day – The value as calculated under 4.5.8.14.

TcrUpliftDlyAmt a, m, d $

Operating Day

Transmission Congestion Rights Daily Uplift Amount per AO – The value as calculated under 4.5.8.15.

DaRtOclDistAoAmt a, m, d $

Operating Day

Day-AheadReal-Time Over Collected Losses Distribution Amount per AO per Operating Day – The value as calculated under 4.5.89.1920.

TcrAucTxnAoAmt a, m, d $

Operating Day

Transmission Congestion Right Auction Daily Amount per AO per Operating Day – The value as calculated under 4.5.10.1.

ArrAucTxnAoAmt a, m, d $

Operating Day

Auction Revenue Rights Daily Amount per AO per Operating Day – The value as calculated under 4.5.10.2.

ArrUpliftAoAmt a, m, d $

Operating Day

Auction Revenue Rights Daily Uplift Amount per AO per Operating Day – The value as calculated under 4.5.10.3.


Variable

Unit

Settlement Interval

Definition

AoIsGFADlyFlg a, m. d Operating Day

Grandfathered Agreement Carve-Out Asset Owner Flag per AO per Operating Day – A Flag which indicates that the AO is exempt from Day-Ahead Transmission Congestion charge types, thus forcing the cost allocation of the exclusion into Non GFA Load Ratio Share

DaGFAMpAmt m, d $

Operating Day

Day-Ahead Grandfathered Agreement Carve-Out Daily Amount per MP per Operating Day – The net reversal of charges and credits 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 to Market Participant m for net cleared offers and bids, net of Bilateral Settlement Schedules for Energy for the Operating Day.

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


4.5.9 Real-Time Balancing Market Settlement

… (13) Settlement associated with revenue mismatch due to the impact of marginal losses on the

Day-Ahead Market LMPs and RTBM LMPs is also performed as part of the RTBM settlement as follows. See Section 4.5.9.20 for calculation details;

(a) For each Loss Pool, a proxy loss charge contribution amount is developed for each Settlement Location with a net RTBM withdrawal (RTBM actual – DA Market cleared amount) that is equal to the sum of i) the positive difference between the MLC at the net withdrawal Settlement Location and the weighted average MLC of all net injections (RTBM actual – DA Market cleared amount) assumed to be serving the net withdrawal, multiplied by that Settlement Location’s net withdrawal, and ii) the sum of charges for Real-Time pseudo-tie Losses at the Settlement Location of the Sink of the pseudo-tie path. These values are then summed to calculate a Loss Pool proxy loss charge contribution.

(i) The net injections assumed to be serving the net withdrawal are the net injections at the Settlement Locations included in that the Loss Pool. To the extent that the net injections in the Loss Pool are not sufficient to serve the net withdrawals in the Loss Pool, net injections from an injection exchange are included to make up the difference. To the extent that the net injections in the Loss Pool are greater than the net withdrawals in the Loss Pool, the excess is added to the injection exchange;

(ii) The injection exchange is comprised of quantities from Loss Pools in which injection exceeds withdrawal. A weighted average of the MLC at the source of these quantities establishes a reference for the component of the loss charge contributions at Settlement Locations with net withdrawal met from outside the Loss Pool.

(b) The Loss Pool proxy loss charge contribution calculated in (a) above are then used to allocated to the total DA Market loss over-collections dollars to each Loss Pool on a pro rata basis.

(a) Each Asset Owner’s credit or charge (all Asset Owner net withdrawals at Settlement Location participate) in each Loss Pool at each withdrawal Settlement Location within that Loss Pool is then equal a pro-rata share of the total marginal


losses over collection or under collection allocated to that Loss Pool. The pro-rata share is calculated as an Asset Owner’s Settlement Location withdrawal divided by the sum of all Asset Owner Settlement Location withdrawals within that Loss Pool. Settlement Location withdrawal is equal to the maximum of (1) zero or (2) the sum of the (i) the difference between Real-Time metered load and DA Market cleared Demand Bids, (ii) the difference between Real-Time metered generation and Day-Ahead Market cleared Resource Offers, (iii) the difference between Real-Time and Day-Ahead Export Interchange Transactions, (iv) the difference between Real-Time and Day-Ahead Import Interchange Transactions, and (v) Real-Time Bilateral Settlement Schedules for Energy, and (vi) Day-Ahead Market Bilateral Settlement Schedules for Energy, including those associated with GFA Carve Outs, at that Settlement Location. Asset Owner credits associated with GFA Carve Outs are used to offset GFA Carve Out costs through inclusion of such credits under Section 4.5.8.23.

(c)

…

4.5.9.20 Real-Time Over-Collected Losses Distribution Amount (1) The Marginal Losses Component of the Day-Ahead Market LMP and RTBM LMP that

results from the economic market solution which considers the cost of marginal losses, congestion costs and incremental Energy costs creates an over collection (or under collection as a result of the Real-Time deviation accounting) related to payment for losses (“RTBM Over-Collected Losses”) that must be accounted for. A RTBM credit or charge is calculated for each hour at each Settlement Location for which an Asset Owner has a net RTBM Energy withdrawal in a Loss Pool that contributed positively to the over collection or under collection or paid a charge for Real-Time Pseudo-Tie Losses at the Settlement Location of the Sink of the Pseudo-Tie path for use of the SPP Transmission system. Each Loss Pool’s contribution to the RTBM Over-Collected Losses is calculated based upon the Settlement Locations contained within the Loss Pool. There are two types of Loss Pools: (a) Loss Pools defined by all Settlement Locations within a Settlement Area (“Settlement Area Loss Pool”); and (b) a single Loss Pool defined by all Hub and External Interface Settlement Locations (“System-Wide Loss Pool”). Injection/withdrawal amounts associated with Settlement Locations spanning multiple Settlement Area Loss Pools are allocated pro rata using the billable metering values submitted at the associated Meter Data Submittal Locations. A loss


rebate factor is calculated for each withdrawal Settlement Location as the sum of i) the difference between the Marginal Loss Component at a withdrawal Settlement Location and the injection weighted average Marginal Loss Component for the Loss Pool, multiplied by the net RTBM Energy withdrawal at that Settlement Location and ii) the sum of charges for Real-Time Pseudo-Tie Losses at the Settlement Location of the Sink of the pseudo-tie path. The injection weighted average MLC for the Loss Pool is calculated assuming that injection in the Loss Pool first serves withdrawal in the Loss Pool and then goes to meet the withdrawal in Loss Pools which do not have sufficient injection to meet all withdrawal. The sum of the Settlement Location loss rebate factors (positive value only, negative values are ignored) is a measure of that Loss Pool’s payment for losses on a marginal basis. The Loss Pool sum of the Settlement Location loss rebate factors are then normalized to allocate a pro-rata portion of the total over collection or under collection in the hour to each Loss Pool. Within a Loss Pool, each Asset Owner is allocated a portion of the Loss Pool subtotal at each Settlement Location based on a ratio share of its net RTBM Market Energy withdrawal to that of the Loss Pool in total. Asset Owners with GFA Carve Out energy transactions are not qualified to receive loss rebates associated with the GFA Carve Out transactions. The amount is calculated as follows.

#RtOclDistHrlyAmt a, s, lp, h =

RtAoSlLpLrsHrlyFct a, s, lp, h *

RtNormLpRbtHrlyFct lp, h

* ( RtIncrOclHrlyAmt h + DaOclHrlyAmt h )* (-1)

Where,

(a) RtIncrOclHrlyAmt h = ∑i

RtIncrOcl5minAmt i

(a.1) #RtIncrOcl5minAmt i =

∑a∑

s

[ ( RtLmp5minPrc s, i – RtMcc5minPrc s, i )

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


– ∑t


+ ∑t

RtImpExp5minQty a, s, i, t – ∑t

DaImpExp5minQty a, s, i, t ) ] / 12

+ RtNetInadvertentSpp5minAmt i + RtPseudoTieLossSpp5minAmt i

(a.2) RtPseudoTieLossSpp5minAmt i =

∑a

∑source

∑ksin

RtPseudoTieLoss5minAmt a, source, sink, i

(a.3) #DaOclHrlyAmt h = ∑a∑

s

[(DaLmpHrlyPrc s, h - DaMccHrlyPrc s, h )

* ( DaClrdHrlyQty a, s, h + ∑t


+ ∑i∑

t

DaImpExp5minQty a, s, i, t / 12 )]

(b) IF RtSppRbtHrlyFct h = 0

THEN

RtNormLpRbtHrlyFct lp, h = 0

ELSE

#RtNormLpRbtHrlyFct lp, h =

Max ( 0, RtLpRbtHrlyFct lp, h ) / RtSppRbtHrlyFct h

(b.1) RtSppRbtHrlyFct h = ∑lp

RtLpRbtHrlyFct lp, h

Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed

Field Code Changed


(b.2) RtLpRbtHrlyFct lp, h = ∑s

Max ( 0, RtSlRbtHrlyFct s, lp, h )

(b.3) RtSlRbtHrlyFct s, lp, h = ∑i

RtSlRbt5minFct s, lp, i

(b.4) #RtSlRbt5minFct s, lp, i = { [ RtLpIntSupply5minFct lp, i

* ( RtMlc5minPrc s, i – RtLpIwaMlc5minPrc lp, i )

+ ( 1 – RtLpIntSupply5minFct lp, i )

* (RtMlc5minPrc s, i – RtSppIwaMlc5minPrc i ) ]

* RtSlWdr5minQty s, lp, i }

+ SltoLp5minMap s, lp, i * ∑source

RtPseudoTieLoss5minAmt a, source, sink (s), i

(b.5) RtSlWdr5minQty s, lp, i =

Max (0, ∑a

SltoLp5minMap s, lp, i * ( RtBillMtr5minQty a, s, i

– DaClrdHrlyQty a, s, h – ∑t


+ ∑t

RtImpExp5minQty a, s, i, t * (1 – RsgCrdFlgt )

–∑t

DaImpExp5minQty a, s, i, t ) ) / 12

(b.6) RtLpWdr5minQty lp, i = ∑s

RtSlWdr5minQty s, lp, i

(b.7) IF RtLpWdr5minQty lp, i = 0


THEN

RtLpIntSupply5minFct lp, i = 0

ELSE

RtLpIntSupply5minFct lp, i =

Min [ 1, RtLpInj5minQty lp, i / RtLpWdr5minQty lp, i ]

(b.8) RtSlInj5minQty s, lp, i = (–1)

* { Min ( 0, ∑a

SltoLp5minMap s, lp, i *

[ RtBillMtr5minQty a, s, i

– DaClrdHrlyQty a, s, h

– ∑t


+ ∑t


– ∑t

DaImpExp5minQty a, s, i, t ] ) } / 12

(b.9) RtLpInj5minQty lp, i = ∑s

RtSlInj5minQty s, lp, i

(b.10) IF RtLpInj5minQty lp, i = 0

THEN

RtLpExtSupply5minFct lp, i = 0

ELSE

RtLpExtSupply5minFct lp, i =


Max [ 0, ( 1 – (RtLpWdr5minQty lp, i

/ RtLpInj5minQty lp, i ) ) ]

(b.11) IF RtLpInj5minQty lp, i = 0

THEN

RtLpIwaMlc5minPrc lp, i = 0

ELSE

RtLpIwaMlc5minPrc lp, i =

∑s

[RtSlInj5minQty s, lp, i * RtMlc5minPrc s, i ]

/ RtLpInj5minQty lp, i

(b.12) RtSppIwaMlc5minPrc i = ∑lp

[ RtLpExtSupply5minFct lp, i

* ∑s

( RtSlInj5minQty s, lp, i a, s, lp, i * RtMlc5minPrc s, i ) ]

/ ∑lp

[ RtLpExtSupply5minFct lp, i * RtLpInj5minQty lp, i ]

(c) RtAoSlLpLrsHrlyFct a, s, lp, h =

RtAoSlWdrHrlyQty a, s, lp, h / RtAoLpWdrHrlyQty lp, h

(c.1) RtAoSlWdrHrlyQty a, s, lp, h =

∑i

Max ( 0, SltoLp5minMap s, lp, i * { [ ( RtBillMtr5minQty a, s, i

– DaClrdHrlyQty a, s, h


+ ∑t


–∑t

DaImpExp5minQty a, s, i, t + (IF RtIncrOclHrlyAmth < 0 THEN 0

ELSE 1) * ∑ source RtPseudoTie5minQty a, source, sink(s), i ) ]

- ∑t

RtEnFinHrlyQty a, s, h, t - ∑t

RtNEnFinHrlyQty a, s, h, t

- ∑t

DaEnFinHrlyQty a, s, h, t - ∑t

DaNEnFinHrlyQty a, s, h, t }

/ 12)

(c.2) RtAoLpWdrHrlyQty lp, h = ∑a∑

s

RtAoSlWdrHrlyQty a, s, lp, h


RtOclDistDlyAmt a, s, lp, d = ∑h

RtOclDistHrlyAmt a, s, lp, h


RtOclDistAoAmt a, m, d = ∑s∑

lp RtOclDistDlyAmt a, s, lp, d


RtOclDistMpAmt m, d = ∑a

RtOclDistAoAmt a, m, d

Field Code Changed

Field Code Changed



Unit

Settlement Interval

Definition

RtOclDistHrlyAmt a, s, lp, h $ Hour Real-Time Over Collected Losses Distribution Amount per AO per Settlement Location in Loss Pool lp per Hour - The amount to AO a for AO a’s share of total over/under collection due to marginal losses at Settlement Location s in Loss Pool lp for the Hour.

RtPseudoTieLossSpp5minAmt i $ Dispatch Interval

Real-Time SPP Total Pseudo-Tie Losses Amount per Dispatch Interval - The total amount for losses on Pseudo-Ties in Dispatch Interval i.

RtPseudoTie5minQty a, source, sink, i MW Dispatch Interval

Real-Time Pseudo-Tie Quantity per Asset Owner per source-sink path per Dispatch Interval – The value described under Section 4.5.9.26.

RtPseudoTieLoss5minAmt a, source,

sink,(s), i $ Dispatch

Interval Real-Time Pseudo-Tie Losses Amount per Asset Owner per source-sink path per Dispatch Interval - The value described under 4.5.9.27 for AO a on path source to sink in Dispatch Interval i. For the purpose of its inclusion in the calculation of the Loss Rebate Factor the sink (s) notation is an indication that value is collected at the sink Settlement Location.

RtNormLpRbtHrlyFct lp, h none Hour Real-Time Normalized Loss Rebate Factor per Loss Pool per Hour – The percentage of RtIncrOclHrlyAmt h allocated to Loss Pool lp for the Hour.

RtSlRbtHrlyFct s, lp, h $ Hour Real-Time Loss Rebate Factor per Settlement Location per Loss Pool per Hour – The sum of RtSlRbt5minFct s, lp, i at Settlement Location s in Loss Pool lp for the Hour.

RtSlRbt5minFct s, lp, i $ Dispatch Interval

Real-Time Loss Rebate Factor per Settlement Location per Loss Pool per Dispatch Interval– The amount of marginal loss dollars calculated at Settlement Location s in Loss Pool lp for the Dispatch Interval.

RtSppRbtHrlyFct h $ Hour Real-Time Loss Rebate Factor per Hour – The SPP total of RtLpRbtHrlyFct lp, h for the Hour.

RtLpRbtHrlyFct lp, h $ Hour Real-Time Loss Rebate Factor per Loss Pool per Hour – The amount of marginal loss dollars collected in Loss Pool lp for the Hour.


Variable

Unit

Settlement Interval

Definition

RtIncrOclHrlyAmt h $ Hour Real-Time Incremental Over Collected Losses Amount per Hour – The sum of RtIncrOcl5minAmt i for the Hour.

DaOclHrlyAmt h $ Hour Day-Ahead Over Collected Losses Amount per Hour – The amount of over collection in the DA Market due to marginal losses for the Hour.

RtIncrOcl5minAmt i $ Dispatch Interval

Real-Time Incremental Over Collected Losses Amount per Dispatch Interval – The amount of over/under collection in the RTBM due to marginal losses for the Dispatch Interval.

RtLpIntSupply5minFct lp, i none Dispatch Interval

Real-Time Loss Pool Internal Supply Factor per Loss Pool per Dispatch Interval – A ratio indicating the percentage of Loss Pool lp’s net withdrawals that are being served by net RTBM Energy injections inside of Loss Pool lp in Dispatch Interval i.

RtLpExtSupply5minFct lp, i none Dispatch Interval

Real-Time Loss Pool External Supply Factor per Loss Pool per Dispatch Interval – A ratio indicating the percentage of Loss Pool lp’s net RTBM Energy injections that are in excess of Loss Pool lp’s net RTBM Energy withdrawals in Dispatch Interval i.

RtLpIwaMlc5minPrc lp, i $/MWh Dispatch Interval

Real-Time Loss Pool Injection Weighted Average Marginal Loss Component per Loss Pool per Dispatch Interval - The weighted average RtMlc5minPrc s, i for all net RTBM Energy injections in loss pool lp in Dispatch Interval i.

RtSppIwaMlc5minPrc i $/MWh Dispatch Interval

Real-Time SPP Injection Weighted Average Marginal Loss Component per Dispatch Interval - The weighted average of RtMlc5minPrc s, i for all loss pool net RTBM Energy injections in excess of loss pool net RTBM Energy withdrawals in Dispatch Interval i.

RtLpInj5minQty , lp, i MW Dispatch Interval

Real-Time Net Injection Quantity per Loss Pool per Dispatch Interval – The net RTBM Energy injection quantity in Loss pool lp in Dispatch Interval i.

RtSlInj5minQty s, lp, i MWh Dispatch Interval

Real-Time Net Injection Quantity per Settlement Location per Loss Pool per Dispatch Interval – Settlement Location s’s net RTBM Energy injection quantity in Loss pool lp in Dispatch Interval i.

Formatted: Font: Times New Roman Bold,Italic, Subscript

Formatted: Font: Not Italic


Variable

Unit

Settlement Interval

Definition

RtLpWdr5minQty lp, i MW Dispatch Interval

Real-Time Net Withdrawal Quantity per Settlement Location per Loss Pool per Dispatch Interval – The net RTBM Energy withdrawal quantity in Loss pool lp in Dispatch Interval i.

RtAoSlLpLrsHrlyFct a, s, lp, h None

Hour

Real-Time Loss Pool Load Ratio Share per AO per Settlement Location per Loss Pool per Hour – The ratio of AO a’s The net RTBM Energy withdrawal at Settlement Location s to the total The net RTBM Energy withdrawals in Loss pool lp in Hour h.

RtAoSlWdrHrlyQty a, s, lp, h MWh Hour Real-Time Net Market Energy Asset Owner Withdrawal per AO per Settlement Location per Loss Pool per Hour – The positive value of the sum of the difference between AO a’s RTBM Energy and its DA Market Energy instruments at Settlement Location s in Loss pool lp in Hour h.

RtAoLpWdrHrlyQty lp, h MWh Hour Real-Time Net Market Energy Withdrawal per Loss Pool per Hour – The sum of net RTBM Energy Asset Owner withdrawal in Loss pool lp in Hour h.

RtSlWdr5minQty s, lp, i MWh Dispatch Interval

Real-Time Net Withdrawal Quantity per Settlement Location per Loss Pool per Dispatch Interval – Settlement Location s’s net RTBM Energy withdrawal quantity in Loss Pool lp in Dispatch Interval i.

SltoLp5minMap s, lp, i none Dispatch Interval

Settlement Location to Loss Pool Map per Settlement Location per Loss Pool per Dispatch Interval - The portion of injection or withdrawal at Settlement Location s associated with Loss Pool lp for Dispatch Interval i.

RtLmp5minPrc s, i $/MWh Dispatch Interval

Real-Time LMP – The value described under Section 4.5.9.1 at Settlement Location s for Dispatch Interval i.

RtMcc5minPrc s, i $/MWh Dispatch Interval

Real-Time Marginal Congestion Component of Real-Time LMP – The Marginal Congestion Component of Real-Time LMP at Settlement Location s for Dispatch Interval i.

DaLmpHrlyPrc s, h $/MWh Hour Day-Ahead LMP – The value described under Section 4.5.8.1 at Settlement Location s for Hour h.




Variable

Unit

Settlement Interval

Definition

DaMccHrlyPrc s, h $/MWh Hour Day-Ahead Marginal Congestion Component of Day-Ahead LMP – The value described under Section 4.5.8.14 at Settlement Location s for Hour h.

RtMlc5minPrc s, i $/MWh Dispatch Interval

Real-Time Marginal Losses Component of Real-Time LMP – The Marginal Losses Component of the Real-Time LMP at Settlement Location s for Dispatch Interval i.

RtEnFinHrlyQty a, s, t, h MWh Hour Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The value described under Section 4.5.9.1 for AO a at Settlement Location s for Hour h.

RtNEnFinHrlyQty a, s, t, h MWh Hour Non-Asset Bilateral Settlement Schedule for Energy per AO per Settlement Location per Transaction per Hour - The value described under Section 4.5.9.2 for AO a at Settlement Location s for Hour h.

DaEnFinHrlyQty a, s, h, t MWh Hour Day-Ahead Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h.

DaNEnFinHrlyQty a, s, h, t MWh Hour Day-Ahead Non-Asset Energy Bilateral Settlement Schedule per AO per Transaction per Settlement Location per Hour – The value described under Section 4.5.8.2 for AO a at Settlement Location s for transaction t for Hour h.

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 for AO a at Settlement Location s for Hour h.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Transaction per Hour in the DA Market – The value described under Section 4.5.8.3 for AO a at Settlement Location s in for transaction t for Hour h.










Variable

Unit

Settlement Interval

Definition


Real-Time Interchange Transaction Quantity per AO per Settlement Location per Transaction per Dispatch Interval – The value described under Section 4.5.9.2 for AO a at Settlement Location s in for transaction t for Dispatch Interval i.

