Southwest Power Pool

MARKET WORKING GROUP MEETING

December 16-17, 2014

AEP Offices – Dallas, TX

• Summary of Motions • Agenda Item 5 – MPRR227-LTCR Compliance Filing Gene Anderson (OMPA) made a motion and Matt Johnson (CUS) seconded to expedite and approve MPRR227 as modified and as being compliant with the FERC Order. The motion passed with one opposition (Westar) and no abstentions. Agenda Item 8 – Marketplace Re-Pricing – Request to FERC for Tariff Waiver John Varnell (Tenaska) made a motion and Jim Flucke (KCPL) seconded that MWG has considered the information regarding the proposed re-pricing event and does not believe this re-pricing is necessary. The motion passed with no opposition and no abstentions. Agenda Item 9 – Resource Hub Request Process Jim Flucke (KCPL) motioned and Rick Yanovich (OPPD) seconded to recommend that the SPP Board of Directors approve the six existing Resource Hubs in SPP Marketplace. The motion passed with no opposition and no abstentions. Rick McCord (EDE) motioned and Ron Thompson (NPPD) seconded to recommend that the SPP Board of Directors approve the new resource hub GSPR2015HUB, and as necessary direct SPP Staff to seek or support a waiver from the 6-month notification for new resource hub requests. The motion passed with no opposition and no abstentions. Jim Flucke (KCPL) motioned and Matt Johnson (CUS) seconded to approve the requested resource hubs necessary for the Integrated System project, information which is to be emailed to MWG voting members with email votes requested and returned no later than 48 hours of the email request. This motion was tabled, according to the vote below:

Gene Anderson (OMPA) made a motion and John Varnell (Tenaska) seconded to table the motion to approve the requested resource hubs necessary for the Integrated System project. The motion to table passed with no opposition and no abstentions.

Agenda Item 10 – MPRR221 – Transitional ARR Allocation Process – SPP Comments Shawn McBroom (OGE) motioned and Ron Thompson (NPPD) seconded to incorporate the SPP Comments into the MPRR221 Recommendation Report. The motion passed with no opposition and no abstentions.

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Agenda Item 11 – MPRR215 Product Substitution Cost Calculation – SPP Comments Rick Yanovich (OPPD) motioned and Shawn McBroom (OGE) seconded to incorporate the SPP Comments into the MPRR215 Recommendation Report. The motion passed with no opposition and no abstentions. Agenda Item 13 – MPRR219 TCR Shortpay Calculation Correction Rick McCord (EDE) made a motion and Shawn McBroom (OGE) seconded to reject MPRR219. The motion passed with one opposition (BETM) and one abstention (Tenaska). Agenda Item 18 – MPRR222 Impact Assessment Ron Thompson (NPPD) made a motion and Rick Yanovich (OPPD) seconded to approve the MPRR222 Impact Assessment. The motion passed with no opposition and no abstentions. Agenda Item 20 – MPRR224 Second Round to the SPP TCR Annual Auction Shawn McBroom (OGE) made a motion and Richard Ross (AEP) seconded to reject MPRR224, followed by Matt Johnson (CUS) making a motion and Cliff Franklin seconding to table the motion to reject on MPRR224. The motion passed with two oppositions (OGE, AEP) and one abstention (Tenaska). Agenda Item 21 – MPRR225 Ramp Reservation Requirements Change Rick McCord (EDE) made a motion and Rick Yanovich (OPPD) seconded to approve the MPRR225 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 23 – MPRR226 Settlement Area Definition Change Aaron Rome (Midwest) made a motion and Rick Yanovich (OPPD) seconded to treat MPRR226 as expedited. The motion passed with no opposition and no abstentions. Aaron Rome (Midwest) made a motion and Cliff Franklin (Westar) seconded to approve MPRR226 as modified in the meeting. The motion passed with no opposition and no abstentions.

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Southwest Power Pool

MARKET WORKING GROUP MEETING

December 16-17, 2014

AEP Offices – Dallas, TX

• M I N U T E S •

Agenda Item 1 — Call to Order, Proxies, Agenda Discussion Richard Ross (AEP) called the meeting to order at 8:15 a.m. The attendance was recorded and proxies were announced (Attachment 1 – MWG Attendance December 16-17 2014). The following members were represented by proxy:

John Varnell (Tenaska) for Ann Scott (Tenaska) (Attachment 1a - Ann Scott Proxy) Lawson Arnett (Xcel) for Amber Metzker (Xcel) (Attachment 1b - Proxy for Amber Metzker)

The group reviewed the agenda (Attachment 2 - MWG Agenda for December 16-17 2014) and agreed to some minor changes in agenda order to accommodate presenters and audience. Agenda Item 2 — Minutes Approval Richard Ross (AEP) asked for feedback on the minutes from the MWG