RsgCrdFlg t




Real-Time Billing Meter Quantity per AO per Settlement Location per Dispatch Interval - The value described under Section 4.5.9.1 for AO a at Settlement Location s in for Dispatch Interval i.


MW$ Dispatch

Interval Real-Time SPP Net Inadvertent Energy Amount per Dispatch Interval – The value calculated under Section 4.5.12.

RtOclDistDlyAmt a, s, lp, d $ Operating Day

Real-Time Over Collected Losses Distribution Amount per AO per Settlement Location per Loss Pool Operating Day - The amount to AO a for AO a’s share of total over/under collection due to marginal losses at Settlement Location s in Loss Pool lp for the Operating Day.

RtOclDistAoAmt a, m, d $ Operating Day

Real-Time Over Collected Losses Distribution Amount per AO per Operating Day- The amount to AO a associated with Market Participant m for AO a’s share of total over/under collection due to marginal losses for the Operating Day.


Real-Time Over Collected Losses Distribution Amount per MP per Operating Day- The amount to MP m for MP m’s share of total over/under collection due to marginal losses for the Operating Day.

a none none An Asset Owner. s none none A Settlement Location. h none none An Hour. i none none A Dispatch Interval.


Variable

Unit

Settlement Interval

Definition

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.

d none none An Operating Day. lp none none A Loss Pool. m none none A Market Participant.


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 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.

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

#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 ) / 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

+ 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

+ DaOclDistMpAmt 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

RtIncrOclHrlyAmt h- ∑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

+ RtRegUpUnusedMileMwpMpAmt m, d

Field Code Changed

Field Code Changed


+ RtRegDnUnusedMileMwpMpAmt m, d

+ RtSpinDistMpAmt m, d + RtSuppDistMpAmt m, d

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

- ∑h

RtIncrOclHrlyAmt 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 )

Comment [MPRR102.1]: MPRR102 awaiting implementation #ER13-1748

Field Code Changed

Field Code Changed


+ ∑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


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



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.


Variable

Unit

Settlement Interval

Definition

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 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.


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.

Comment [MPRR102.2]: MPRR102 awaiting implementation. #ER13-1748





Variable

Unit

Settlement Interval

Definition

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.


Day-Ahead Over Collected Losses Distribution Amount per MP per Operating Day - The value calculated under Section 4.5.8.19.

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.

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.





RsgCrdFlg t none none Reserve Sharing Group Contingency Reserve Deployment Flag per


Variable

Unit

Settlement Interval

Definition


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.


Real-Time Regulation-Up Service Amount per MP per Operating Day – The value described under Section4.5.9.4.


Real-Time Unused Regulation-Up Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.24.


Real-Time Regulation-Down Service Amount per MP per Operating Day – The value described under Section 4.5.9.5.


Real-Time Unused Regulation-Down Mileage Make Whole Payment Amount per MP per Operating Day – The value described under Section 4.5.9.25.






Variable

Unit

Settlement Interval

Definition

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


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.


Real-Time Over Collected Losses Distribution Amount per MP per Operating Day - The value calculated under Section 4.5.9.20.

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.


Variable

Unit

Settlement Interval

Definition

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.


Real-Time Regulation-Up Service Distribution Amount – The value calculated under Section 4.5.9.11.


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.




Variable

Unit

Settlement Interval

Definition

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.

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.

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

a none none An Asset Owner. s none none A Resource Settlement Location. h none none An Hour.


Variable

Unit

Settlement Interval

Definition

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.



Attachment AE

1.1 Definitions and Acronyms

1.1 Definitions L

Loss Pool

A collection of either (i) Settlement Locations within a Settlement Area (a “Settlement Area Loss

Pool”), or (ii) all External Interfaces and Market Hubs located throughout the Transmission System,

that is used for the purpose of determining an Asset Owner’s allocation of over-collected loss revenues

in Sections 8.5.16 or 8.6.16 of Attachment AE.

8.5.16 Day-Ahead Over-Collected Losses Distribution Amount

The MLC of the Day-Ahead Market LMP creates an over collection of funds related to

payment for losses (“Day-Ahead Market Over-Collected Losses”) that is calculated and

distributed must be refunded to Asset Owners, as described in this Section 8.65.16 of this

Attachment AE. Day-Ahead Market Over-Collected Losses refunds associated with a GFA

Carve Out are calculated pursuant to this Section 8.5.16 and included as a credit to the GFA

Carve Out costs under Section 8.5.18 of this Attachment AE, and shall not be credited to a GFA

Carve Out Responsible Entity to the extent of load it serves under GFA Carve Out Schedule(s).

(1) A payment/charge for the portion of such Day-Ahead Market over-collected

losses allocable to each Asset Owner (“Day-Ahead Over-Collected Losses Distribution

Amount”) shall be calculated for each hour at each Settlement Location for which an Asset

Owner has a Day-Ahead Market Energy withdrawal within a Loss Pool, provided that such

withdrawal does not include Energy associated with cleared Virtual Energy Bids, and such Loss

Pool contributed positively to the over-collection according to the following calculations:

(a) Each Loss Pool’s contribution to the Day-Ahead Market over-collected losses is

calculated based on transactional activity in that Loss Pool where such transactional activity shall

include: cleared Resource Offers, cleared Demand Bids, cleared Import Interchange Transaction

Offers, cleared Export Interchange Transaction Bids, cleared Virtual Energy Bids and cleared

Virtual Energy Offers.


(b) A “Day-Ahead Market Loss Pool loss rebate factor” is calculated hourly for each

Loss Pool. The Day-Ahead Market Loss Pool loss rebate factor is equal to the sum of the

positive loss rebate factors calculated in the Day-Ahead Market at each withdrawal Settlement

Location in the Loss Pool (the “Day-Ahead Market Withdrawal Settlement Location loss rebate

factor”). Day-Ahead Market Withdrawal Settlement Location loss rebate factors are calculated

hourly as the difference between the Day-Ahead MLC at a withdrawal Settlement Location in

the Loss Pool and the injection weighted average Day-Ahead MLC for the Loss Pool, multiplied

by the withdrawal quantity at that withdrawal Settlement Location.

(i) For any Settlement Location that is contained within more than one Settlement

Area Loss Pool, any injections or withdrawals associated with such Settlement Location shall be

allocated pro rata to the applicable Settlement Area Loss Pools based upon actual submitted real-

time meter values for the Meter Data Submittal Locations contained within each applicable

Settlement Area Loss Pool.

(ii) The total withdrawal quantity at a Settlement Location is calculated as the

positive value of the sum of all cleared Resource Offers, cleared Demand Bids, cleared Import

Interchange Transaction Offers, cleared Export Interchange Transaction Bids, cleared Virtual

Energy Bids and cleared Virtual Energy Offers at that Settlement Location.

(c) The injection weighted average Day-Ahead MLC for a Loss Pool is calculated

assuming that injection in a Loss Pool first serves withdrawals in the Loss Pool and then goes to

meet the withdrawal in Loss Pools that do not have sufficient injections to meet all withdrawals.

(d) A Day-Ahead Loss Pool Unitized Loss Rebate Factor is calculated for each Loss

Pool and is equal to that Loss Pool’s Day-Ahead Market Loss Pool loss rebate factor, as

calculated in (1)(b) above, divided by the sum of all Day-Ahead Market Loss Pool loss rebate

factors.

(2) The Day-Ahead over-collected losses distribution amount shall be calculated

hourly for each Asset Owner for each Loss Pool and withdrawal Settlement Location within each

Loss Pool as follows:

Asset Owner Settlement Location Day-Ahead Over-Collected Losses Distribution

Amount =

[(Day-Ahead Loss Pool Unitized Loss Rebate Factor) * (Day-Ahead Over-Collected

Losses Amount) * (Asset Owner Settlement Location Withdrawal in Loss Pool / Total Asset

Owner Settlement Location Withdrawals in Loss Pool] * (-1)


(a) The Day-Ahead Over-Collected Losses Amount in an hour is equal to the sum for

all Settlement Locations of an amount equal to [(Day-Ahead LMP – Day-Ahead MCC)] * Total

cleared Energy MW at each Settlement Location.

(b) The Asset Owner Settlement Location Withdrawal in Loss Pool is equal to the

positive value of sum of the Asset Owner’s cleared Demand BidsT, cleared Resource Offers,

cleared Interchange Transactions, Day-Ahead Market Bilateral Settlement Schedules and GFA

Carve Out Schedules at that Settlement Location in that Loss Pool.

(c) Day-Ahead Loss Pool Unitized Loss Rebate Factor is the factor calculated as

described in subsection (1)(d) above.

8.5.18 Day-Ahead GFA Carve Out Daily Amount

A Day-Ahead Market credit or charge for exclusion of transactions associated with GFA Carve

Outs from Marketplace settlement of congestion, losses and hedging instruments as described

under Section 8.2.2 of this Attachment AE, is calculated each day for every Asset Owner

modeled to represent a GFA Carve Out. This Day-Ahead GFA Carve Out Daily Amount is

calculated as follows:

Day-Ahead GFA Carve Out Daily Amount per Asset Owner = ((-1) * (Day-Ahead Asset Energy

Amount + Day-Ahead Non-Asset Energy Amount + Transmission Congestion Rights Funding

Amount + Transmission Congestion Rights Daily Uplift + Day-Ahead Over Collected Losses

Distribution Amount + Transmission Congestion Rights Auction Daily Amount + Auction

Revenue Rights Daily Amount + Auction Revenue Rights Daily Uplift Amount))

Where:

(1) Day-Ahead Asset Energy Amount is equal to the daily sum of the hourly values

calculated under Section 8.5.1(1) and 8.5.1(2) of this Attachment AE;

(2) Day-Ahead Non-Asset Energy Amount is equal to the daily sum of the hourly

values calculated under Section 8.5.1(3) of this Attachment AE;

(3) Transmission Congestion Rights Funding Amount is equal to the daily sum of the

hourly values calculated under Section 8.5.11 of this Attachment AE;

(4) Transmission Congestion Rights Daily Uplift Amount is equal to the daily value

calculated under Section 8.5.12 of this Attachment AE;

(5) Day-Ahead Over-Collected Losses Distribution Amount is equal to the daily sum

of the hourly values calculated under Section 8.56.16 of this Attachment AE;


(6) Transmission Congestion Rights Auction Daily Amount is equal to the daily

value calculated under Section 8.7.1 of this Attachment AE;

(7) Auction Revenue Rights Daily Amount is equal to the daily value calculated

under Section 8.7.2 of this Attachment AE; and

(8) Auction Revenue Rights Daily Uplift Amount is equal to the daily value

calculated under Section 8.7.3 of this Attachment AE.

8.6.16 Real-Time Over-Collected Losses Distribution Amount

The MLC of the Day-Ahead Market LMP and RTBM LMP creates an over collection of

funds (or under collection of funds as a result of the Real-Time deviation accounting) related to

the payment for losses (“RTBM “Over-Collected Losses”) that must be refunded (or charged) as

described below. Over-Collected Losses refunds associated with a GFA Carve Out are

calculated pursuant to this Section 8.6.16 and included as a credit to the GFA Carve Out costs

under Section 8.5.18 of this Attachment AE, and shall not be credited to a GFA Carve Out

Responsible Entity to the extent of load it serves under GFA Carve Out Schedule(s).

(1) A payment or charge for the portion of such RTBM Over-Collected Losses

allocable to each Asset Owner (“Real-Time Over-Collected Losses Distribution Amount”) shall

be calculated for each hour at each Settlement Location for which an Asset Owner has a net

RTBM Energy withdrawal within a Loss Pool, provided that such withdrawal does not include

Energy associated with cleared Day-Ahead Market Virtual Energy Bids and Virtual Energy

Offers, and such Loss Pool contributed positively to the RTBM Over-Collected Losses or were

charged for Real-Time pseudo-tie losses at the Settlement Location of the sink of the pseudo-tie

path for use of the SPP Transmission System according to the following calculations:

(a) Each Loss Pool’s contribution to the RTBM Over-Collected Losses is calculated

based on transactional activity in that Loss Pool where such transactional activity shall include:

actual Resource Energy, actual load consumption, RTBM Import Interchange Transactions and,

RTBM Export Interchange Transactions, cleared Day-Ahead Market Virtual Energy Bids and

cleared Day-Ahead Market Virtual Energy Offers.

(b) A “Real-Time Loss Pool loss rebate factor” is calculated hourly for each Loss

Pool. The Real-Time Loss Pool loss rebate factor is equal to the sum of the positive loss rebate

factors calculated in the RTBM at each withdrawal Settlement Location in the Loss Pool (the

“Real-Time Withdrawal Settlement Location loss rebate factor”). Real-Time Withdrawal


Settlement Location loss rebate factors are calculated hourly as the sum of i) the difference

between the Real-Time MLC at a withdrawal Settlement Location in the Loss Pool and the

injection weighted average Real-Time MLC for the Loss Pool, multiplied by the withdrawal

quantity at that withdrawal Settlement Location and ii) the sum of charges for Real-Time pseudo-

tie losses at the Settlement Location of the sink of the pseudo-tie path.

(i) For any Settlement Location that is contained within more than one Settlement

Area Loss Pool, any injections or withdrawals associated with such Settlement Location shall be

allocated pro rata to the applicable Settlement Area Loss Pools based upon actual submitted real-

time meter values for the Meter Data Submittal Locations contained within each applicable

Settlement Area Loss Pool.

(ii) The total withdrawal quantity at a Settlement Location is calculated as the

positive value of the sum of: (i1) the difference between actual Resource outputs and cleared

Day-Ahead Market Resource Offers; (ii2) the difference between actual load consumption and

cleared Day-Ahead Market Demand Bids; (iii3) the difference between RTBM scheduled Import

Interchange Transactions and Day-Ahead Market cleared Import Interchange Transaction Offers;

and (iv4) the difference between RTBM scheduled Export Interchange Transactions and Day-

Ahead Market cleared Export Interchange Transaction Bids; (v) cleared Day-Ahead Market

Virtual Energy Bids multiplied by (-1); and (vi) cleared Day-Ahead Market Virtual Energy

Offers multiplied by (-1),; at that Settlement Location.

(c) The injection weighted average Real-Time MLC for a Loss Pool is calculated

assuming that net RTBM injection in a Loss Pool first serves net RTBM withdrawals in the Loss

Pool and then goes to meet the net RTBM withdrawal in Loss Pools that do not have sufficient

Net RTBM injections to meet all net RTBM withdrawals.

(d) A Real-Time Loss Pool Unitized Loss Rebate Factor is calculated for each Loss

Pool and is equal to that Real-Time Loss Pool loss rebate factor, as calculated in subsection

(1)(b) above, divided by the sum of all Real-Time Loss Pool loss rebate factors.

(2) An Real-Time oOver-cCollected lLosses dDistribution aAmount shall be

calculated hourly for each Asset Owner for each Loss Pool and withdrawal Settlement Location

within each Loss Pool as follows:

Asset Owner Settlement Location Real-Time Over-Collected Losses Distribution

Amount = [(Real-Time Loss Pool Unitized Loss Rebate Factor) * (Real-Time Over-Collected

Losses Amount + Day-Ahead Over-Collected Losses Amount) * Asset Owner Settlement


Location Withdrawal in Loss Pool / Total Asset Owner Settlement Location Withdrawals in Loss

Pool] * (-1)

(a) The Real-Time Over-Collected Losses Amount in an hour is equal to the sum for

all Settlement Locations of [(Day-AheadReal-Time LMP – Day-AheadReal-Time

MCC)] * the difference between actual Energy and Day-Ahead Market cleared

Energy MW at each Settlement Location plus the sum of the losses for all

Resources of loads that are pseudo-tied out of the SPP Balancing Authority.

(b) The Day-Ahead Over-Collected Losses Amount in an hour is equal to the sum for

all Settlement Locations of an amount equal to [(Day-Ahead LMP – Day-Ahead

MCC)] * Total cleared Day-Ahead Market Energy MW at each Settlement

Location.

(cb) The Asset Owner Settlement Location Withdrawal in Loss Pool is equal to the

positive value of the sum for that Asset Owner at that Settlement Location in that

Loss Pool of: (i) the difference between actual Resource outputs and cleared Day-

Ahead Market Resource Offers; (ii) the difference between actual load

consumption and cleared Day-Ahead Market Demand Bids; (iii) the difference

between RTBM scheduled Import Interchange Transactions and Day-Ahead

Market cleared Import Interchange Transaction Offers; (iv) the difference

between RTBM scheduled Export Interchange Transactions and Day-Ahead

Market cleared Export Interchange Transaction Bids; and (v) RTBM Bilateral

Settlement Schedules, (vi) Day-Ahead Market Bilateral Settlement Schedules and

(vii) GFA Carve Out Schedules.

(dc) Real-Time Loss Pool Unitized Loss Rebate Factor is the factor calculated as

described in subsection (1)(d) above.



Congestion Hedging MWG October Update

October 21-22, 2014

Charles Cates Manager, Congestion Hedging

Agenda

• October Market Overview

• Funding Report via Protocols

• Limit Expansion via Protocols

2

2014 OCTOBER ALLOCATION RESULTS

3

Outage Overview

4

76

264

0

50

100

150

200

250

300

March April May June July Aug. Sept. October

# of

Out

ages

Annual Monthly

No Monthly June Process

Allocation Participation Trends

5

39

32

0

5

10

15

20

25

30

35

40

45

March April May July Aug. Sep. October

# of

Par

ticip

ants

Annual Monthly

Incremental Allocation Activity

6

0

500

1000

1500

2000

2500

5500 6500 7500 8500 9500 10500

Meg

awat

ts A

war

ded

Megawatts Attempted

July On August On September On October OnJuly Off August Off September Off October off

October

2014 OCTOBER AUCTION RESULTS

7

8,400

6,150

26,600 157,80

0

Self Converts Awarded

Self Converts not Awarded

Bids Awarded

Bids not Awarded

Round 1

October Incremental Activity

8

Round 2

6,200

29,420

127,000

Self Converts Awarded

Self Converts not Awarded

Bids Awarded

Bids not Awarded

Incremental Activity Trends

9

July

Aug.

Sep.

Oct. R1

Oct. R2

Time Period Bid Attempts

117 GW

180 GW

150 GW

123 GW

146 GW

Bid Award %

19%

20%

16%

15%

20%

Sell Attempts

8 GW

10 GW

8 GW

6 GW

16 GW

36%

34%

35%

36%

37%

4.7 GW

5.3 GW

3.8 GW

14.5 GW

6.2 GW

Sell Award % Self-Convert Attempts

100%

100%

58%

100%

100%

Self-Convert Award %

Incremental Auction Activity

10

0

5

10

15

20

25

30

35

0 50 100 150 200

GW

Aw

arde

d

GW Attempted

July On August On September On October OnJuly Off August Off September Off October Off

October

Incremental Bid Activity (Normalized to March)

11

0

1

2

3

4

5

6

7

March April May June July Aug. Sep. Oct.

# of Bids MW Awards

0

5

10

15

20

25

30

35

June July August September Fall Winter Spring

Mill

ions

($)

Yearly Positive Auction Revenue Trend

12

Aug. Annual

Aug. Monthly Current Year End Total

Nov. Monthly

Oct. Monthly

Underfunded DA September Constraints

13

4

3

2

1. Woodward – FPL Switch 138 (WDWFPLWDWTAT)

2. Renfrow Line (TEMP67_20472)

3. Gentleman – Red Willow (GENTLMREDWIL)

4. Temporary Flowgate (TMP123_20529)

1

14

September TCR Funding

82% Funded For Month of September

Total Uplift: $7.5 M Total DA Rent: $33.7 M Total TCR Payout: $41.2 M

0%

20%

40%

60%

80%

100%

120%

140%

160%

180%

200%

($4)

($3)

($2)

($1)

$0

$1

$2

$3

$4

% F

UN

DIN

G (D

aily

)

TCR

Fun

ding

M

illio

ns

% Funding (Daily) DA Congestion Rent Surplus/Shortfall

GENTLMREDWIL

IATSTRSTJHAW

SEMIANNUAL FUNDING REPORT

15

Funding Report

Market Protocols for SPP Integrated Marketplace – Section 5.2.3 - Simultaneous Feasibility

2.b - Every six (6) months for the first two (2) years after implementation of the Integrated Marketplace, SPP will analyze the net funding of TCRs through the Day-Ahead Market and report to the MWG. In the event the cumulative funding is at or below 90% or above 100%, MWG may approve an additional adjustment of all subsequent monthly auctions and the month of June in the annual auction of the normal and emergency ratings of all flowgates and monitored transmission system elements in (2) above.

16

ARR Funding (Actuals) Since Go-Live

17

$34.01

$0

$20

$40

$60

March April May June July August September

Mill

ions

ARR Fund

$3.60

$0

$2

$4

$6

March April May June July August September

Mill

ions

ARR Surplus

TCR Funding Since Go-Live

18

0%

20%

40%

60%

80%

100%

120%

140%

($4)

($3)

($2)

($1)

$0

$1

$2

TCR

Fun

ding

M

illio

ns

DA Congestion Rent Surplus/Shortfall % Funding (Daily)

End of 6 month window

A M

J

A

S

O

M

6 month funding 89.8%

7 month funding 88.4%

QUARTERLY LIMIT EXPANSION REPORT

19

Limit Expansion

Market Protocols for SPP Integrated Marketplace – Section 5.5.3 – Monthly TCR Auction Clearing and

Simultaneous Feasibility 2.a – […] SPP will increase the ratings of the applicable

transmission lines to ensure feasibility prior to the Round 1 auction. SPP will report back to the MWG on a quarterly basis regarding the number of times that that transmission line ratings had to be adjusted to ensure feasibility;

20

Expanded Limits

21

What •Element rating increase

When •Monthly Allocation •Monthly Auction

Why •Protocol 5.4.3 (Annual awards must remain feasible in new models for monthly processes) •Topology Change (typically new outages)

Number of Expanded Elements

22

*No Limit Expansion performed in June

0

50

100

150

200

250

300

Mar.ON

Mar.OFF

Apr.ON

Apr.OFF

MayON

MayOFF

JulyON

JulyOFF

Aug.ON

Aug.OFF

Sep.ON

Sep.OFF

Oct.ON

Oct.OFF

# of

Unique Elements Expanded Incremental Outages

Expanded Limit Details

Third Quarter

– 132 Total Limit Expansions

– Limits were expanded an average of 18% High %: 60.5% expansion of 115 kV line

– 92.6 MW Expansion Low %: 0.01% of 345 kV Transformer

– .076 MW Expansion

23

Congestion Hedging Transitional Allocation Overview

October 21-22, 2014

Charles Cates Manager, Congestion Hedging

Purpose

2

Allocation of NEW Transmission Facility Capacities Provide ARR Hedging Instruments for new members

– Accomplished in Single Round

– Same Products as Annual Allocation Excludes June

July, August, September, Fall, Winter and Spring

Conditions for Study

Transitional Allocation Study can be requested by entities – Bringing new transmission facilities under SPP’s Tariff and

into SPP’s Integrated Marketplace Non-transmission owning entities joining in conjunction may

participate in but not request the study

Participating entities must – Have existing firm transmission service that is:

New to SPP’s Integrated Marketplace

Sold across new facilities that were not included in the Annual TCR Auction

3

Qualifications for Entry

Entities must: – Inform SPP of plans to join Marketplace 18 months prior

to desired join date

– Have the ability to meet applicable registration deadlines

– Sync join date with first of month

– Must request a minimum of Winter and Spring periods

Otherwise: – No transitional allocation will be done, and

– Monthly process will be used

4

OTHER CONSIDERATIONS

5

Cost of Possible Options

Software change cost estimates for onboarding new entities for Congestion Hedging purposes: 1. Join using the standard monthly process

– No change needed (Free)

2. Single round allocation only (SPP presented) – $70 K - $90 K software/vendor

– Undetermined staff cost

3. Full annual style allocation and auction for all MPs – $225 K - $260 K software/vendor

– Undetermined staff cost

6

Risks

Options 2 & 3:

• Projected cost highly subject to change

• Numerous software and programmatic issues

• Many manual changes required – solution is a “hack” to existing process

All Options:

• Highly dependent on upstream processes being ready

• SPP still working to identify parallel flow impacts

7

Recommendation

• SPP Staff recommends that the MWG proceed with development of the MPRR language to support the inclusion of a transitional ARR allocation process

8

Outage Subgroup Proposal

October 21, 2014

Jared Greenwalt [email protected]

501.688.8314


Outage Subgroup Objective

• Gather concerns regarding:

– Outage coordination processes

– Related TCR processes

• Propose short/long-term solutions

• Concerns:

– Outage Submission Timing

– Duration Thresholds

– Consecutive Outages

– New Transmission Elements

2

Outage Submission Timing

• Problem: Planned outages are not submitted early enough to be included in the model

• Proposal: SPP will improve communication about deadlines

– Clearly mark deadline on TCR Calendar

– Email a reminder to TO of the model deadline each month

– Educate Transmission Operators on TCR process

• Proposal to MWG: Design outage submission requirements for Transmission and Generation Outages (Criteria)

3

Duration Thresholds

• Problem: Very short outages are modeled as an outage for the entire month

• Proposal: Outages less than 120 hours will not be modeled as an outage for the month

– Longer outages modeled for entire month

– Engineering judgment may override

4

Reducing outages in the model may increase underfunding

Consecutive Outages

• Problem: Each consecutive outage (e.g. parallel lines) is currently modeled as an outage for the entire month

• Proposal: Use engineering judgment to best represent the effect of the outages in the model for the month

– All situations are not the same

– Case by case basis

– Engineering judgment used by other RTOs

5

Reducing outages in the model may increase underfunding

New Transmission Elements

• Problem: Should new transmission elements be modeled before they are in service?

• Proposal: Continue modeling transmission elements that are in service only

– Lower priority than other outage issues

– High degree of risk and uncertainty of timing

6

Reducing Outages in the Model

• Modeling fewer outages likely increases underfunding

– More underfunding causes more uplift to MPs

• Removing outages from the model allows individual MPs to potentially attain more hedging rights for congestion

– Modeling one-day outages for the month likely removes hedging rights on that path for the whole month

– It may also reduce hedging capability on surrounding paths

7

More Hedges More Uplift Outages

Summary

• Clearly communicate model deadlines

– Educate TOps on outage coordination

• Outages < 120 hours will not be modeled

– Engineering judgment

• Use engineering judgment for congestion hedging modeling

• Begin drafting a design for outage submission requirements for Transmission and Generation Outages (Criteria)

8


MPRR No. 196 PRR

Title Ancillary Service SPP Manual Override on Regulation




Approve Reject


Defer Refer

Ranking High

Impact Analysis Required Yes, Estimated Cost: $51,131 Duration: 7 months No

Cost impacts and duration includes vendor and SPP Rough Order of Magnitude estimates equal to +/- 50%.


Section No.: 1,; 4.4.4.1.1; 4.5.9.9 Title: Glossary; URD Exemptions; Real-Time Out-Of-Merit Amount Protocol Version: 20.b



Revision Description The below language just adds another provision into the protocols and tariff language allowing Make Whole Payments to occur when regulation is manually moved between the Day Ahead Market Clearing and the Real Time Actual causing a Market Participant to be financially harmed.



Attachment AE Section 1.1 Definitions; Section 6.4.1.1 Uninstructed Resource Deviation Exemptions; 8.6.6 Real-Time Out-of-Merit Amount

No



No


MWG


Opposed: N/A

Abstained: N/A



Opposed: N/A

Abstained: N/A


Opposed: N/A

Abstained: N/A

RTWG Date of Vote: 8/28/2014 Vote: Unanimously Approved


MOPC Date of Vote: Vote:


Date 7/16/2014

Sponsor Name Amber Metzker E-mail Address [email protected] Company Xcel Energy/SPS Phone Number 303-571-6202

Comments Received

Comment Author Terry Gates – AEP Date 8/1/2014

Comment Description These comments add “Real-Time” to the definition of Manual Dispatch Instructions. By adding “Real-Time” to the definition, this lets the reader know that the Manual Dispatch Instruction happens in the Real-Time Market.



Comment Description MWG added the phrase, “after the Day-Ahead Market clears” to the definition of Manual Dispatch Instruction to let the reader know that Manual Dispatch Instructions happen after the Day-Ahead Market. Those instructions will then go through the OOME calculations.



Comment Description The changes in MPRR196 would allow a Resource to receive compensation when Regulation is manually deselected between the Day Ahead Market Clearing and the Real Time Actual causing a Market Participant to be financially harmed. These



comments add the flag that would trigger the calculation for the compensation.


Comments Received Comment Author Micha Bailey Date 10/17/2014

Comment Description

MPRR196 allows units that were cleared for Operating Reserves in the Day-Ahead Market to receive compensation when those units are manually deselected in Real-Time for the Operating Reserves. If MPRR196 gets implemented with the one deselect flag as proposed, then all or none of the products will go through the OOME calculation. These comments fix this issue by creating four more flags for Regulation-Up Service, Regulation-Down Service, Spinning Reserve and Supplemental Reserve. If Regulation-Up Service receives the flag for being manually deselected, then only Regulation-Up will go through the OOME calculations.



1. Glossary

Manual Dispatch Instruction

A dispatch instruction created outside of the normal RTBM SCED Dispatch Instruction solution to address a system reliability condition that could not be resolved by the RTBM SCED. As defined in Attachment AE of the Tariff.

4.4.4.1.1 URD Exemptions

A Resource will receive a URD exemption in a Dispatch Interval under the following situations:

(1) The Resource is deployed for Contingency Reserve as described under Section Error! Reference source not found. or is deployed for a Contingency Reserve test as described under Sections Error! Reference source not found. and Error! Reference source not found.;

(2) The Resource trips or is derated after receiving Dispatch Instructions;

(3) There is missing or bad Resource SCADA data in the Dispatch Interval;

(4) During a system Emergency if the URD is associated with actual Resource output above the Resource’s Setpoint Instruction in a shortage condition or if the URD is associated





with actual Resource output below the Resource’s Setpoint Instruction during an excess generation condition;

(5) If a Dispatch Instruction is issued to a Resource beyond the reported capabilities due to the application of a VRL;

(6) If the Resource is part of a Common Bus and the URD calculated at the Common Bus is less than the Operating Tolerance calculated at the Common Bus;

(7) A Resource will receive an Uninstructed Resource Deviation exemption to the extent a Market Participant can demonstrate the URD resulted from an event of force majeure or, in the case of a Variable Energy Resource, if the URD results from extremely high wind or other extreme weather-related conditions materially and directly impacting a Variable Energy Resource’s ability to provide Energy. For purposes of this subsection, the term force majeure shall have the meaning described under Section 10.1 of the SPP Tariff except that acts of Curtailment shall not qualify for exemption.

(8) The Resource is issued an OOME instruction for Energy.

In the event a Resource does not receive a URD exemption in a Dispatch Interval, the Market Participant may provide SPP with adequate documentation through the dispute process in order for the Market Participant to be eligible to avoid such Uninstructed Resource Deviation. SPP shall determine through the dispute process whether an exemption will be given. Adequate documentation may include but is not limited to an audio file documenting a call between the Market Participant and SPP.

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 Error! Reference source not found.(3)(b)(i) and/or otherwise receives a Manual Dispatch Instruction 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 Manual Dispatch Instructions 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 Error! Reference source not found.. The cost allocation of out-of-merit credits associated with Manual Dispatch Instructions 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 Error! Reference source not found.. Out-of-merit credits associated with Manual Dispatch Instructions issued directly by SPP to address a reliability issue other than a Local Reliability Issue will be recovered under Section Error! Reference source not found.. The amount will be calculated on a Dispatch Interval basis under the following conditions:

(a) If the Manual Dispatch Instruction is for Energy in the up direction and the Energy Offer Curve cost associated with the Out-Of-Merit-Energy (OOME) MW is greater than the RTBM LMP, the Asset Owner will receive a credit equal to the difference multiplied by the OOME 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 Manual Dispatch Instruction MW) and (ii) the Resource’s Desired Dispatch);

(b) If the Manual Dispatch Instruction is for Energy in the down direction, including a Resource de-commitment 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. 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 Manual Dispatch Instruction MW)); and/or

(c) If thea Manual Dispatch Instruction for Energy or Operating Reserve, or a Resource de-commitment instruction, 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 a Manual Dispatch Instruction 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.

IF RtOom5minFlg a, s, i = 1 OR ResDeCommit5minFlg a, s, i = 1 OR RtReprice5minFlg a, s, i = 1

THEN

#RtOom5minAmt a, s, i = ( RtOomeIncr5minAmt a, s, i + RtOomeDecr5minAmt a, s, i

+ RtOomor5minAmt a, s, i ) * (-1)

ELSE IF RtDeSelectOrFlg 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 ) -

Comment [MCB10]: MPRR206


Max (0, Min (Min (0, RtBillMtr5minQty a, s, i ) * (-1), RtAvgSetpoint5minQty a, s, i - RtOomeDesiredEn5minQty a, s, i )

* Max( 0, RtLmp5minPrc s, i ) ) / 12

(a.1) #RtOomeIncrEn5minAmt a, s, i =

∫y

x


Where:

X = 0 Y = Min ( Min ( 0, RtBillMtr5minQty a, s, i ) * (-1), RtAvgSetpoint5minQty a, s, i )

(a.2) #RtOomeDesiredEn5minAmt a, s, i =

∫y

x


Where:

X = 0 Y = RtOomeDesiredEn5minQtya, s, i

(b) RtOomeDecr5minAmt a, s, i =

Max (0, (-1) * Max (Min ( 0, RtBillMtr5minQty a, s, i ) * (-1), RtAvgSetpoint5minQty 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

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 RtDeSelectOrFlg 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 ) )

* RtDeSelectRegUpFlg a, s, i )

+ (( Max (0, ∑z

DaRegDnHrlyQty a, z, s, h - RtRegDn5minQty a, z, s, i )

* Max ( 0, RtRegDnMcp5minPrc z, i - DaRegDnMcpHrlyPrc z, h ) )

Field Code Changed

Field Code Changed

Field Code Changed


* RtDeSelectRegDnFlg a, s, i )

+ (( Max (0, ∑z

DaSpinHrlyQty a, z, s, h - RtSpin5minQty a, z, s, i )

* Max ( 0, RtSpinMcp5minPrc z, i - DaSpinMcpHrlyPrc z, h ) )

* RtDeSelectSpinFlg a, s, i )

+ (( Max (0, ∑z

DaSuppHrlyQty a, z, s, h - RtSupp5minQty a, z, s, i )

* Max ( 0, RtSuppMcp5minPrc z, i - DaSuppMcpHrlyPrc z, h ) )

* RtDeSelectSuppFlg a, s, i )] / 12

(1) 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

(2) 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


Field Code Changed

Field Code Changed


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



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 SPP Manual Dispatch Instruction.

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 SPP manual Dispatch Instruction 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 SPP manual Dispatch Instruction 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.

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 SPP issues a Manual Dispatch Instruction 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 7, otherwise, this flag is set equal to zero. Comment [MCB11]: MPRR 206


Variable

Unit

Settlement Interval

Definition

RtDeSelectOrFlg 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 a Manual Dispatch Instruction is sent 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 7.

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 Manual Dispatch Instruction as an output floor and the As-Dispatched Maximum Capacity Limit (Economic or Regulating, as applicable) in place prior to the issuance of the Manual Dispatch Instruction 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 Manual Dispatch Instruction MW or RtBillMtr5minQty a, s, i.


Variable

Unit

Settlement Interval

Definition

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 RtDispDesiredEn5minQty a, s, i.

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 Manual Dispatch Instruction 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.

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 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.

Comment [MPRR102.12]: MPRR102 awaiting Implementation. #ER13-1748



Variable

Unit

Settlement Interval

Definition


Real-Time Regulation-Up Service Quantity per AO per Settlement Location per Dispatch Interval in the RTBM– The value described under Section 4.5.9.4.


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.


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.


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.

RtDeSelectRegUpFlg 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 a Manual Dispatch Instruction 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.

RtDeSelectRegDnFlg 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 a Manual Dispatch Instruction 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.






Variable

Unit

Settlement Interval

Definition

RtDeSelectSpinFlg 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 a Manual Dispatch Instruction 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.

RtDeSelectSuppFlg 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 a Manual Dispatch Instruction 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.


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.


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.

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 SPP Manual Dispatch Instruction.




Variable

Unit

Settlement Interval

Definition

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 SPP Manual Dispatch Instruction.

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 SPP Manual Dispatch Instruction.


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 SPP Manual Dispatch Instruction.

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.



Attachment AE

1.1 Definitions

Manual Dispatch Instruction

A Dispatch Instruction and/or Operating Reserve procurement after the Day-Ahead Market clears that

originates from SPP outside of the normal Real-Time Balancing Market security constrained economic

dispatch solution to address a system reliability condition.

6.4.1.1 Uninstructed Resource Deviation Exemptions

A. A Resource will receive a URD exemption in a Dispatch Interval

under the following situations:

(1) The Resource is deployed for Contingency Reserve as described in Section 6.3.2

of this Attachment AE or is deployed for a Contingency Reserve test as described

under Sections 2.10.1 and 2.10.2 of this Attachment AE; or

(2) The Resource trips off-line or is derated after receiving Dispatch Instructions; or

(3) There is missing or bad Resource SCADA data in the Dispatch Interval; or

(4) If during Emergency Conditions the URD is due to a Resource output above the

Resource’s Setpoint Instruction in a shortage condition or the URD is due to a

Resource output below the Resource’s Setpoint Instruction during an excess

generation condition; or

(5) If a Dispatch Instruction is issued to a Resource beyond the reported capabilities

due to the application of a VRL; or

(6) If the Resource is part of a Common Bus and the URD calculated at the Common

Bus is less than the Operating Tolerance calculated at the Common Bus; or

(7) If the URD results from an event of force majeure or, in the case of a Variable

Energy Resource, if the URD results from extremely high wind or other extreme

weather-related conditions materially and directly impacting a Variable Energy

Resource’s ability to provide or reduce output of Energy. For purposes of this

subsection, the term force majeure shall have the meaning described under

Section 10.1 of this Tariff except that acts of Curtailment shall not qualify for

exemption. ; or


(8) If the Resource has been issued a Manual Dispatch Instruction for Energy.

B. In the event a Resource does not receive a URD exemption in a Dispatch Interval,

the Transmission Provider shall determine through the dispute process, in

accordance with the invoice dispute process as provided in Section 10.3 of this

Attachment AE, whether an exemption to an Uninstructed Resource Deviation

will be given. The Market Participant may provide the Transmission Provider

with adequate documentation in order for the Market Participant to be eligible to

avoid such Uninstructed Resource Deviation. Adequate documentation may

include but is not limited to an audio file documenting a call between the Market

Participant and the Transmission Provider. 8.6.6 Real-Time Out-of-Merit Amount

An RTBM OOME payment will be made to each Asset Owner with a Resource that

receives a Transmission Provider Manual Dispatch Instruction 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 a Manual Dispatch Instruction by a local

transmission operator that the Market Monitor determines were selected in a discriminatory

manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of this

Attachment AE, and such Resources were affiliated with the local transmission operator are not

eligible to receive a RTBM OOME payment. RTBM OOME payments made to Asset Owners

that received a Manual Dispatch Instruction 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 a Manual Dispatch Instruction 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 Manual Dispatch Instruction 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”) is greater than the RTBM LMP, the Asset Owner will receive a payment

for the difference multiplied by the OOME 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 Manual Dispatch Instruction. The OOME MW is

calculated as the positive difference between (i) the lesser of the actual Resource output

or the Resource’s Manual Dispatch Instruction MW and (ii) the Resource’s economic


operating point. The Resource’s economic operating point is calculated as described

under Section 8.6.5(4)(d);

(2) If the Manual Dispatch Instruction is for Energy in the down direction, including a

Resource de-commitment 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”). 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 Manual Dispatch Instruction.

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 Manual Dispatch Instruction MW;

(3) If athe Manual Dispatch Instruction for Energy or Operating Reserve, or a Resource de-

commitment instruction, 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 a Manual Dispatch

Instruction 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.



Protocols Revision Request

MPRR No. 214 PRR

Title Adequate Fuel Cost Recovery


Section No.: 4.4.2.3.5 (new); 4.5.9.8 Title: Ensuring Reliable Operations – Adequate Fuel Cost Recovery for market Participants (new); RUC Make-Whole-Payment Amount Protocol Version: 21.a

Impact Analysis Required Yes – If yes, estimated cost: No SPP Staff will complete this section.

Member Software Impact Yes No

Requested Resolution Normal Expedited Urgent Action




Reason for Revision

Dogwood Energy believes that it would be prudent to consider a framework for additional fuel cost recovery required as a result of commitment directives issued as a result of an SPP Alert. Pursuant to MWG’s direction, the comments previously submitted in response to MPRR 189 have been revised and resubmitted herein with input from SPP Staff on implementation of financial settlement.


This MPRR will allow Market Participants to recover additional fuel costs required as a result of commitment directives issued by SPP. The MP will file a dispute with SPP using the Request Management System. SPP will review the dispute and associated documents. If the dispute is granted, then SPP will allocate those revenues to the MP which include the additional fuel cost recovery via the RUC MWP charge type and run a re-settlement statement.


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

Attachment AE 6.2.2.4 Emergency Operations – Adequate Fuel Cost Recovery 8.5.9 Day-Ahead Make Whole Payment Amount 8.6.5 Reliability Unit Commitment Make Whole Payment Amount

No

Criteria Implications or Changes

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

No

Credit Implications

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

No

Attachment 17 - MPRR 214 Adequate Fuel Cost Recovery.docx Page 1 of 17

Date 9/8/2014

Sponsor Name Rob Janssen E-mail Address [email protected] Company Dogwood Energy Phone Number 443.542.5125


4.4.2.3.4 Ensuring Reliable Operations In the event of an emergency situation, SPP will follow the emergency procedures and communication guidelines as described in the Emergency Operating Plan (EOP). Market Participants must provide all necessary information and perform all necessary actions as described in the Emergency Operating Plan (EOP) on SPP.org.

4.4.2.3.5 Ensuring Reliable Operations-Adequate Fuel Cost Recovery for Market Participants

(1) When SPP issues an alert, as described in sections 6 and 9 of SPP’s Emergency Operations Plan (an “Alert”), Market Participants shall be eligible for reimbursement for any net financial loss arising from procurement of fuel in excess of the amount ultimately required to meet SPP’s dispatch instructions up to the amount of fuel required to meet the commitments made via SPP’s reliability commitment and dispatch processes. This includes, but is not limited to, circumstances in which SPP reduces the level and/or duration of its dispatch instruction or decommits the previously committed Resource. This provision shall not apply to circumstances out of SPP’s control, such as a Resource’s failure to perform due to a forced outage or other facility-specific event, other than a documented fuel supply or transportation restriction. In such circumstances, net financial losses associated with excess fuel purchases above the amount that the Market Participant’s Resource can consume during the period of the reliability commitment can be recovered from SPP.

(1)(2) In the event that fuel suppliers or transporters impose scheduling restrictions, such as uniform schedules over a twenty-four hour period, or scheduling during non-business days, that require the procurement of fuel in excess of the amount needed to meet SPP’s dispatch instructions or require procurement beyond the time period of the reliability commitment from SPP, the affected Market Participant shall notify SPP’s reliability desk as soon as reasonably practicable after an Alert is issued and such Market Participant receives a commitment from SPP via a reliability commitment process. Upon such notice from a Market Participant, SPP may either rescind or modify the reliability commitment to the Market Participant to be consistent with the scheduling restrictions. If SPP does not either rescind or modify the commitment in a timely manner to be consistent with the scheduling restrictions, then any “excess” fuel purchased by the Market Participant in order to meet the reliability commitment shall also be reimbursed by

Comment [JG1]: Proposed language from MPRR 189



SPP for adequate cost recovery purposes to the extent that such purchases are consistent with the scheduling restriction notice provided by the Market Participant. Market Participants shall provide evidence of any such asserted scheduling restrictions upon request from SPP if not previously reflected in their concurrent Resource Offer parameters.

(2)(3) The reimbursement by SPP for adequate cost recovery under this section shall reflect the Market Participant’s net financial loss, taking into account its commercially reasonable attempts to mitigate its losses by reselling excess fuel, and shall be limited to the amount by which its total fuel costs incurred during the relevant period exceed the actual recovery of fuel costs received in connection with sales of fuel, Energy and Ancillary Services, including but not limited to, make whole payments. Market Participants seeking such reimbursement shall document the reasons for the loss and their efforts to mitigate such loss. The implementation of this section shall not deprive a Market Participant of compensation from the market for its non-fuel costs and any margin included in its Resource Offers for periods of time during which the Market Participant’s Resource(s) were in operation. However, neither should the implementation of this section provide compensation to a Market Participant for non-fuel variable costs and margin, other than start costs, for periods of time during which the Market Participant’s Resource(s) did not operate. Reimbursement shall not apply to fuel that was purchased in advance of an SPP reliability commitment made after the issuance of an Alert.

(4) Reimbursements shall be paid to the affected Market Participants as described under Section 4.5.9.8(3)(a) and 4.5.9.8(3)(b) and recovered from Market Participants under Section 4.5.9.10.


(1) The RUC Make-Whole-Payment Amount is a credit or charge1 to a Resource Asset Owner and is calculated for each Resource with a RUC Commitment Period that was committed by SPP with an RTBM Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1. Asset Owners of Resources committed by a local transmission operator to address a Local Emergency Condition are eligible to receive a RUC make whole payment, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a RUC make whole payment. For such eligible local transmission operator commitments, a manual process is employed for the calculations and the make-whole-payments will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The RUC Make-Whole-Payment Amount is also calculated for combined cycle Resources with a RUC Commitment Period



during which the Resource is moved into a configuration that incurs additional costs over the Resource configuration used in the DA Market Commitment Period for the corresponding time period. A payment is made to the Resource Asset Owner when the sum of the Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy Offer Curve, and Transition State Offer costs and Operating Reserve Offer costs associated with actual MWh amounts for Energy and cleared RTBM Operating Reserve, and any additional eligible costs identified as described under Section 4.5.9.8(3)(b) is greater than the Energy and Operating Reserve RTBM revenues received for that Resource over the Resource’s RUC Make-Whole-Payment Eligibility Period. Recovery of such compensation shall be collected in accordance with Section 8.6.7 of Attachment AE.


(a) As shown in Exhibit 4-25, for Resources with a RUC Commitment Period that begins in one Operating Day and ends in the next Operating Day, two RUC Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last Dispatch Interval of the first Operating Day. The second period begins in the first Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated with the Resource’s RUC De-Commit Time.


(b) If the Resource is a combined cycle Resource committed in the DA Market and then, during an RTBM hour within the DA Market Commitment Period, the Resource is moved into a configuration that is different from the configuration used in the DA Market Commitment period and such configuration incurs a Transition State Offer cost and/or a No-Load Offer cost that is higher than the No-Load Offer cost associated with the configuration used in the DA Market, that RTBM hour will be considered the start of a


RUC Commitment

Period

Time






RUC Make-Whole-Payment Eligibility Period. The end of this RUC Make-Whole-Payment Eligibility Period will be defined by the RTBM hour when the configuration in that RTBM hour is the same configuration as the configuration used in the corresponding DA Market Commitment Period hour, the Resource’s De-Commit Time or the end of the Operating Day, whichever is less.


(a) If SPP cancels a start-up order prior to the start of the associated RUC Make-Whole-Payment Eligibility Period and the Resource is not a Synchronized Resource, the Asset Owner will receive reimbursement for a time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset Owners may request additional compensation through submittal of actual cost documentation to the SPP via the dispute process as described under Section 4.5.15. Such additional compensation request may include net financial losses, as documented by submittal of out-of-pocket fuel expenses and revenues incurred following SPP’s issuance of an Alert as described under Section 4.4.2.3.5. 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.

(b) If SPP modifies a RUC Commitment Period instruction issued following the issuance of an Alert as described under 4.4.2.3.5, the Resource was a Synchronized Resource and such modification causes an Asset Owner to incur net financial losses in the form of additional out-of-pocket fuel costs, that Asset Owner may request compensation through submittal of actual out-of-pocket fuel expense and revenue documentation as described under Section 4.4.2.3.5 via the dispute process as described in section 4.5.15. SPP will review the submitted documentation and confirm that the submitted information is sufficient to document actual out-of-pocket expenses and revenues and that all or a portion of such expenses are eligible for recovery. Any approved additional compensation will be included as an eligible cost for recovery.

(a)(c) In order to receive Start-Up Offer recovery within a RUC Make-Whole-Payment Eligibility Period, the Resource must be a Synchronized Resource for at least one Dispatch Interval in the RUC Make-Whole Payment Eligibility Period.

(b)(d) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the RUC Make-Whole Payment Eligibility Period, the Resource must be a Synchronized Resource in that Dispatch Interval.



(c)(e) There may be more than one RUC Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single RUC Make-Whole Payment Eligibility Period is contained within a single Operating Day.

(d)(f) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the following RUC Make-Whole Payment Eligibility Periods:

(i) Any RUC Make-Whole Payment Eligibility Period for which the RUC SCUC did not consider the Resource’s Start-Up Offer in the commitment decision except that RTBM Start-Up Offers associated with manual commitments as described under Sections 4.3.2.2(3)(c), 4.3.2.2(3)(d), 4.4.1.2(3)(c) and 4.4.1.2(3)(d) are eligible for recovery;



(e)(g) For each RUC Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time multiplied by 12 rounded down to the nearest whole interval or (2) 24 Hours multiplied by 12, and that portion of the Start-Up Offer is included as a cost in each interval of the RUC Make-Whole Payment Eligibility Period until the sum of these interval costs are equal to the RTBM Start-Up Offer or until the end of the RUC Make-Whole Payment Eligibility Period, whichever occurs first.

(f)(h) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the last RUC Make-Whole Payment Eligibility Period in the Operating Day, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the first RUC Make-Whole Payment Eligibility Period of the following Operating Day provided that the Resource has not been committed in the DA Market in any hour of the first RUC Make-Whole Payment Eligibility Period as described in (h) below. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $12,000. The RUC Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For RUC Make-Whole Payment calculation purposes, the RUC Commitment Period is split into two separate RUC Make-Whole Payment Eligibility Periods as described in (2).a above. The first RUC Make-Whole Payment Eligibility Period will include $100/interval of

Comment [MPRR190.5]: MPRR190 Awaiting FERC filing


Start-Up Offer costs ($12,000 / 120 intervals) in hour 23 and 24 intervals. The second RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs in hours 1 through 8 intervals.

(g)(i) If the Resource has been committed in the DA Market in a period adjacent to and following a RUC Make-Whole Payment Eligibility Period to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the Day-Ahead Make-Whole Payment Eligibility Period.

(h)(j) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at a Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, and such cost is not due to any independent action of the Market Participant. In such cases, the additional costs are equal to the difference between the average Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs associated with Contingency Reserve is limited to the time period defined as the Transition State Time submitted in the Resource Offer. Recovery of these costs associated with Regulation-Up and/or Regulation-Down is limited to all Dispatch Intervals within the transition hour.


...


ATTACHMENT AE

6.2.2.3 Congestion Management

The Transmission Provider shall use the following process to coordinate the operations of

the RTBM to manage congestion within the SPP Balancing Authority Area and between the SPP

Balancing Authority Area and external Balancing Authority Areas:

...



6.2.2.4 Emergency Operations – Adequate Fuel Cost Recovery

(1) When the Transmission Provider issues an emergency alert, consistent with NERC

emergency procedures and as further described in the Market Protocols (an “Alert”),

Market Participants shall be eligible for reimbursement for any net financial loss arising

from procurement of fuel in excess of the amount ultimately required to meet the

Transmission Provider’s dispatch instructions up to the amount of fuel required to meet

the commitments made via the Transmission Provider’s Reliability Unit Commitment

and dispatch processes. This reimbursement includes, but is not limited to, circumstances

in which the Transmission Provider reduces the level and/or duration of its dispatch

instruction or decommits the previously committed Resource. This provision shall not

apply to circumstances out of the Transmission Provider’s control, such as a Resource’s

failure to perform due to a forced outage or other facility-specific event, other than a

documented fuel supply or transportation restriction. In such circumstances, net financial

losses associated with excess fuel purchases above the amount that the Market

Participant’s Resource can consume during the period of the reliability commitment can

be recovered from SPP.

(2) In the event that fuel suppliers or transporters impose scheduling restrictions, such as

uniform schedules over a twenty-four hour period, or scheduling during non-business

days, that require the procurement of fuel in excess of the amount needed to meet the

Transmission Provider’s dispatch instructions or require procurement beyond the time

period of the reliability commitment from the Transmission Provider, the affected Market

Participant shall notify the Transmission Provider’s reliability desk as soon as reasonably

practicable after an Alert is issued and such Market Participant receives a commitment

from the Transmission Provider pursuant to the results of a reliability commitment

process. Upon such notice from a Market Participant, the Transmission Provider may

either rescind or modify the reliability commitment to the Market Participant to be

consistent with the scheduling restrictions. If the Transmission Provider does not either

rescind or modify the commitment in a timely manner to be consistent with the

scheduling restrictions, then any “excess” fuel purchased by the Market Participant in

order to meet the reliability commitment shall also be reimbursed by the Transmission

Provider for adequate cost recovery purposes to the extent that such purchases are

consistent with the scheduling restriction notice provided by the Market Participant.


Market Participants shall provide evidence of any such asserted scheduling restrictions

upon request from the Transmission Provider if not previously reflected in their

concurrent Resource Offer parameters.

(3) The reimbursement by the Transmission Provider for adequate cost recovery under this

section shall reflect the Market Participant’s net financial loss, taking into account its

commercially reasonable attempts to mitigate its losses by reselling excess fuel, and

shall be limited to the amount by which its total fuel costs incurred during the relevant

period exceed the actual recovery of fuel costs received in connection with sales of fuel,

Energy and Ancillary Services, including but not limited to, make whole

payments. Market Participants seeking such reimbursement shall document the reasons

for the loss and their efforts to mitigate such loss. The implementation of this section

shall not deprive a Market Participant of compensation from the market for its non-fuel

costs and any margin included in its Resource Offers for periods of time during which the

Market Participant’s Resource(s) were in operation. However, neither should the

implementation of this section provide compensation to a Market Participant for non-fuel

variable costs and margin, other than start-up costs, for periods of time during which the

Market Participant’s Resource(s) did not operate. Reimbursement shall not apply to fuel

that was purchased in advance of the Transmission Provider’s reliability commitment

made after the issuance of an Alert.

(4) Reimbursements shall be paid to the affected Market Participants as described under

Sections 8.6.5(3)(a) and 8.6.5(3)(b) of this Attachment AE and recovered from Market

Participants under Section 8.6.7 of this Attachment AE.












revenues.









Commitment Period.











periods:



except as described under Section 8.6.5(3)(ih);






























eligible Resource is equal the sum for all hours in the Day-Ahead Market Make








Offer Curve,

(iv) Regulation-Up cost associated with cleared Regulation-Up from

Regulation-Up Offers as described under Section 5.1.3 of this Attachment

AE, as calculated by multiplying Regulation-Up by the cost of such Attachment 17 - MPRR 214 Adequate Fuel Cost Recovery.docx Page 11 of 17

Regulation-Up as calculated from the Resource’s Day-Ahead Market

Regulation-Up Offer,

(v) Regulation-Down cost, associated with cleared Regulation-Down from

Regulation-Down Offers as described under Section 5.1.3 of this

Attachment AE, as calculated by multiplying Regulation-Down by the

cost of such Regulation-Down as calculated from the Resource’s Day-

Ahead Market Regulation-Down Offer,





Market Spinning Reserve Offer, and





Ahead Market Supplemental Reserve Offer








(ii) The sum of the revenues calculated under Section 8.5.2, 8.5.3 and 8.5.4

for that eligible Resource.






Condition are eligible to receive a RUC make whole payment, except that, if the Market Attachment 17 - MPRR 214 Adequate Fuel Cost Recovery.docx Page 12 of 17







costs associated with actual Energy and cleared RTBM Operating Reserve, and other

additional eligible costs as identified under Section 6.2.2.4 of this Attachment AE is

greater than the Energy and Operating Reserve RTBM revenues received over the

Resource’s RUC make whole payment eligibility period. Recovery of such

compensation shall be collected in accordance with Section 8.6.7 of this Attachment AE.










period. Resource production costs are calculated using the RTBM Offer prices in effect

at the time the commitment decision was made for start-up, no-load, and minimum-

energy; and the RTBM Offer prices in effect at the solving of a dispatch interval for the

Energy above minimum energy, Regulation-Up, Regulation-Down, Spinning Reserve,

and Supplemental Reserve.






documentation to the Transmission Provider via the dispute process as described

under Section 10.3 of this Attachment AE. Such additional compensation request

may include net financial losses, as documented by submittal of out-of-pocket Attachment 17 - MPRR 214 Adequate Fuel Cost Recovery.docx Page 13 of 17

fuel expenses and revenues incurred following SPP’s issuance of an Alert as

described as described under Section 6.2.2.4 of this Attachment AE. 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.

(b) If the Transmission Provider modifies a RUC Commitment Period instruction

issued following the issuance of an Alert as described under 6.2.2.4 of this

Attachment AE, the Resource was a Synchronized Resource and such

modification causes an Asset Owner to incur net financial losses in the form of

additional out-of-pocket fuel costs, that Asset Owner may request compensation

through submittal of actual out-of-pocket fuel expense and revenue

documentation as described under Section 6.2.2.4 of this Attachment AE via the

dispute process as described in section 10.3 of this Attachment AE. The


the submitted information is sufficient to document actual out-of-pocket expenses

and revenues and that all or a portion of such expenses are eligible for recovery.

Any approved additional compensation will be included as an eligible cost for

recovery.

(cb) In order to receive the full amount of Start-Up Offer recovery within a RUC make



period.

(dc) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in



(ed) There may be more than one RUC make whole payment eligibility period for a



(fe) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the











self-committed.

(fg) For each RUC make whole payment eligibility period within an Operating Day, a








(hg) To the extent that the full amount of the RTBM Start-Up Offer is not accounted






(h) below.

(ih) If the Resource has been committed in the Day-Ahead Market in a period adjacent





eligibility period.

(ij) If a Resource has operated outside of its Operating Tolerance in any Dispatch





(jk) If a Resource becomes non-dispatchable in any Dispatch Interval, any cost




(lk) If a Resource’s minimum operating limit is increased above the Resource’s














Disallowance)]


Resource is equal the sum for all Dispatch Intervals in the RUC Make Whole

Payment Eligibility Period of (i) Start-Up Offer used to make commitment

decision, (ii) No-Load Offer used to make commitment decision, (iii) Energy cost

at minimum output as calculated from the Energy Offer Curve used to make

commitment decision, (iv) Energy cost above minimum output as calculated from

the Energy Offer Curve that applied to the current Dispatch Interval, and (v)

Operating Reserve cost associated with cleared Real-Time Operating Reserve as

calculated from the Operating Reserve Offers except that Operating Reserve costs

associated with self-scheduled Operating Reserve where such self-schedules are

less than or equal to the amount of Operating Reserve cleared shall be set equal to

zero, and (vi) Real-Time Potential Regulation-Up Unused Mileage Make Whole

Payment as calculated under Section 8.6.19(2)(b) of this Attachment AE and (vii)


Real-Time Potential Regulation-Down Unused Mileage Make Whole Payment as

calculated under Section 8.6.20(2)(b) of this Attachment AE.






Resource (iii) Energy revenue associated with payments made under Section 8.6.6

of this Attachment AE (iv) amounts associated with settlement made under























PRR Comments

MPRR

No. 214 MPRR Title Adequate Fuel Cost Recovery

Date 9/11/2014

Submitter Name Debbie James E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3577

Comments The changes below delete the word dispatch and replace it with the word commitment along with other clarifying changes. A unit will need to have a commitment from SPP in order to receive the costs associated with the recovery. SPP is concerned that to confirm/verify the costs associated with Adequate Fuel Cost Recovery would be a manual process and SPP has no current process in place today. All changes are highlighted in yellow.

Revised Proposed Protocol Language Revision

4.4.2.3.4 Ensuring Reliable Operations In the event of an emergency situation, SPP will follow the emergency procedures and communication guidelines as described in the Emergency Operating Plan (EOP). Market Participants must provide all necessary information and perform all necessary actions as described in the Emergency Operating Plan (EOP) on SPP.org.

4.4.2.3.5 Ensuring Reliable Operations-Adequate Fuel Cost Recovery for Market Participants

(1) When SPP issues an alert, as described in sections 6 and 9 of SPP’s Emergency Operations Plan (an “Alert”), Market Participants shall be eligible for reimbursement for any net financial loss arising from procurement of fuel in excess of the amount ultimately required to meet SPP’s dispatch instructions up to the amount of fuel required to meet the commitments made via SPP’s reliability commitment and dispatch processes. This includes, but is not limited to, circumstances in which SPP reduces the level and/or duration of its dispatchcommitment instruction or decommits the previously committed Resource. This provision shall not apply to circumstances out of SPP’s control, such as a Resource’s failure to perform due to a forced outage or other facility-specific event, other than a documented fuel supply or transportation

Comment [JG1]: Proposed language from MPRR 189

Attachment 18 - MPRR 214 SPP Comments 9-11-2014_MWG.docx Page 1 of 17


restriction. In the case of documented fuel supply or transportation restrictionsuch circumstances, net financial losses associated with excess fuel purchases above the amount that the Market Participant’s Resource can consume during the period of the reliability commitment can be recovered from SPP.

(1)(2) In the event that fuel suppliers or transporters impose scheduling restrictions, such as uniform schedules over a twenty-four hour period, or scheduling during non-business days, that require the procurement of fuel in excess of the amount needed to meet SPP’s dispatchcommitment instructions or require procurement beyond the time period of the reliability commitment from SPP, the affected Market Participant shall notify SPP’s reliability desk as soon as reasonably practicable after an Alert is issued and such Market Participant receives a commitment from SPP via a reliability commitment process. Upon such notice from a Market Participant, SPP may either rescind or modify the reliability commitment to the Market Participant to be consistent with the scheduling restrictions. If SPP does not either rescind or modify the commitment in a timely manner to be consistent with the scheduling restrictions, then any “excess” fuel purchased by the Market Participant in order to meet the reliability commitment shall also be reimbursed by SPP for adequate cost recovery purposes to the extent that such purchases are consistent with the scheduling restriction notice provided by the Market Participant. Market Participants shall provide evidence of any such asserted scheduling restrictions upon request from SPP if not previously reflected in their concurrent Resource Offer parameters.

(2)(3) The reimbursement by SPP for adequate cost recovery under this section shall reflect the Market Participant’s net financial loss, taking into account its commercially reasonable attempts to mitigate its losses. by reselling excess fuel., and The reimbursement shall be limited to the amount by which its total fuel costs incurred during the relevant period exceed the actual recovery of fuel costs received in connection with sales of fuel, Energy, and Ancillary ServicesOperating Reserve, including but not limited to, and make whole payments. Market Participants seeking such reimbursement shall document the reasons for the loss and their efforts to mitigate such loss. The implementation of this section shall not deprive a Market Participant of compensation from the market for its non-fuel costs and any margin included in its Resource Offers for periods of time during which the Market Participant’s Resource(s) were in operation. However, neither should the implementation of this section provide compensation to a Market Participant for non-fuel variable costs and margin, other than start costs, for periods of time during which the Market Participant’s Resource(s) did not operate. Reimbursement shall not apply to fuel that was purchased in advance of an SPP reliability commitment made after the issuance of an Alert.

(4) Reimbursements shall be paid to the affected Market Participants as described under Section 4.5.9.8(3)(a) and 4.5.9.8(3)(b) and recovered from Market Participants under Section 4.5.9.10.



(1) The RUC Make-Whole-Payment Amount is a credit or charge1 to a Resource Asset Owner and is calculated for each Resource with a RUC Commitment Period that was committed by SPP with an RTBM Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1. Asset Owners of Resources committed by a local transmission operator to address a Local Emergency Condition are eligible to receive a RUC make whole payment, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a RUC make whole payment. For such eligible local transmission operator commitments, a manual process is employed for the calculations and the make-whole-payments will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The RUC Make-Whole-Payment Amount is also calculated for combined cycle Resources with a RUC Commitment Period during which the Resource is moved into a configuration that incurs additional costs over the Resource configuration used in the DA Market Commitment Period for the corresponding time period. A payment is made to the Resource Asset Owner when the sum of the Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy Offer Curve, and Transition State Offer costs and Operating Reserve Offer costs associated with actual MWh amounts for Energy and cleared RTBM Operating Reserve, and any additional eligible costs identified as described under Section 4.5.9.8(3)(b) is greater than the Energy and Operating Reserve RTBM revenues received for that Resource over the Resource’s RUC Make-Whole-Payment Eligibility Period. Recovery of such compensation shall be collected in accordance with Section 8.6.7 of Attachment AE.


(a) As shown in Exhibit 4-25, for Resources with a RUC Commitment Period that begins in one Operating Day and ends in the next Operating Day, two RUC Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last Dispatch Interval of the first Operating Day. The second period begins in the first Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated with the Resource’s RUC De-Commit Time.



Operating Day 1 Operating Day 2 Real-Time Make-Whole Payment Eligibility Period





(b) If the Resource is a combined cycle Resource committed in the DA Market and then, during an RTBM hour within the DA Market Commitment Period, the Resource is moved into a configuration that is different from the configuration used in the DA Market Commitment period and such configuration incurs a Transition State Offer cost and/or a No-Load Offer cost that is higher than the No-Load Offer cost associated with the configuration used in the DA Market, that RTBM hour will be considered the start of a RUC Make-Whole-Payment Eligibility Period. The end of this RUC Make-Whole-Payment Eligibility Period will be defined by the RTBM hour when the configuration in that RTBM hour is the same configuration as the configuration used in the corresponding DA Market Commitment Period hour, the Resource’s De-Commit Time or the end of the Operating Day, whichever is less.


(a) If SPP cancels a start-up order prior to the start of the associated RUC Make-Whole-Payment Eligibility Period and the Resource is not a Synchronized Resource, the Asset Owner will receive reimbursement for a time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset Owners may request additional compensation through submittal of actual cost documentation to the SPP via the dispute process as described under Section 4.5.15. Such additional compensation request may include net financial losses, as documented by submittal of out-of-pocket fuel expenses and revenues incurred following SPP’s issuance of an Alert as described under Section 4.4.2.3.5. 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.

(b) If SPP modifies a RUC Commitment Period instruction issued following the issuance of an Alert as described under 4.4.2.3.5, the Resource was a Synchronized Resource and

RUC Commitment

Period

Time



such modification causes an Asset Owner to incur net financial losses in the form of additional out-of-pocket fuel costs, that Asset Owner may request compensation through submittal of actual out-of-pocket fuel expense and revenue documentation as described under Section 4.4.2.3.5 via the dispute process as described in section 4.5.15. SPP will review the submitted documentation and confirm that the submitted information is sufficient to document actual out-of-pocket expenses and revenues and that all or a portion of such expenses are eligible for recovery. Any approved additional compensation will be included as an eligible cost for recovery.

(a)(c) In order to receive Start-Up Offer recovery within a RUC Make-Whole-Payment Eligibility Period, the Resource must be a Synchronized Resource for at least one Dispatch Interval in the RUC Make-Whole Payment Eligibility Period.

(b)(d) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the RUC Make-Whole Payment Eligibility Period, the Resource must be a Synchronized Resource in that Dispatch Interval.

(c)(e) There may be more than one RUC Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single RUC Make-Whole Payment Eligibility Period is contained within a single Operating Day.

(d)(f) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the following RUC Make-Whole Payment Eligibility Periods:

(i) Any RUC Make-Whole Payment Eligibility Period for which the RUC SCUC did not consider the Resource’s Start-Up Offer in the commitment decision except that RTBM Start-Up Offers associated with manual commitments as described under Sections 4.3.2.2(3)(c), 4.3.2.2(3)(d), 4.4.1.2(3)(c) and 4.4.1.2(3)(d) are eligible for recovery;



(e)(g) For each RUC Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time multiplied by 12 rounded down to the nearest whole interval or (2) 24 Hours multiplied by 12, and that portion of the Start-Up Offer is included as a cost in each interval of the RUC Make-Whole Payment Eligibility Period until the sum of these

Comment [MPRR190.5]: MPRR190 Awaiting FERC filing


interval costs are equal to the RTBM Start-Up Offer or until the end of the RUC Make-Whole Payment Eligibility Period, whichever occurs first.

(f)(h) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the last RUC Make-Whole Payment Eligibility Period in the Operating Day, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the first RUC Make-Whole Payment Eligibility Period of the following Operating Day provided that the Resource has not been committed in the DA Market in any hour of the first RUC Make-Whole Payment Eligibility Period as described in (h) below. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $12,000. The RUC Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For RUC Make-Whole Payment calculation purposes, the RUC Commitment Period is split into two separate RUC Make-Whole Payment Eligibility Periods as described in (2).a above. The first RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs ($12,000 / 120 intervals) in hour 23 and 24 intervals. The second RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs in hours 1 through 8 intervals.

(g)(i) If the Resource has been committed in the DA Market in a period adjacent to and following a RUC Make-Whole Payment Eligibility Period to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the Day-Ahead Make-Whole Payment Eligibility Period.

(h)(j) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at a Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, and such cost is not due to any independent action of the Market Participant. In such cases, the additional costs are equal to the difference between the average Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs associated with Contingency Reserve is limited to the time period defined as the Transition State Time submitted in the Resource Offer. Recovery of these costs associated with Regulation-Up and/or Regulation-Down is limited to all Dispatch Intervals within the transition hour.




...


ATTACHMENT AE

6.2.2.3 Congestion Management

The Transmission Provider shall use the following process to coordinate the operations of

the RTBM to manage congestion within the SPP Balancing Authority Area and between the SPP

Balancing Authority Area and external Balancing Authority Areas:

...

6.2.2.4 Emergency Operations – Adequate Fuel Cost Recovery

(1) When the Transmission Provider issues an emergency alert, consistent with NERC

emergency procedures and as further described in the Market Protocols (an “Alert”),

Market Participants shall be eligible for reimbursement for any net financial loss arising

from procurement of fuel in excess of the amount ultimately required to meet the

Transmission Provider’s dispatch instructions up to the amount of fuel required to meet

the commitments made via the Transmission Provider’s Reliability Unit Commitment

and dispatch processes. This reimbursement includes, but is not limited to, circumstances

in which the Transmission Provider reduces the level and/or duration of its

dispatchcommitment instruction or decommits the previously committed Resource. This

provision shall not apply to circumstances out of the Transmission Provider’s control,

such as a Resource’s failure to perform due to a forced outage or other facility-specific

event, other than a documented fuel supply or transportation restriction. In such

circumstances, net financial losses associated with excess fuel purchases above the

amount that the Market Participant’s Resource can consume during the period of the

reliability commitment can be recovered from SPP.

(2) In the event that fuel suppliers or transporters impose scheduling restrictions, such as

uniform schedules over a twenty-four hour period, or scheduling during non-business

days, that require the procurement of fuel in excess of the amount needed to meet the

Transmission Provider’s dispatchcommitment instructions or require procurement


beyond the time period of the reliability commitment from the Transmission Provider, the

affected Market Participant shall notify the Transmission Provider’s reliability desk as

soon as reasonably practicable after an Alert is issued and such Market Participant

receives a commitment from the Transmission Provider pursuant to the results of a

reliability commitment process. Upon such notice from a Market Participant, the

Transmission Provider may either rescind or modify the reliability commitment to the

Market Participant to be consistent with the scheduling restrictions. If the Transmission

Provider does not either rescind or modify the commitment in a timely manner to be

consistent with the scheduling restrictions, then any “excess” fuel purchased by the

Market Participant in order to meet the reliability commitment shall also be reimbursed

by the Transmission Provider for adequate cost recovery purposes to the extent that such

purchases are consistent with the scheduling restriction notice provided by the Market

Participant. Market Participants shall provide evidence of any such asserted scheduling

restrictions upon request from the Transmission Provider if not previously reflected in

their concurrent Resource Offer parameters.

(3) The reimbursement by the Transmission Provider for adequate cost recovery under this

section shall reflect the Market Participant’s net financial loss, taking into account its

commercially reasonable attempts to mitigate its losses by reselling excess fuel., and The

reimbursement shall be limited to the amount by which its total fuel costs incurred during

the relevant period exceed the actual recovery of fuel costs received in connection with

sales of fuel, Energy, Operating Reserve and Ancillary Services, including but not limited

to, and make whole payments. Market Participants seeking such reimbursement shall

document the reasons for the loss and their efforts to mitigate such loss. The

implementation of this section shall not deprive a Market Participant of compensation

from the market for its non-fuel costs and any margin included in its Resource Offers for

periods of time during which the Market Participant’s Resource(s) were in operation.

However, neither should the implementation of this section provide compensation to a

Market Participant for non-fuel variable costs and margin, other than start-up costs, for

periods of time during which the Market Participant’s Resource(s) did not operate.

Reimbursement shall not apply to fuel that was purchased in advance of the Transmission

Provider’s reliability commitment made after the issuance of an Alert.


(4) Reimbursements shall be paid to the affected Market Participants as described under

Sections 8.6.5(3)(a) and 8.6.5(3)(b) of this Attachment AE and recovered from Market

Participants under Section 8.6.7 of this Attachment AE.











revenues.









Commitment Period.












periods:



except as described under Section 8.6.5(3)(ih);






























eligible Resource is equal the sum for all hours in the Day-Ahead Market Make








Offer Curve,

(iv) Regulation-Up cost associated with cleared Regulation-Up from

Regulation-Up Offers as described under Section 5.1.3 of this Attachment

AE, as calculated by multiplying Regulation-Up by the cost of such

Regulation-Up as calculated from the Resource’s Day-Ahead Market

Regulation-Up Offer,

(v) Regulation-Down cost, associated with cleared Regulation-Down from

Regulation-Down Offers as described under Section 5.1.3 of this

Attachment AE, as calculated by multiplying Regulation-Down by the

cost of such Regulation-Down as calculated from the Resource’s Day-

Ahead Market Regulation-Down Offer,





Market Spinning Reserve Offer, and





Ahead Market Supplemental Reserve Offer









(ii) The sum of the revenues calculated under Section 8.5.2, 8.5.3 and 8.5.4

for that eligible Resource.






Condition are eligible to receive a RUC make whole payment, except that, if the Market







costs associated with actual Energy and cleared RTBM Operating Reserve, and other

additional eligible costs as identified under Section 6.2.2.4 of this Attachment AE is

greater than the Energy and Operating Reserve RTBM revenues received over the

Resource’s RUC make whole payment eligibility period. Recovery of such

compensation shall be collected in accordance with Section 8.6.7 of this Attachment AE.











period. Resource production costs are calculated using the RTBM Offer prices in effect

at the time the commitment decision was made for start-up, no-load, and minimum-

energy; and the RTBM Offer prices in effect at the solving of a dispatch interval for the

Energy above minimum energy, Regulation-Up, Regulation-Down, Spinning Reserve,

and Supplemental Reserve.






documentation to the Transmission Provider via the dispute process as described

under Section 10.3 of this Attachment AE. Such additional compensation request

may include net financial losses, as documented by submittal of out-of-pocket

fuel expenses and revenues incurred following SPP’s issuance of an Alert as

described as described under Section 6.2.2.4 of this Attachment AE. The


the submitted information is sufficient to document actual costs and that all or a

portion of the actual costs are eligible for recovery.

(b) If the Transmission Provider modifies a RUC Commitment Period instruction

issued following the issuance of an Alert as described under 6.2.2.4 of this

Attachment AE, the Resource was a Synchronized Resource and such

modification causes an Asset Owner to incur net financial losses in the form of

additional out-of-pocket fuel costs, that Asset Owner may request compensation

through submittal of actual out-of-pocket fuel expense and revenue

documentation as described under Section 6.2.2.4 of this Attachment AE via the

dispute process as described in section 10.3 of this Attachment AE. The


the submitted information is sufficient to document actual out-of-pocket expenses

and revenues and that all or a portion of such expenses are eligible for recovery.

Any approved additional compensation will be included as an eligible cost for

recovery.


(cb) In order to receive the full amount of Start-Up Offer recovery within a RUC make



period.

(dc) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in



(ed) There may be more than one RUC make whole payment eligibility period for a



(fe) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the










self-committed.

(fg) For each RUC make whole payment eligibility period within an Operating Day, a








(hg) To the extent that the full amount of the RTBM Start-Up Offer is not accounted







(h) below.

(ih) If the Resource has been committed in the Day-Ahead Market in a period adjacent





eligibility period.

(ij) If a Resource has operated outside of its Operating Tolerance in any Dispatch




(jk) If a Resource becomes non-dispatchable in any Dispatch Interval, any cost




(lk) If a Resource’s minimum operating limit is increased above the Resource’s














Disallowance)]




Payment Eligibility Period of (i) Start-Up Offer used to make commitment

decision, (ii) No-Load Offer used to make commitment decision, (iii) Energy cost

at minimum output as calculated from the Energy Offer Curve used to make

commitment decision, (iv) Energy cost above minimum output as calculated from

the Energy Offer Curve that applied to the current Dispatch Interval, and (v)

Operating Reserve cost associated with cleared Real-Time Operating Reserve as

calculated from the Operating Reserve Offers except that Operating Reserve costs

associated with self-scheduled Operating Reserve where such self-schedules are

less than or equal to the amount of Operating Reserve cleared shall be set equal to

zero, and (vi) Real-Time Potential Regulation-Up Unused Mileage Make Whole

Payment as calculated under Section 8.6.19(2)(b) of this Attachment AE and (vii)

Real-Time Potential Regulation-Down Unused Mileage Make Whole Payment as

calculated under Section 8.6.20(2)(b) of this Attachment AE.






Resource (iii) Energy revenue associated with payments made under Section 8.6.6

of this Attachment AE (iv) amounts associated with settlement made under
























Day-Ahead Must Offer Evaluation

October 21, 2014

Jared Greenwalt [email protected]

501.688.8314


Day-Ahead Must Offer Background

• “The primary purpose of this requirement is to address two issues.

– First, allow sufficient capacity to be cleared in the Day-Ahead Market so that commitments through the RUC are minimized. This is important so that the commitment decisions are made as early as possible so that sufficient resources are available to meet the reliability needs of the system.

– Second, produce an efficient outcome whose results converge with Real-Time Balancing Market results.” – MOPC Minutes & Attachments, April 12-13, 2011

2

Day-Ahead Must Offer Background

• “…[T]he must-offer requirement is intended to ensure that sufficient resources are available to serve load and provide operating reserves.” - 141 FERC ¶ 61,048

• “…[W]e will require SPP to monitor the effect that the limited day-ahead must-offer requirement proposed herein has on market outcomes and file with the Commission an assessment of market performance after the first year of operations.” - 141 FERC ¶ 61,048

3

Must Offer Statistics

4

0

100

200

300

400

500

600

Not Participating

Outage

Market, Self, Reliability

Total Resources Offered in Day-Ahead in 2014

Apr May Jun Jul Aug SepMar


5

0

10,000

20,000

30,000

40,000

50,000

60,000

Not Participating

Outage


Reported Load

Total MWs Offered in Day-Ahead in 2014



6

0

10,000

20,000

30,000

40,000

50,000

60,000


Obligation

Total Offered MWs vs. Obligation MWs for Penalty Hours

Penalty Hours


7

0%

50%

100%

150%

200%

250%

Market, Self, Reliability %

Obligation %

Total Offered MWs vs. Obligation MWs for Penalty Hours

Penalty Hours


8

$0

$50,000

$100,000

$150,000

$200,000

$250,000


DA Must Offer Penalties in 2014


• 28 shortages identified in initial screen (3/1 – 9/30)

• 13 final penalty-periods resulted

– 128 penalty-hours

• $361,544.77 total penalties

• Reasons initial screen may not result in a penalty:

– Commit Status = Not Participating, CROW = Outage

CROW overrides Commit Status

– Firm power purchases

9

Must Offer Issues

• Splitting load and generation into two AOs

– Frees MP from any must offer obligation

• Processing some data is manual and cumbersome

– Purchases/Sales and Non-registered JOU shares

• Requiring VERs to offer in the Day-Ahead Market

– Causes unorthodox offers in the Day-Ahead Market

• Designated AO submitting Commitment Status

– Share owners have no control over Commitment Status

• No incentive to report sales

10

Potential Changes to Limited Must Offer

• Implement “Affiliated Asset Owner” language

– Treat “Affiliated Asset Owners” as one AO

– Keep generation and load from being split into two AOs

• Tie Firm Power Purchases/Sales to BSS

– Make purchases/sales queryable

• Remove requirement for VERs to offer in Day-Ahead

11

October MWG – Marketplace Update • Regulation Performance

• Congestion Overview

• RUC Update

• Pricing

• Load Forecast accuracy

– Weather/Load forecast relationship

• Wind forecast accuracy

– September WF Overrides

• DAMKT Update

• Appendix

2

REGULATION PERFORMANCE Section 1

3

Notes 1. Resources that received deployment instructions for a minimum of 2,250 4-second

intervals were included in each Regulation product. This percentage roughly correlates to a 5 minute period in 1 day.

2. Response calculation is the same method used for mileage calculation.

3. % Score is: Regulation Response / Expected Regulation Setpoint.

4. Regulation Response calculation expects resources to simultaneously drive towards their expected energy and expected CR setpoints.

a. Expected setpoints are derived from RTGen setpoints that are ramped over the respective time periods i. 5 minutes for energy

ii. 10 minutes for CR

iii. 4 seconds for regulation

4

September 2014 Regulation Up Performance

5

0123456789

10111213141516171819202122232425262728293031

5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reso

urce

Cou

nt

Score (%)

September 2014 System-Wide Regulation Up Histogram

Reg Up

September 2014 Regulation Down Performance

6

0123456789

1011121314151617181920212223242526

5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100%

Reso

urce

Cou

nt

Score (%)

September 2014 System-Wide Regulation Down Histogram

Reg Down

CONGESTION OVERVIEW Section 2

7

DA vs RT Constraints

• Top 10 Congested Constraints in DA

8

Constraint # Intervals Binding or Breached Average Shadow Price OSGCANBUSDEA 387 46.97

WDWFPLWDWTAT 379 34.12

GENTLMREDWIL 351 15.99

TEMP67_20472 294 36.62

IATSTRSTJHAW 293 5.26

TEMP47_20353 207 3.79

SHAHAYKNOXFR 174 4.99

CBLUFFS_XF 172 1.21

TMP123_20529 164 10.92

TEMP37_20355 157 6.16

* Average Shadow Price includes every interval in the month

DA vs RT Constraints

• Top 10 Congested Constraints in RTBM

9

Constraint # Intervals Binding or Breached Average Shadow Price WDWFPLWDWTAT 3815 52.96

OSGCANBUSDEA 2441 50.21

TEMP67_20472 1864 51.36

IATSTRSTJHAW 1719 8.40

TEMP47_20353 917 5.67

TEMP37_20355 801 18.65

REDWILLMINGO 662 5.52

SILDIVNWSCIM 512 10.03

TMP123_20529 448 4.63

SHAHAYKNOXFR 319 8.40

* Average Shadow Price includes every interval in the month

RUC UPDATE Section 3

10

• The commitment breakdown for the month of September is shown to the right of total commitments made by DAMKT, RUC, SELF, and MANUAL.

• 66% of the commitments come from DAMKT, while 9% are considered manual.

Commitment Breakdown – September 2014

11

*SELF commits are post DAMKT

DAMKT, 66% MANUAL, 9%

RUC, 11%

SELF, 14%

Commitment Breakdown

DAMKT 1,136,278.80 MW

RUC 85,329.80 MW

MANUAL 99,436.20 MW

SELF 56,199.80 MW

• The 9% of manual commitments shown on the last slide amounts to 662 commitments.

• Of these 662, roughly 66 (10%), were actual new commitment startups not tied to the front or back end of a case.

• The majority of these commitments are backend extensions where units are being staggered offline for ramping purposes.

• In conclusion, less than 1% of the total commitments made in the month of September were actual new manual commitments

Manual Commitments – September 2014

12

Back End, 63%

Front End, 27%

New Commit, 10%

9,943.6 MW

26,847.8 MW

62,644.8 MW

SEPTEMBER PRICING Section 4

13

14 *=more info for anomalies included on next slide

-25

25

75

125

175

225

8/29/2014 00:00 9/3/2014 00:00 9/8/2014 00:00 9/13/2014 00:00 9/18/2014 00:00 9/23/2014 00:00 9/28/2014 00:00 10/3/2014 00:00

Hourly Avg LMP DA LMP RT LMP

15

RT LMP Outliers • Highest LMPs

– 9/5/2014 11:00 $221.16 High SMPs occurred due to REGUP shortage from IB 11:35 to IB 11:50 with the highest reaching

$742. We did not have enough upward ramp to clear all upward products. At the time of the highest SMP we were getting our next MW of REGUP from the demand curve causing the product scarcity price to be $600 rolling over into LMP.

– 9/9/2014 20:00 $145.24 We had three main constraints breaching throughout the day. REDWILLMINGO

OSGCANBUSDEA and IATSTRSTJHAW. These breached with high marginal values causing high SMPs off and on from IB 10:25 to IB 13:35. Similarly during this time period we were short on all upward products off and on also effecting the SMP for the day.

– 9/10/2014 12:00 and 14:00 $196.34 and $121.99 Day started with high wind (~5000MW) with breaching on a handful of constraints. The

breaches were minor in magnitude, but caused small price spikes.

– 9/24/2014 06:00 and 16:00 $145.19 and $147.68 High SMPs were observed during morning load pickup in particular IB 06:00. FGs

WDWFPLWDWTAT breached during these intervals. There was a CRD event at 16:01:29 and deployed 400 MW CR. PreRSS RTBM logic caused high SMPs for IB 16:20 – 16:30.

16

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

$45.00

1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep

LMP

DA LMP

RT LMP

Day Ahead 14-Mar 14-Apr 14-May 14-Jun 14-Jul 14-Aug 14-Sep DA MEC $ 39.75 $ 39.24 $ 37.13 $ 33.14 $ 32.71 $ 34.18 $ 30.15 DA MLC $ (0.15) $ (0.16) $ (0.13) $ (0.15) $ (0.08) $ (0.08) $ (0.17) DA MCC $ (0.15) $ (0.39) $ (0.26) $ (0.09) $ (0.10) $ (0.08) $ (0.18) DA LMP $ 39.45 $ 38.69 $ 36.74 $ 32.89 $ 32.52 $ 34.03 $ 29.81 Real Time 14-Mar 14-Apr 14-May 14-Jun 14-Jul 14-Aug 14-Sep RT MEC $ 40.39 $ 33.89 $ 37.91 $ 28.91 $ 31.21 $ 33.55 $ 30.17 RT MLC $ (0.18) $ (0.15) $ (0.11) $ (0.11) $ (0.07) $ (0.08) $ (0.17) RT MCC $ (0.33) $ (0.55) $ (0.31) $ (0.26) $ (0.08) $ (0.23) $ (0.40) RT LMP $ 39.88 $ 33.19 $ 37.49 $ 28.54 $ 31.07 $ 33.24 $ 29.61

LOAD FORECAST Section 5

17

18 * Load forecast data used from DA-RUC cases

0

1

2

3

4

5

6

7

0

5

10

15

20

25

30

35

409/

1

9/2

9/3

9/4

9/5

9/6

9/7

9/8

9/9

9/10

9/11

9/12

9/13

9/14

9/15

9/16

9/17

9/18

9/19

9/20

9/21

9/22

9/23

9/24

9/25

9/26

9/27

9/28

9/29

9/30

Erro

r Per

cent

GW

Mid Term Load Forecast

Daily AVG MTLF Daily AVG Actual Error Threshold % Forecast Error %

19

Over forecast by MOA

20

Over forecast by weather station

Load/Weather Forecasts • Snapshot is taken when DARUC runs

• We are “stuck” with the weather forecast for the day (in this case a bad forecast)

• Load forecast uses the last several days of load actuals to bias it’s results

• Weather front may come through quickly (one day)*

– Causes actual load usage to drop

– Load forecast still thinks the load should be similar to two/three/four days prior

• SPP currently working on Shift Engineer/EMS engineer alert

– Alert when temperatures and load change by a considerable amount

– Communication to control the actual load bias

21 * Information may be specific to this or similar cases

22 * Load forecast data used from DA-RUC cases

0

1

2

3

4

5

6

7

8

9

0

5

10

15

20

25

30

35

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

Erro

r Per

cent

age

GW

Hour

MTLF by Hour of the Day for September

AVG MTLF by Hour AVG Actual by Hour AVG Error % Error Threshold %

23

0

0.5

1

1.5

2

0

5

10

15

20

25

30

35

409/

1

9/2

9/3

9/4

9/5

9/6

9/7

9/8

9/9

9/10

9/11

9/12

9/13

9/14

9/15

9/16

9/17

9/18

9/19

9/20

9/21

9/22

9/23

9/24

9/25

9/26

9/27

9/28

9/29

9/30

Erro

r Per

cent

GW

Short Term Load Forecast

Daily AVG STLF Daily AVG Actual Error Threshold % Forecast Error %

WIND FORECAST Section 6

24

25 * Wind forecast data used from DA-RUC cases

0

5

10

15

20

25

30

35

40

0

1

2

3

4

5

6

9/1

9/2

9/3

9/4

9/5

9/6

9/7

9/8

9/9

9/10

9/11

9/12

9/13

9/14

9/15

9/16

9/17

9/18

9/19

9/20

9/21

9/22

9/23

9/24

9/25

9/26

9/27

9/28

9/29

9/30

Erro

r Per

cent

GW

Mid Term Wind Forecast

Daily AVG MTWF Daily AVG Actual MW Override Error Threshold % Forecast Error %

26 * Wind forecast data used from DA-RUC cases

0

2

4

6

8

10

12

14

16

18

20

22

24

26

28

30

0

0.5

1

1.5

2

2.5

3

3.5

4

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

Erro

r Per

cent

age

GW

Hour

MTWF by Hour of the Day for September

AVG MTWF by Hour AVG Actual by Hour AVG Error % Error Threshold %

27

0

5

10

15

0

1

2

3

4

5

6

9/1

9/2

9/3

9/4

9/5

9/6

9/7

9/8

9/9

9/10

9/11

9/12

9/13

9/14

9/15

9/16

9/17

9/18

9/19

9/20

9/21

9/22

9/23

9/24

9/25

9/26

9/27

9/28

9/29

9/30

Erro

r Per

cent

GW

Short Term Wind Forecast

Daily AVG STWF Daily AVG Actual Error Threshold % Forecast Error %

DAMKT UPDATE Section 7

28

DA Obligations vs RUC Obligations - September • DA (Cleared Load + NSI – Virtual Offers – Wind Offers)

• RUC (Load Forecast + NSI – Wind Forecast)

29

15000

17000

19000

21000

23000

25000

27000

29000

31000

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 - September

• All September days averaged into one “average” day

• Average 1208 MW short

• Peak 2149 MW short

• Differences – Virtuals

– Wind offered in DA vs Wind forecast in RUC

30

DA Obligations vs RUC Obligations - September

Average MW Short by Hour

31

0

500

1000

1500

2000

2500

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Average Shortfall

DA Fixed and PS Bid (with losses) vs MTLF

32

20000

22000

24000

26000

28000

30000

32000

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

DemandBid

September - Cleared Virtual offers and bids

33

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Cleared Virtual Offers(MW)

Cleared Virtual Bids(MW)

September Average Production Cost

34

• DAMKT: $10,010,060

• DA-RUC: $12,045,117

• RTBM: $12,210,309

APPENDIX

Section 8

35

36

Constraint Reason

OSGCANBUSDEA North South loading in SPS primarily due to economic dispatch (resources in SPS south are usually not economic), as well as high wind north of this constraint. This has historically been the #1 constraint in the market the past few years.

WDWFPLWDWTAT West east constraint shows up now since the new Hitchland – Woodward 345kV lines were energized in May, allowing all the wind power to flow from west Kansas and the Texas Panhandle into the Woodward area. This shows up when there is high westeast flow from Hitchland and/or high wind in the Woodward area. We have some control on this if the WFEC Mooreland generation is online (Inc unit).

GENTLMREDWIL High north south flow coming from the Gentleman units; this is a proxy flowgate for concerns on the 115kV system in the area. We can usually reconfigure to avoid having to bind this, but sometimes storms or high load in the area prevents us from using the reconfiguration.

IATSTRSTJHAW High output from Iatan units and high northsouth flow (usually from MISO wind and other external impacts). We usually have to call TLR on this flowgate to get relief from the external impacts.

TEMP67_20472 High northsouth flow and high load in the N Oklahoma area; this is a new transmission line that was energized in May. The nearby Flat Ridge 2 and Chisholm View wind farms hurt this flowgate as well. We have some control on this if the WFEC Mooreland generation is online (Inc unit).

TEMP72_20480 Transmission outages in the area; this line is between the cheap WR coal generation (JEC, LEC) and Kansas City load, so it was loaded up for much of the time during the outage(s).

TEMP47_20353 This is primarily an outlet issue for Montrose generation, created by an outage on the Montrose – Stillwell 161kV line. Easily controlled by redispatching Montrose generation down. This is a duplicate of TEMP65_20468 and the TEMP65_20468 flowgate has since been deleted.

37

IATSTRIATEAT High output from Iatan units; there are three outlets for Iatan generation (Iatan – Stranger 345kV, Iatan – Eastowne 345kV, and the Iatan 345/161kV transformer). This usually shows up when there is either low load or high generation on the Kansas City 161kV system, resulting in less flow from the Iatan units down onto the 345/161kV transformer.

TEMP65_20468 This is primarily an outlet issue for Montrose generation, created by an outage on the Montrose – Stillwell 161kV line. Easily controlled by redispatching Montrose generation down. This is a duplicate of TEMP47_20353 and this flowgate has since been deleted.

HARRANNICAMA North South loading in SPS primarily due to economic dispatch (resources in SPS south are usually not economic), this is pretty similar to OSGCANBUSDEA.

SHAHAYKNOXFR This is due to high load in NW Kansas/Hays area (occasionally aggravated by nearby transmission outages). Goodman generation is the only thing that can practically relieve the constraint. If they are online and have dispatchable room (not maxed out), we can bind the flowgate. Otherwise, we will violate it.

TEMP09_20424 Due to high load in the Wichita area (not really outage related); Gordon Evans generation helps this constraint out the most (Murray Gill is the other major Inc generations); this temp flowgate may be a result of how we commit WR’s generation, as I don’t think this showed up in past summers in the EIS.

SHAHAYPOSKNO High westeast, northsouth flows through mid-Kansas (usually high wind), sometimes coupled with high load in the NW Kansas/Hays area. Goodman generation can help fix this, but we usually will not commit them for this flowgate and we try to use reconfiguration (opening a breaker at Post Rock 230kV) so that the westeast through-flow is broken when the contingency occurs.

38

CBLUFFS_XF Due to congestion on the Council Bluffs transformer. Primarily caused by virtual offer submissions in the area..

TMP123_20529

High wind and westeast flow on the system, driven by local wind in the Woodward area as well as high westeast flows coming in from the Hitchland – Woodward 345kV double circuit lines. This constraint showed up during the Tatonga 345kV bus outage, and is pretty similar in loading to WDWFPLWDWTAT flowgate. The contingent element for WDWFPLWDWTAT was outaged as part of the Tatonga 345kV bus outage, so TMP123_20529 became one of the next highest loaded constraints. Controlled by increasing Mooreland generation and backing down any dispatchable (DVER or not) west of the flowgate (OKGE wind, SPS units, west Kansas wind…). This constraint did continue to show up some even after the Tatonga outage ended, with loading very close to WDWFPLWDWTAT loading. The limit used to control any of the Woodward – FPL flowgates is variable, due to a Special Protection System that trips the Centennial wind farm if there is an overload of the Woodward – FPL line (we adjust the effective limit in real-time to allow for this “relief”).

TEMP37_20355

High wind and high NWSE flow on the system. Some outages may aggravate this, but it shows up during system intact conditions anyway. This is controlled in RTBM by dispatching down NPPD and SECI conventional generation (as well as some DVERs if their price gets low enough).

REDWILLMINGO

Proxy flowgate used primarily to control voltage and thermal constraints on the SECI/MIDW system in NW Kansas. This basically just backs down the Gentleman units. In real-time, the effective limit is determined a lot by conversation between SPP and SECI operators, based on how they feel about current voltage and loading in the area.

SILDIVNWSCIM Loaded up due to several outages in Oklahoma City (transmission and generation), and only during high load times. This is controlled mostly by bringing on and dispatching up OKGE generation on the 138kV system in Oklahoma City (like Mustang, Smith, McClain…)

39

Actual v. Forecasted Temps

*Poor forecasts are circled

PRR Comments

MPRR

No. 213 MPRR Title Default VOM for Mitigated Offers

Date 9/19/2014

Submitter Name Micha Bailey on behalf of MOTF-2014 E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.2522

Comments MOTF-2014 added language to the VOM costs review by the Market Monitor annually. MOTF-2014 added that the review will be done by the Market Monitor and the Market Working Group. MOTF-2014 also added language to account for inflation and other rising costs of VOM. All changes are highlighted in yellow.

Revised Proposed Protocol Language Revision

8.2.2.3 Mitigation Measures for Energy Offer Curves

(1) Mitigated energy offer curves shall be submitted on a daily basis by the Market Participant in accordance withnot to exceed the costs described in the Mitigated Offer Development Guidelines. The mitigated energy offer curve may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource is not committed by the DA Market, the mitigated energy offer curve may be updated until the Day-Ahead RUC process begins. For Resources committed by the DA Market, the mitigated energy offer curve submitted as of 1100 hours on the day before the Operating Day will apply to the DA Market on the day before the Operating Day and the RTBM on the Operating day; for all other Resources the mitigated energy offer submitted at the time the Day-Ahead RUC process begins will apply to the Day-Ahead RUC process on the day before the Operating Day, and the Intra-Day RUC processes and the RTBM on the Operating Day.

(2) The Energy Offer Curve conduct thresholds are as follows: (a) For Resources with local market power as described in Section 8.2.2.7(3), the threshold is a 10%

increase above the Mitigated Energy Offer Curve;

(b) For Resources located in a Frequently Constrained Area and not subject to the threshold in Section 8.2.2.3(1), the threshold is a 17.5% increase above the Mitigated Energy Offer Curve.

Attachment 21 - MPRR 213 MOTF-2014 Comments 9-19-2014.docx Page 1 of 26


(c) For all other Resources the threshold is a 25% increase above the Mitigated Energy Offer Curve. (3) The Transmission Provider shall apply mitigation measures by replacing the Energy Offer Curve with the

Mitigated Energy Offer Curve if: (a) The Resource’s Energy Offer Curve exceeds the Mitigated Energy Offer Curve by the applicable

conduct threshold; and (b) The Resource has local market power as determined in Section 8.2.2.7; and (c) The Resource either:


An Energy Offer below $25/MWh will not be subject to mitigation measures for economic withholding. (4) The Mitigated Energy Offer Curve 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”), inter-temporal opportunity costs, and variable operations and maintenance costs (VOM), as not to exceed the costs detailed in the Mitigated Offer Development Guidelines. The formula for Mitigated Energy Offer Curves can be found in Appendix G Section 2.5.

(5) Opportunity costs may be reflected in the total fuel related costs and/or the VOM under the following circumstances:

(a) Externally imposed environmental run-hour restrictions; or (b) Physical equipment limitations on the number of starts or run-hours; or (c) Fuel supply limitations.




(c) For VOM costs, Market Participants shall submit VOM costs, not to exceed the default levels in the mitigated offer development guidelines,calculated in adherence with the Appendix G of the Market Protocols, without prior approval of the Market Monitor. Any VOM costs in excess of the default levels shall reflect short run marginal costs, exclusive of fixed costs. The default VOM costs shall be reviewed and updated by the Market Monitor and the Market Working Group (MWG) at least annually, as described in Section 2.4 of Appendix G of the Market Protocols. To the extent that the Market Monitor determines that SPP competitive market offers reflect lower VOM costs than the default VOM costs, the default VOM costs shall be reduced.reflecting short-run marginal costs, exclusive of fixed costs.

Further details associated with the development and , validation, and updating of these costs are included in SPP’s Mitigated Offer Development Guidelines.

Comment [CTM1]: Clean-up. Not related to VOM. This item is in the formula, but not in the description.

Comment [GA2]: Potentially to be explained in Appendix G. There is concern about just saying “lower” in this sentence.

Comment [CTM3]: This is a clean-up to match the Tariff.


(7) For Demand Response Resources with behind the meter generation the Mitigated Energy Offer Curve shall be developed in the same manner, described above, as any other generating Resource. For load response Demand Response Resources, the mitigated Energy Offer Curve shall reflect the quantifiable opportunity costs associated with the reduction, net of related offsetting increases in usage.

(8) 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 for Energy Offers for Non-Dispatchable Variable Energy Resources will occur.

(9) Intra-day changes to the Mitigated Energy Offer Curve are allowed under the following conditions: (a) The Market Participant incurs higher fuel procurement costs due to a request by the Transmission

Provider for a Resource to remain online past the scheduled commitment period by the DA Market or a RUC process; or

(b) A Resource must switch fuels due to unforeseen operating conditions; Intra-day changes to the Mitigation Energy Offer Curve must follow the Mitigated Offer Development Guidelines and will be validated by the Market Monitor.


8.2.2.4 Mitigation Measures for Start-Up and No-Load Offers

(1) A Mitigated Start-up Offer and a Mitigated No-load Offer shall be submitted daily by the Market Participant not to exceed the costs described in in accordance with the Mitigated Offer Development Guidelines. The Mitigated Start-up and No-load Offers may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource in not committed by the DA Market, the Mitigated Start-up and No-load Offers may be updated until the Day-Ahead RUC process begins. The Mitigated Start-up and No-load Offers submitted at the time the Day-Ahead RUC process begins will apply to the Day-Ahead RUC process on the day before the Operating Day and the Intra-Day RUC processes on the Operating Day.

(2) The Start-Up and No-Load Offer conduct thresholds are as follows:

(a) For Resources with local market power as described in Section 8.2.2.7(3), the threshold is a 10% increase above the mitigated offer for the applicable offer;

(b) For all other Resources the threshold is a 25% increase above the mitigated offer for the applicable offer.

(3) The Transmission Provider shall apply mitigation measures by replacing the Start-Up or No-Load Offer with the applicable Mitigated Start-up or mitigated No-load Offer if:

(a) The Resource’s Start-Up or No-Load Offer exceeds the mitigated offer by the applicable threshold; and

(b) The Resource has local market power as determined in Section 8.2.2.7; and


(c) The Resource fails the Market Impact Test as described in Section 8.2.2.9, or the Resource has local market power as described in Section 8.2.2.7(3).

(4) The mitigated Start-Up Offer shall represent the cost per start as determined from start fuel usage and the costs related to that fuel usage, electrical costs (station service), maintenance costs attributed to starts, and additional labor costs, if required above normal station manning levels. The formula for mitigated Start-Up Offers can be found in Appendix G Section 2.6:

(5) The mitigated Start-Up Offer for Demand Response resources shall be the cost to shut down or curtail load for a given period, which does not vary with output, or the start cost of a behind the meter generator.

(6) The mitigated Start-Up Offer for Variable Energy Resources shall be zero.

(7) The mitigated No-Load Offer shall be the hourly fixed cost required to create a monotonically increasing mitigated Energy Offer Curve. It shall be calculated according to either of two methods found in Appendix G Section 2.7 which are No-Load Fuel Approach and No-Load Cost Approach.

(8) The Mitigated No-Load Offer for behind the meter Demand Response resources shall adhere to the same definition above as a generating Resource. For load response Demand Response Resources, the Mitigated No-Load Offer shall not exceed the quantifiable ongoing hourly costs associated with manufacturing process changes associated with a reduction in load consumption.

(9) The mitigated No-Load Offer for Variable Energy Resources shall be zero.




(c) For VOM costs, Market Participants shall submit VOM costs not to exceed the default levels in the mitigated offer development guidelines, Appendix G of the Market Protocols, without prior approval of the Market Monitor. Any VOM costs in excess of the default levels shall reflect short run marginal costs, exclusive of fixed costs. The default VOM costs shall be reviewed and updated by the Market Monitor and the Market Working Group

Comment [MCB4]: Clean-up. This is an existing Tariff requirement that is missing from the Protocols section.


(MWG) at least annually, as described in Section 2.4 of Appendix G of the Market Protocols. To the extent that the Market Monitor determines that SPP competitive market offers reflect lower VOM costs than the default VOM costs, the default VOM costs shall be reduced.

(9)(11) The Market Participant shall submit documentation of the method for calculating mitigated Start-Up and mitigated No-Load Offers that is adequate to permit the MMU to verify submitted offers. Further details associated with the development, validation, and updating of these costs are included in SPP’s Mitigated Offer Development Guidelines.


8.2.2.5 Mitigation Measures for Operating Reserve Offers

(1) A mitigated offer for each Operating Reserve product shall be submitted daily by the Market Participant not to exceed the costs described in accordance with the Mitigated Offer Development Guidelines. The mitigated operating reserve offers may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource is not committed by the DA Market, the mitigated operating reserve offers may be updated until the Day-Ahead RUC process begins. For Resources committed by the DA Market, the mitigated operating reserve offers submitted as of 1100 hours on the day before the Operating Day will apply to the DA Market on the day before the Operating Day and the RTBM on the Operating Day; for all other Resources, the mitigated operating reserve offers submitted at the time the Day-Ahead RUC process begins will apply to the RTBM on the Operating Day.

(2) The offer conduct thresholds for each of the Operating Reserve products are as follows: (a) For Resources with local market power as described in Section 8.2.2.7(3), the threshold is a 10%

increase above the mitigated offer for the applicable Operating Reserve Offer; (b) For all other Resources the threshold is a 25% increase above the mitigated offer for the

applicable Operating Reserve Offer. (3) Any Operating Reserve Offer exceeding the applicable threshold, except offers below $10/MW, will be

deemed excessive. (4) The Transmission Provider shall apply mitigation measures by replacing the relevant Operating Reserve

Offer with the applicable mitigated operating reserve offer if: (a) The Resource’s Operating Reserve Offer exceeds the mitigated offer by the applicable conduct

threshold and; (b) The Resource has local market power as determined in Section 8.2.2.7; and (c) The Resource either:


(5) The mitigated Spinning Reserve Offer shall be equal to zero for Resources other than CTs and Hydro Resource with synchronous condenser capability. No known incremental costs are incurred for providing Spinning Reserves from other resource types. Mitigated Spinning Reserve

Comment [CTM5]: Clean-up to match the Tariff.


Offers for CTs and Hydro Resources with synchronous condenser capability are calculated as described in Appendix G, Sections 6 and 7.

(6) The mitigated Supplemental Reserve Offer shall not exceed any fuel related costs and labor costs necessary for the unit to be prepared for deployment. The formula for mitigated Supplemental Reserve Offer can be found in Appendix G Section 2.9.

(7) The mitigated Regulation-Up Offer and Regulation-Down Offer shall not exceed the sum of the cost increase due to:

(a) The heat rate increase during non-steady state operation;

(b) The cost increase in variable operations and maintenance costs due to non-steady state operation; and

(c) Uncompensated costs

The formula for mitigated Regulation-Up and Regulation-Down Offers can be found in Appendix G Section 2.10

(8) Further details associated with the development of the exact costs specified in the formulas above are included in Appendix G.

(9) The Market Participant may include in the calculation of its mitigated Operating Reserve Offer an amount reflecting the Resource-specific opportunity costs if the Market Participant is able to demonstrate to the satisfaction of the SPP Market Monitoring Unit that such costs are legitimate and verifiable and not otherwise included in market outcomes. To the extent such costs include run-time restrictions, such run-time restrictions shall be updated at least weekly with more frequent updating to occur the fewer hours that remain available. The formulas and instructions in the price forecast model for any such opportunity costs shall be determined by the SPP Market Monitoring Unit and published in Appendix G as part of the Mitigated Offer Development Guidelines, updated, as needed, by the SPP Market Monitoring Unit. Opportunity costs for mitigated Operating Reserve Offers shall not include Energy and Operating Reserve Markets revenues associated with forgone Energy or other types of Operating Reserve production to the extent that such costs are included in market outcomes

(10) 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 Operating Reserve Offers and shall include, among other data, the following information:




(c) For VOM costs, Market Participants shall submit VOM costs, not to exceed the default levels in the mitigated offer development guidelines, Appendix G of the Market Protocols, without prior approval of the Market Monitor. Any VOM costs in excess of the default levels shall reflect short run marginal costs, exclusive of fixed costs. The default VOM costs shall be reviewed and updated by the Market Monitor and the Market Working Group (MWG) at least annually, as described in Section 2.4 of Appendix G of the Market Protocols. To the extent that the Market Monitor determines that SPP competitive market offers reflect lower VOM costs than the default VOM costs, the default VOM costs shall be reduced. calculated in adherence with the Appendix G of the Market Protocols, reflecting short-run marginal costs, exclusive of fixed costs.


Appendix G 2.4 Total Variable Operation and Maintenance Cost

Total Variable Operation and Maintenance (VOM) costs are the incremental parts and labor expenses of maintaining equipment and facilities in satisfactory operating condition. A resource should reflect its short-run incremental VOM costs by using the most current data availablenot exceed the default VOM costs below without prior approval of the Market Monitoring Unit through the Mitigated Offer Methodology Approval Process. This could include the previous maintenance cycle period cost or actual short-run incremental cost where available.

Table XX. Default VOM Costs

Resource Type Energy Offer Curve VOM ($/MWh)

Start-up VOM ($/MW)

No Load VOM ($/mmBtu)

Wind $0.00 $0.00 $0.00

Solar $0.00 $0.00 $0.00

Hydro $4.00 $0.00 $0.00

Nuclear $6.50 $0.00 $0.65

Comment [GA6]: Need further definition of what “incremental” includes.


Coal (less than 100 MW capacity)

$6.00 $10.50 $0.70

Coal (more than 100 MW capacity)

$3.00 $6.00 $0.60

Gas Combined Cycle $3.00 $15.00 $1.00

Gas Combustion Turbine (Aero-Derivative)

$6.00 $5.00 $1.10

Gas Combustion Turbine (Industrial Frame)

$4.00 $15.00 $1.10

Gas Steam $12.00 $5.00 $2.00

Oil $20.00 $15.00 $2.50

𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 ($) =

��𝐴𝑛𝑛𝑢𝑎𝑙 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($)𝑐𝑢𝑟𝑟𝑒𝑛𝑡 𝑦𝑒𝑎𝑟 ∗𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑛𝑒𝑥𝑡 𝑦𝑒𝑎𝑟

𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑐𝑢𝑟𝑟𝑒𝑛𝑡 𝑦𝑒𝑎𝑟�

+ �𝐴𝑛𝑛𝑢𝑎𝑙 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($)𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟 ∗𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑛𝑒𝑥𝑡 𝑦𝑒𝑎𝑟

𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟�

+ �𝐴𝑛𝑛𝑢𝑎𝑙 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($)𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟−1 ∗𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑛𝑒𝑥𝑡 𝑦𝑒𝑎𝑟

𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟−1� + ⋯

+ �𝐴𝑛𝑛𝑢𝑎𝑙 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($)𝑐𝑢𝑟𝑟𝑒𝑛𝑡 𝑦𝑒𝑎𝑟−𝑚𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑝𝑒𝑟𝑖𝑜𝑑+1

∗𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑛𝑒𝑥𝑡 𝑦𝑒𝑎𝑟

𝐸𝑠𝑐𝑎𝑙𝑎𝑡𝑖𝑜𝑛 𝐼𝑛𝑑𝑒𝑥𝑙𝑎𝑠𝑡 𝑦𝑒𝑎𝑟−𝑚𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑝𝑒𝑟𝑖𝑜𝑑 𝑦𝑒𝑎𝑟𝑠+1��

The SPP MMU will review the development of the total maintenance costs for all resources pursuant to the Mitigated Offer Methodology Approval Process.

The total VOM cost as calculated above is based on available maintenance expense history for the defined Maintenance Period (See Section 2.4.2) regardless of Market Participantship. Only expenses incurred as a result of short-run incremental electric production (short-run marginal costs) qualify for inclusion.


2.4.1 Escalation Index

Escalation Index is the annual escalation index as derived from the July 1 Handy - Whitman Index for the SPP region, “construction cost electrical plant”. Otherwise, the Bureau of Labor Statistics Producer Price Index Series ID PCU3331203331208, Construction Machinery Manufacturing, Other Construction Machinery and Equipment shall be used for the Escalation Index as shown below.

Bureau of Labor Statistics Producer Price Index

2004: Index 104.7 – Escalation Factor 1.314




2008: Index 125.6 - Escalation Factor 1. 096




2012: Index 137.6(est) - Escalation Factor 1.000

2.4.2 Maintenance Period

The period of years between major overhauls or such other period as used in the calculation of total VOM under Section 2.4, not to exceed 10 years.

If a resource experiences a significant configuration change, the resource may submit to the SPP MMU its changed VOM cost methodology.

Examples of a significant resource configuration change may include but are not limited to:

• Flue Gas Desulfurization (FGD or scrubber)

• Activated Carbon Injection (ACI)

• Selective Catalytic NOX Reduction (SCR)

• Selective Non-Catalytic NOX Reduction (SNCR)

• Low-NOX burners

• Bag House addition

• Long-term Fuel change (greater than 10 years)


• Water injection for NOX control

• Gas Turbine Inlet Air Cooling

• Dry Sorbent Injection (DSI)

2.4.3 Average VOM Cost

Average VOM Cost is the average VOM cost $/mmBtu, $/MWh or $/hour. This is defined as allocated VOM dollars in the historical Maintenance Period divided by total MWhs, total fuel or total on-line hours associated with the historical Maintenance Period, depending on VOM type.

𝐸𝑛𝑒𝑟𝑔𝑦 𝑂𝑓𝑓𝑒𝑟 𝐶𝑢𝑟𝑣𝑒 (𝐸𝑂𝐶) 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($ 𝑀𝑊ℎ⁄ )1

=𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝐸𝑂𝐶 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4

𝑇𝑜𝑡𝑎𝑙 𝑀𝑤ℎ𝑠 𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑

𝑇𝐹𝑅𝐶 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($ 𝑚𝑚𝐵𝑡𝑢⁄ )2

=𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑇𝐹𝑅𝐶 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4

𝑇𝑜𝑡𝑎𝑙 𝐹𝑢𝑒𝑙 (𝑚𝑚𝐵𝑡𝑢)𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑

𝑁𝑜𝑙𝑜𝑎𝑑 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($ 𝑚𝑚𝐵𝑡𝑢⁄ )3

=𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑁𝑜𝑙𝑜𝑎𝑑 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4

𝑇𝑜𝑡𝑎𝑙 𝐹𝑢𝑒𝑙 (𝑚𝑚𝐵𝑡𝑢)𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑

𝑁𝑜𝑙𝑜𝑎𝑑 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($ 𝐻𝑜𝑢𝑟⁄ )4

=𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑁𝑜𝑙𝑜𝑎𝑑 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4

𝑇𝑜𝑡𝑎𝑙 𝑜𝑛 − 𝑙𝑖𝑛𝑒 ℎ𝑜𝑢𝑟𝑠 𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑

𝑆𝑡𝑎𝑟𝑡𝑢𝑝 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($ 𝑆𝑡𝑎𝑟𝑡⁄ ) 5

=𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑆𝑡𝑎𝑟𝑡𝑢𝑝 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4

𝑇𝑜𝑡𝑎𝑙 𝑆𝑡𝑎𝑟𝑡𝑠 𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑

𝑆𝑡𝑎𝑟𝑡𝑢𝑝 𝑉𝑂𝑀 𝐶𝑜𝑠𝑡($ 𝑆𝑡𝑎𝑟𝑡⁄ ) 6

=𝐴𝑙𝑙𝑜𝑐𝑎𝑡𝑒𝑑 𝑆𝑡𝑎𝑟𝑡𝑢𝑝 𝑝𝑜𝑟𝑡𝑖𝑜𝑛 𝑜𝑓 𝑇𝑜𝑡𝑎𝑙 𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 𝑓𝑟𝑜𝑚 𝑆𝑒𝑐𝑡𝑖𝑜𝑛 2.4

𝑇𝑜𝑡𝑎𝑙 𝑆𝑡𝑎𝑟𝑡𝑠 𝑖𝑛 𝑀𝑎𝑖𝑛𝑡𝑒𝑛𝑎𝑛𝑐𝑒 𝑃𝑒𝑟𝑖𝑜𝑑

The Market Participant should review and update The the VOM adders costs should be reviewed and updated at least once every twelve months or once in the maintenance cycle, whichever is shorter. The

1 See Section 2.5 and Section 2.10.1. 2 See Section 2.3 3 See Section 2.7 4 See Section 2.7 5 See Section 2.6 6 See Section 2.10


MMU will review and update the default VOM costs at least once every twelve months. The default VOM costs will be adjusted with inflation, as determined by the Handy-Whitman Index. The review will also consider any other relevant rising costs that have resulted in higher VOM costs for the resources in the SPP footprint. The MMU’s review shall compare the default VOM costs to the implied VOM costs in SPP Day Ahead Market and Real-Time Balancing Market offers during competitive market intervals. To the extent that the MMU determines that the default VOM costs are over-stated relative to the competitive offers, the default VOM costs shall be lowered.

If a Market Participant feels that a resource modification or required change in operating procedures will affect the resource's VOM adderscosts, the revised VOM adders costs must be submitted to the SPP MMU for review and approval pursuant to the Mitigated Offer Methodology Approval Process.

3.6 VOM Cost

Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types including nuclear units.

Nuclear VOM Cost - The historical dollars per unit of fuel (or heat) as derived from FERC Accounts 530 and 531 for nuclear steam units.

3.6.1 Configuration Addition VOM Adder

For units undergoing a significant system or unit Configuration Addition the use of an additional “Configuration Addition VOM Adder” may be included in the determination of the total maintenance adder. It is not intended to be used for upgrades to existing equipment.

Examples of significant system or unit Configuration Additions may include but are not limited to:

• Conversion from open loop to closed loop circulation water systems

The specific system or unit configuration system change must be reviewed by the MMU for evaluation pursuant to the Mitigated Offer Methodology Approval Process prior to approving the use of a Configuration Addition Maintenance adder.

3.6.2 Calculation of the Configuration Addition VOM Adder:

The Configuration Addition Maintenance adder (“CAMA”) is to be calculated in the same manner as the VOM cost adder described in this section with the exception that the Configuration Addition VOM total maintenance dollars are only the incremental additional costs incurred because of the system or unit configuration change.

As with the current maintenance adder calculation, the adder for year (Y) uses the actual costs beginning with year (Y-1). Therefore, the first year of actual incremental additional expenses will be captured by the CAMA in the second year.


Following the initial year of use of the CAMA, each additional year’s Configuration Addition VOM cost will be incorporated into the Configuration Addition Maintenance adder until the end of the historical maintenance cost period selected for the unit.

To calculate the Configuration Addition VOM Adder, calculate the solely incremental VOM Cost for the Configuration Change. Please note these expenses are purely incremental.

3.6.3 Reductions in Total VOM Costs:

While it is expected that the Configuration Addition VOM adder will most often be used to cover step increases in VOM costs, it is also to be used to capture step decreases in VOM costs resulting from a significant system or unit configuration change that results in a significant reduction in VOM costs. Any equipment that falls into disuse or is retired because of the configuration change must have its VOM expenses removed from the historical record used to develop the VOM adder. An example of a significant system or unit configuration change that may result in a step decrease in qualified VOM costs includes, but is not limited to, conversion from open loop to closed loop circulation water systems.

4.6 VOM Cost

Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following information only pertains to fossil steam units.

Fossil Steam - VOM Cost - is the historical VOM dollars as derived from FERC Accounts 512 and 513 for fossil steam units.

Units with less than 1 year of history are considered immature. Such units can be assigned their calculated Maintenance Adder and/or Start Cost Maintenance Adder, or a forecast value, subject to evaluation pursuant to the Mitigated Offer Methodology Approval Process.

4.6.1 Configuration Addition VOM Adder

For units undergoing a significant system or unit Configuration Addition the use of an additional “Configuration Addition VOM Adder” may be included in the determination of the total VOM adder. It is not intended to be used for upgrades to existing equipment (i. e. : replacement of a standard burner with a low NOX burner). Examples of significant system or unit Configuration Additions may include but are not limited to:

• Installation of Flue Gas Desulfurization (FGD or scrubber) systems

• Activated Carbon Injection (ACI) or other sorbent injection systems

• Installation of SCR or SNCR NOX removal systems

• Conversion from open loop to closed loop circulation water systems


• Bag House addition

• Water injection for NOX control

• Gas Turbine Inlet Air Cooling

• Dry Sorbent Injection (DSI)

The specific system or unit configuration system change needs to be reviewed by the MMU pursuant to the Mitigated Offer Methodology Approval Process and receive final approval thereof prior to the use of a Configuration Addition VOM Adder.

4.6.2 Calculation of the Configuration Addition VOM Adder

The Configuration Addition VOM Cost (CAVC) is to be calculated in the same manner as the VOM Adder described in this section with the exception that the Configuration Addition VOM Cost dollars are only the incremental additional costs incurred because of the system or unit configuration change.

As with the current VOM dollar calculation under Section 2.4, the adder for year (Y) uses the actual costs beginning with year (Y-1). Therefore, the first year of actual incremental additional expenses will be captured by the CAVC in the second year.

Following the initial year of use of the CAVA, each additional year‘s CAVA will be incorporated into the total until the end of the historical Maintenance Period selected for the unit.

4.6.3 Reductions in Total VOM Costs

While it is expected that the Configuration Addition VOM adder will most often be used to cover step increases in VOM costs, it is also to be used to capture step decreases in VOM costs resulting from a significant system or unit configuration change that results in a significant reduction in VOM costs. Any equipment that falls into disuse or is retired because of the configuration change must have its VOM expenses removed from the historical record used to develop the VOM adder. An example of a significant system or unit configuration change that may result in a step decrease in qualified VOM costs includes, but is not limited to, a fuel change from coal to gas fuel.

5.7 VOM Cost

Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to combined cycle units.

Combined Cycle VOM Cost – the historical VOM dollars as derived from FERC Accounts 512, 513, and 553. If submitting as a simple cycle combustion turbine, use total dollars from FERC Account 553.


6.7 VOM Cost

Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to CT and diesel engine units.

Combustion Turbine - VOM Cost – The historical total dollars from FERC Account 553 should be used to calculate the VOM $ specified under Section 2.4.

7.6 VOM Cost

Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to hydro units.

The historical total dollars from the FERC accounts listed here should be used to calculate the VOM $ specified under Section 2.4. The cost of labor, materials used and expenses incurred in the maintenance of plant, includible in Account 332, Reservoirs, Dams, and Waterways. (See operating expense instruction 2). The cost of labor materials used and expenses incurred in the maintenance of fish and wildlife, and recreation facilities, the book cost of which is includible in Account 332, Reservoirs, Dams, and Waterways, includable in Account 545, Maintenance of Miscellaneous Hydraulic Plant.

9.4 VOM

Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to wind units.

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.

𝐸𝑂𝐶 𝑉𝑂𝑀 𝐴𝑑𝑑𝑒𝑟 ($/𝑀𝑊ℎ) =𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 ($)

𝑀𝑊ℎ 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑃𝑟𝑜𝑑𝑢𝑐𝑒𝑑

10.4 VOM

Note: The information in Section 2.4 contains basic VOM Cost information relevant for all unit types. The following additional information only pertains to solar units.


Solar 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 solar units, VOM dollars from the previous years should be divided by MWh generated in the same period.

𝐸𝑂𝐶 𝑉𝑂𝑀 𝐴𝑑𝑑𝑒𝑟 ($/𝑀𝑊ℎ) =𝑉𝑂𝑀 𝐷𝑜𝑙𝑙𝑎𝑟𝑠 ($)

𝑀𝑊ℎ 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑖𝑜𝑛 𝑃𝑟𝑜𝑑𝑢𝑐𝑒𝑑


Attachment AF

3.2 Mitigation Measures for Energy Offer Curves

Mitigated Energy Offer Curves shall be submitted on a daily basis by the Market

Participant not to exceed the costs described in accordance with the mitigated offer

development guidelines in the Market Protocols. The mitigated Energy Offer Curve may

be updated up to 1100 hours on the day before the Operating Day 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 1100 hours on the day before the Operating Day 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:


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;


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: Attachment 21 - MPRR 213 MOTF-2014 Comments 9-19-2014.docx Page 15 of 26

(1) The Resource’s Energy Offer Curve exceeds the mitigated Energy Offer

Curve by the applicable conduct threshold; and





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”); inter-temporal opportunity costs; and Energy Offer Curve

(“EOC”) variable operations and maintenance costs (“VOM”) , as not to exceed

the costs detailed in the mitigated offer development guidelines 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 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

Comment [CTM7]: This is a clarification.


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



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 information will be sufficient for

replication of the mitigated Energy Offer Curve and shall include, among other

data, the following information:










(3) For VOM costs, Market Participants shall submit VOM costs, calculated

in adherence with not to exceed the default levels in the mitigated offer

development guidelines, the Appendix G of the Market Protocols, without

prior approval of the Market Monitorreflecting short-run marginal costs,

exclusive of fixed costs. Any VOM costs in excess of the default levels

shall reflect short run marginal costs, exclusive of fixed costs. The default

VOM costs shall be reviewed and updated by the Market Monitor and the

Market Working Group (MWG) at least annually, as described in Section

2.4 of Appendix G of the Market Protocols. To the extent that the Market

Monitor determines that SPP competitive market offers reflect lower

VOM costs than the default VOM costs, the default VOM costs shall be

reduced.

Further details associated with the development, validation, and updating of these


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. 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. Intra-day changes to the mitigated

energy offer curve must follow the mitigated offer development guidelines in the

Market Protocols and will be validated by the Market Monitor.




3.3 Mitigation Measures for Start-Up Offers and No-Load Offers

A mitigated Start-Up Offer and a mitigated No-Load Offer shall be submitted daily by

the Market Participant, not to exceed the costs described in in accordance with the

mitigated offer development guidelines in the Market Protocols. The mitigated Start-Up

and No-Load Offers may be updated up to 1100 hours on the day before the Operating

Day for use in the Day-Ahead Market. In the case a Resource is not committed by the

Day-Ahead Market, the Start-Up and No-Load Offers may be updated until the Day-

Ahead RUC begins. The mitigated Start-Up and No-Load Offers 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 on the Operating Day.

A. The Start-Up and No-Load Offer conduct thresholds are as follows:


conduct threshold is a 10% increase above the mitigated Start-Up or

mitigated No-Load Offer, as applicable;


mitigated Start-Up or mitigated No-Load Offer, as applicable.

B. The Transmission Provider shall apply mitigation measures by replacing the Start-

Up or No-Load Offer with the applicable mitigated Start-Up or No-Load Offer if:

(1) The Resource’s Start-Up or No-Load Offer exceeds the mitigated Start-Up

or mitigated No-Load Offer, as applicable, by the applicable conduct

threshold; and






C. The mitigated Start-Up Offer shall represent the cost per start as determined from

start fuel usage and the costs related to that fuel usage, Performance Factor cost of

electricity for station use to start (“Station Service”), maintenance costs attributed

to starts, and additional labor costs, if required above normal station staffing

levels. The following formula shall apply to all mitigated Start-Up Offers:

Mitigated Start-Up Offer ($/Start) = [Start Fuel (mmBtu/Start) *

Total Fuel Related Costs ($/mmBtu) * Performance Factor] + [Station

Service (MWh/Start) *

Station Service Rate ($/MWh)] + Start VOM ($/Start) + Start Additional

Labor Cost ($/Start)

The mitigated Start-Up Offer for Demand Response resources shall be the cost to

shut down or curtail load for a given period, which varies with the number of

deployments rather than the amount of response, and/or the start cost of Behind-

The-Meter Generation utilizing the mitigated Start-Up Offer calculation

applicable to other generation Resources as defined above.

The mitigated Start-Up Offer for Variable Energy Resources shall be zero.

D. The mitigated No-Load Offer shall be the hourly fixed cost required to create a

monotonically increasing mitigated Energy Offer Curve. It shall be calculated

according to either of two methods:

(1) No-Load Fuel Approach

Mitigated No-Load Offer ($/hour) = No Load Fuel (mmBtu/hour) *

Performance Factor * (No-Load VOM ($/mmBtu) +

Total Fuel Related Cost ($/mmBtu)

(2) No-Load Cost Approach

Mitigated No-Load Offer ($/hour) =

(Heat Input at Minimum Economic Capacity Operating Limit

(mmBtu) * Performance Factor *

(Total Fuel Related Cost ($/mmBtu) + No Load VOM ($/mmBtu)

) ) –

(Incremental Cost up to Minimum Economic Capacity Operating

Limit ($/MWh) * Minimum Economic Capacity Operating Limit

(MW) )


The mitigated No-Load Offer for Demand Response Resources utilizing

Behind-The-Meter Generation shall adhere to the same definition above as a

generating Resource. For Demand Response Resources utilizing load

reduction, the mitigated No-Load Offer shall not exceed the quantifiable

ongoing hourly costs associated with load reduction.

The mitigated No-Load Offer for Variable Energy Resources shall be zero.

E. The Market Participant shall submit all inputs used in calculating mitigated Start-

Up and mitigated No-Load Offers to permit the Market Monitor to verify

submitted offers. Required information includes: 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. 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. Information to be provided by the Market Participant

shall include the following:









(3) For VOM costs, Market Participants shall submit VOM costs not to

exceed the default levels in the mitigated offer development guidelines,

Appendix G of the Market Protocols, without prior approval of the Market

Monitor. reflecting short-run marginal costs, exclusive of fixed costs.

Any VOM costs in excess of the default levels shall reflect short run

marginal costs, exclusive of fixed costs. The default VOM costs shall be

reviewed and updated by the Market Monitor and the Market Working

Group (MWG) at least annually, as described in Section 2.4 of Appendix

G of the Market Protocols. To the extent that the Market Monitor


determines that SPP competitive market offers reflect lower VOM costs

than the default VOM costs, the default VOM costs shall be reduced.

Further details associated with the development, validation and updating of these





3.4 Mitigation Measures for Operating Reserve Offers

A mitigated offer for each Operating Reserve product shall be submitted daily by the

Market Participant not to exceed the costs described in accordance with the mitigated

offer development guidelines in the Market Protocols. The mitigated Operating Reserve

Offers may be updated up to 1100 hours on the day before the Operating Day for use in

the Day-Ahead Market. In the case a Resource is not committed by the Day-Ahead

Market, the mitigated Operating Reserve Offers may be updated until the Day-Ahead

RUC begins. For Resources committed by the Day-Ahead Market, the mitigated

Operating Reserve Offers submitted as of 1100 hours on the day before the Operating

Day 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 Operating Reserve

Offers submitted at the time the Day-Ahead RUC begins will apply to the RTBM on the

Operating Day.

A. The offer conduct thresholds for each of the Operating Reserve products are as

follows:


conduct threshold is a 10% increase above the mitigated offer for the

applicable Operating Reserve Offer;

(2) For all other Resources, the conduct threshold is a 25% increase above the

mitigated offer for the applicable Operating Reserve Offer.

B. Any Operating Reserve Offer exceeding the applicable threshold, except offers

below $10/MWh, will be deemed excessive. The Transmission Provider shall

apply mitigation measures by replacing the Operating Reserve Offer with the

applicable mitigated Operating Reserve Offer if:

(1) The Resource’s Operating Reserve Offer exceeds the applicable mitigated

offer by the conduct threshold; and






C. The mitigated Spinning Reserve Offer shall be equal to zero for Resources other

than combustion turbines, reciprocating engines and hydro Resources operating as

a synchronous condenser. No known incremental costs are incurred for providing

Spinning Reserves from other resource types.

Total mitigated Spinning Reserve Offer for combustion turbines, reciprocating

engines and hydro Resources operating as a synchronous condenser shall not

exceed any additional fuel related costs, maintenance costs and power

consumption costs necessary for the Resource to be prepared for deployment of

Spinning Reserve:

Mitigated Spinning Reserve Offer ($/MW) ≤

(Additional Fuel Cost($/Hr) + Additional Maintenance Cost

($/Hr) + Condensing Power Cost ($/Hr) ) /

Spinning Reserve MW

The mitigated Supplemental Reserve Offer shall not exceed labor costs necessary for the

Resource to be prepared for deployment of Supplemental Reserve:

Mitigated Supplemental Reserve Offer ($/MW) <

Additional Labor Cost($) / Average Supplemental Reserve MW

D. The mitigated Regulation-Up Offer shall not exceed the sum of the cost increase

due to:




Mitigated Regulation-Up Offer ($/MW) <


($/MW) +


E. The mitigated Regulation-Down Offer shall not exceed the sum of the cost

increase due to:





Mitigated Regulation-Down Offer ($/MW) <


($/MW) +


Further details associated with the development of the exact costs in the formulas

above are included in the Market Protocols.

F. The Market Participant may include in the calculation of its mitigated Operating

Reserve Offer an amount reflecting the Resource-specific opportunity costs if the

Market Participant is able to demonstrate to the satisfaction of the SPP Market

Monitoring Unit that such costs are legitimate and verifiable and not otherwise

included in market outcomes. To the extent such costs include run-time

restrictions, such 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 formulas and instructions in

the price forecast model for any such opportunity costs shall be determined by the



Monitoring Unit. Opportunity costs for mitigated Operating Reserve Offers shall

not include Energy and Operating Reserve Markets revenues associated with

forgone Energy or other types of Operating Reserve production to the extent that

such costs are included in market outcomes.

G. 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 Operating Reserve Offers 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.



(3) For VOM costs, Market Participants shall submit VOM costs, not to

exceed the default levels in the mitigated offer development guidelines,

Appendix G of the Market Protocols without prior approval of the Market

Monitor. Any VOM costs in excess of the default levels shall reflect short

run marginal costs, exclusive of fixed costs. The default VOM costs shall

be reviewed and updated by the Market Monitor and the Market Working

Group (MWG) at least annually, as described in Section 2.4 of Appendix

G of the Market Protocols. To the extent that Market Monitor determines

that SPP competitive market offers reflect lower VOM costs than the

default VOM costs, the default VOM costs shall be reduced.

calculated in adherence with the Appendix G of the Market Protocols, reflecting


H. In all cases under this Section 3.4, cost data submitted for the development of



3.5 Validation of Mitigated Resource Offer Parameters

The Market Monitor shall review the costs included in each mitigated Resource Offer in

order to ensure that the Market Participant has correctly applied the formulas and definitions in

Sections 3.2, 3.3, 3.4 and the Market Protocols and that the level of the mitigated offer is

otherwise acceptable. If the mitigated offer determined by the Market Monitor and the Market

Participant differ, the mitigated offer calculated by the Market Monitor shall be used. If a

Market Participant submits a dispute over its mitigated offer, the previously approved mitigated

offer shall be used from the time the dispute is submitted until the dispute is resolved. The

procedures for submitting and processing disputes related to mitigated offers shall be those

specified in the Market Protocols. The Transmission Provider shall remedy mitigated offer

disputes resolved in favor of the Market Participant by providing make whole payments, as

necessary, to the Market Participant whose mitigated offer was improperly determined by the

Market Monitor.


Each Market Participant is obligated to provide to the Market Monitor any cost data

necessary to allow the Market Monitor to validate its mitigated Resource Offer.

The Market Monitor shall keep such data confidential, and all cost data submitted under

this Section 3.5, including any opportunity cost data, shall be subject to the confidentiality

provisions set forth in Section 11 of Attachment AE of this Tariff. The Market Monitor shall

develop and maintain on the Transmission Provider’s website the mechanism and procedures to

allow Market Participants to submit such cost data.



Re-directing Transmission Service with Pseudo-Ties

• Background on Pseudo-Tie rules

• Current Practice

• SPP Recommendation

2

Agenda

Background

• SPP filed MPRR 69 shortly after Marketplace go-live – MPRR 69 clarified rules for pseudo-tie out resources

Charges congestion and losses from Source/Sink to INT

Limits flexibility on changing pseudo-tie status to registration timelines

• FERC requested additional information from SPP on the treatment of pseudo-tie out assets in SPP – Registration rules, limitations and re-direction of

transmission service

3

Background continued

• SPP clarified that SPP cannot operationally support, outside of established registration timelines, a pseudo-tied asset from moving in and out of the market

• SPP clarified that SPP did not allow the re-direction of transmission for service supporting a pseudo-tie – SPP considered the service as permanently scheduled

(via the pseudo-tie)

– No systematic method for limiting the use of the service in real-time

– No systematic method for accounting for overuse of service in settlements

4

Background continued

• FERC accepted MPRR 69 – Pseudo-tied out assets cannot “jump in and out” of the

Market

– Pseudo-tied out assets will be charged congestion and losses

• FERC pointed out that SPP has nothing in the Tariff that limits the re-direction of transmission service supporting pseudo-ties

5

Current Practice • SPP is processing redirects in accordance with the

Changes of Service Specifications (Section 22) of the Tariff requirements

• If a transmission customer overuses the transmission service, a penalty will be enforced in transmission settlements pursuant to Section 13.7(c) of the Tariff – Process is managed manually after-the-fact

6

Current Practice: Example • 100MW TSR supports Resource Y that is registered as

pseudo-tied out

• Resource Y decides to limit output to 25MW for HE1500-2000 and wants to use the remaining 75MW transmission service

• 75MW of the TSR is re-directed for HE1500-2000 and used to support an interchange transaction (e-tag)

• If Resource Y’s output exceeds 25MW anytime during HE1500-2000 (the re-direction time period) the transmission customer will be penalized for over usage

• Process is managed manually after-the-fact

7

Pseudo-Tie Out TSR Redirects • SPP has previously taken the position that re-direction

of transmission service supporting pseudo-ties is not available – The pseudo-tie is a fully subscribed schedule

implemented all of the time.

– Static in nature due to registration requirements

– Recommended MP desiring re-direction flexibility to use dynamic interchange scheduling

• No customers had requested the possibility of re-direction of service supporting pseudo-ties until recently

• The Tariff does not address the topic specifically

8

Limitations to Pseudo-Tie Out Redirects?

• SPP has concerns about managing the re-direction of transmission service supporting pseudo-tied out resources both in operations and in settlements

• If more transmission customers register assets using a pseudo-tied out approach, SPP will need to invest in new systems to automate the accounting process. – Validation of service rights will be enforced after-the-

fact

– Penalties will be charged if transmission service is over subscribed, consistent with the Tariff

9

Options for Pseudo-Tie Out TSR Re-directs

• Add clarifying language to the Tariff, Market Protocols, and Business Practices to address the re-direction rules for transmission service supporting pseudo-ties. – Options:

1. Limit re-direction rights to Market registration timelines

– TC can only re-direct on a bi-monthly basis, consistent with the market registration

2. Limit re-direction rights to a time period that is more manageable than hourly to reflect the static nature of the tie

– Monthly or weekly basis only 3. Treat re-direction rights similar to service as if the tie is

dynamic

– Hourly rights to direct

10

SPP Recommendation

• SPP recommends options 1 or 2 – Consistent with static nature of pseudo-tie registration

– MPs choosing for more flexibility with TSR redirection have the option registering a resource in the market of using dynamic interchange scheduling

– Enables SPP to manage re-direction manually without the need for new systems

11

SPP Market Working Group Meeting October 21st - 22nd, 2014 AEP Office - Dallas, TX

Discussion Topic: “Rules for Redirection of Transmission Service for Pseudo-Tie Out Resources”

Southern Company Comments:

• Southern is a point to point transmission service customer under the SPP OATT and has two variable energy resources that are pseudo-tied out of SPP to serve load in the Southern Company Balancing Area.

• As such a customer, Southern is entitled under Section 22.1 of the SPP OATT to redirect available room in its firm reservation on a non-firm basis.

• FERC has recently ruled that there is no provision in SPP’s OATT that permits SPP to restrict such redirection rights.

• In order for SPP to amend the OATT to include restrictions on redirect of unused transmission reservation, SPP would have the burden of proving that such restrictions are “consistent with or superior to” the pro forma OATT, which is predicated on service flexibility and optimization with respect to firm point to point transmission rights.

• Furthermore, any limitation of the redirection rights of pseudo-tie customers would:

o Prevent pseudo-tie customers from being able to fully utilize the rights they have purchased, therefore lowering the overall transmission utilization on SPP’s system,

1

o decrease the value of the transmission service without lowering the

price for the service, and

o Single out pseudo-tie customers in an unfair and unjust way

• However, we recognize and appreciate SPP’s concern that it cannot currently monitor pseudo-tie transmission utilization using the same tools and procedures it uses for point to point customers who do not have a pseudo-tie out resource.

• Therefore, Southern proposes the following rather than unfairly limiting customers’ redirect rights. Option 1: Do nothing. Do not speculate that customers will abuse redirection. Charge a penalty if a customer over-utilizes their reservation. This is the way MISO currently handles pseudo-tie customer transmission redirects. Option 2: SPP can easily verify in day-ahead, hour ahead and real time operations that the pseudo-tie flow does not exceed the capacity of the transmission reservation minus the portion of the reservation that is utilized by other (redirected and tagged) transactions. Option 3: SPP can allow market participants to tag the pseudo-tie transaction and therefore verify transmission utilization the same way it does for non-pseudo tie customers. MISO does not currently allow pseudo-tie tags, but it seems reasonable that a cooperative effort would be successful in gaining MISO support for tagging pseudo-ties. Tagging pseudo-ties appears to be the way the industry is headed.

2

Option 4: SPP can require pseudo-tie customers to provide detailed transmission utilization information as needed for day-ahead and real time operations. This information can be provided to SPP via Portal, Web Services interface or ICCP.

3

SPP September 2014 Marketplace Update

Market Monitoring Unit

October 22, 2014

Overview • LMPs and MCPs

• Summary of Scarcity Events

• DA Market Participation

• Make Whole Payments and RNU

• Congestion

• TCR Funding

• Coal Delivery Issues

2

Monthly Average LMPs

3

0

2

4

6

0

5

10

15

20

25

30

35

40

45

50

Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14

$/M

MB

TU

$/M

WH

SPP NORTH HUB

DA LMP RT LMP Panhandle

0

2

4

6

0

5

10

15

20

25

30

35

40

45

50


$/M

MB

TU

$/M

WH

SPP SOUTH HUB

DA LMP RT LMP Panhandle

4

0

10

20

30

40

50

60

Loca

tio

nal

Mar

gin

al P

rice

($

/MW

h)

Daily Average SPP Hub Energy Prices September 2014

SPPNORTH_HUB - DAMKT SPPNORTH_HUB - RTBM SPPSOUTH_HUB - DAMKT SPPSOUTH_HUB - RTBM

Monthly Average RTBM Regulation Prices

5

6

0

5

10

15

20

25

30

Mar

ket

Cle

arin

g P

rice

($

/MW

) Daily Average SPP Regulation Up MCPs

September 2014

DAMKT RTBM

7

0

2

4

6

8

10

12

14

16

18M

arke

t C

lear

ing

Pri

ce (

$/M

W)

Daily Average SPP Regulation Down MCPs September 2014

DAMKT RTBM

Monthly Average RTBM OR Prices

8

9

0

2

4

6

8

10

12M

arke

t C

lear

ing

Pri

ce (

$/M

W)

Daily Average SPP Spinning Reserve MCPs September 2014

SPP - DAMKT SPP - RTBM

10

0

2

4

6

8

10

12M

arke

t C

lear

ing

Pri

ce (

$/M

W)

Daily Average SPP Spinning Reserve MCPs September 2014

1 - RTBM 2 - RTBM 3 - RTBM 4 - RTBM

Monthly Average RTBM OR Prices

11

12

0

0.5

1

1.5

2

2.5

3

3.5M

arke

t C

lear

ing

Pri

ce (

$/M

W)

Daily Average SPP Supplemental Reserve MCPs September 2014

SPP - DAMKT SPP - RTBM

13

0

0.5

1

1.5

2

2.5

3

3.5M

arke

t C

lear

ing

Pri

ce (

$/M

W)

Daily Average SPP Supplemental Reserve MCPs September 2014

1 - RTBM 2 - RTBM 3 - RTBM 4 - RTBM

14

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00C

ou

nt

of

5 M

inu

te M

arke

t In

terv

als

RTBM Scarcity and Ramp Events September 2014

OR Scarcity REG Up Scarcity REG Dn Scarcity Spin Scarcity OR Ramp Scarcity Reg Down Ramp Scarcity

Note : Where both capacity and ramp scarcity exisit in the same interval, only the capacity scarcity is shown.

Virtual Participation in Marketplace

15

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%


Cleared Virtual Bids as Percent of Report Load Cleared Virtual Offers as Percent of Reported Load

Virtual Participation – Hourly Volume

16

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

Ave

rage

Ho

url

y V

olu

me

(M

Wh

)

Hourly Average Cleared Virtual Bids Hourly Average Uncleared Virtual BidsHourly Average Uncleared Virtual Offers

Hourly Average Cleared Virtual Offers

Average Hourly Load Participation in DA Market

17

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

101%

102%

103%

104%


Cleared Demand as Percent of Reported Load-Off Peak Cleared Demand as Percent of Reported Load- ON Peak

Make Whole Payments

18

Revenue Neutrality Uplift

19

* This table is based on the latest available settlements data and is subject to change due to resettlement


DA Revenue Inadequacy 0 0 0 0 0 0 0

RT Revenue Inadequacy 22,000 85,000 19,000 54,000 111,000 49,000 110,000

OOME MWP 154,000 91,000 94,000 170,000 83,000 22,000 39,000

RT Regulation Deployment Adj 739,000 131,000 -21,000 219,000 161,000 143,000 37,000

RT JOA 0 0 0 0 0 0 0

RT Congestion 338,000 1,455,000 2,552,000 4,383,000 -180,000 -344,000 2,794,000

Sub-Total 1,253,000 1,762,000 2,644,000 4,826,000 175,000 -130,000 2,980,000

Less RT Net Inadvertent 647,000 1,078,000 504,000 196,000 268,000 426,000 907,000

RNU * 606,000 684,000 2,140,000 4,630,000 -93,000 -556,000 2,073,000

20

September Congestion

21

TCR Summary by Month

88.9% Funding

September TCR Summary

22

Many Outages Unaccounted for in Annual Process

ARR Summary by Month

23

Coal Deliveries

• Thanks to all market participants who have been in contact with the MMU regarding coal delivery delays.

• Transparency is helping MMU track the situation.

• MMU verified opportunity costs may be used in mitigated offers to reflect fuel supply limitations.

• Reflecting opportunity costs in offers is a more economic solution to managing coal supply than adjusting offer parameters, for both the market participant and for SPP.

24

Regulatory Report to MWG for October 2014

Current Filings

Description FERC Docket No.

Activity Status

IM Motion for Clarification

ER12-1179 ER13-1173

Motion for clarification made on July 11, 2014 regarding cost allocation for manual resource commitments to address local reliability issues. Order granting rehearing issued by FERC on August 11, 2014.

Awaiting order.

Order No. 755 – Frequency Response Compensation

ER13-1748 Filing made on June 21, 2013. Comments due by July 12, 2013. • Three interventions were filed. SPP filed responses on August 1, 2013.

Deficiency letter issued by FERC on March 7, 2014. SPP filed its deficiency response on April 7, 2014. Order issued by FERC on June 19, 2014 conditionally accepting the filing with several compliance requirements outlined in the order. Compliance filing made on July 21, 2014. Comments due by August 11, 2014.

• One intervention was filed. Amendment to compliance filing made on August 1, 2014. Comments due by August 22, 2014.

Awaiting order.

First Filing Post Go-Live

ER14-1653 Filing of MPRRs and TRRs made on April 3, 2014. Comments due by April 24, 2014. • Four interventions were filed and one protest was filed. SPP filed responses on

May 9, 2014. Deficiency letter issued by FERC on May 30, 2014. SPP filed its deficiency response on July 2, 2014. Order issued by FERC on August 29, 2014 conditionally accepting the filing with one compliance requirement outlined in the order.

Awaiting order.


Compliance filing made on August 29, 2014. Comments due by October 21, 2014. Second Filing Post Go-Live

ER14-2399 Filing of MPRRs (91, 113, 122, 124, 144) and TRRs (121, 124) made on July 10, 2014. Comments due by July 31, 2014.

• Two interventions were filed.

Amendment to compliance filing made on August 27, 2014. Comments due by September 17, 2014. Motion for Deferral filed on September 19, 2014.

Preparing supplemental filing.

Order No. 681 – LTCRs (Phase II Project)

ER14-2553 Filing of MPRRs 138 and 171 made on July 31, 2014. Comments due by August 21, 2014.

• Seven interventions were filed and two protests were filed. SPP filed responses on September 8, 2014.

• In reply to SPP’s responses, two responses were filed.

Awaiting order.

MPRR 183—Re-pricing Clarification

ER15-20 Filing of MPRR 183 made on October 2, 2014. Comments due by October 23, 2014. • Three interventions were filed.

Awaiting order.

MPRR 173—Physical Withholding Screen


Awaiting order.

MPRR 190—MWP Start-Up Offer Recovery Eligibility Clarifications


Awaiting order.

MPRR 178—DVER & NDVER Operating Limit Clarification

ER15-47 Filing of MPRR 190 made on October 6, 2014. Comments due by October 27, 2014. • One intervention was filed.

Awaiting order.


Future Filings

MPRR Title Status/Anticipated Filing Date 101 Combined Cycle Enhanced Design Phase II project 140 Mitigated Transition State Offers Phase II project 141 Mitigated Regulation Mileage Phase II project 155 Modification of OOME Rules Tabled by SPP Operations

165 Pseudo-Tie Losses Correction Related to deficient filing (ER14-1653)

176 Order 755 Compliance Corrections Phase II project 180 Federal Service Exemption IS Filing 193 VRL and Market-to-Market coordination BOD 10/28/2014 194 Mitigation Tests for Manual Commitments BOD 10/28/2014 195 Online Supplemental Reserve and OR Dispatch Status BOD 10/28/2014

198 Change MP to AO in Physical Withholding Rules Sponsor may appeal to BOD 10/28/2014

199 Intra-Day Mitigation Measures Clarifications BOD 10/28/2014 201 Dispute Clarification BOD 10/28/2014 202 Uneconomic Production Monitoring Screen BOD 10/28/2014 204 Compliance and Additional Changes FERC Order 755 BOD 10/28/2014 212 Over Collected Losses Design Change BOD 10/28/2014

Documents

Southwest Power Pool MARKET WORKING GROUP MEETING October … october 21-22... · 2019-02-08 · Minutes No. [236] Southwest Power Pool MARKET WORKING GROUP MEETING October 21-22,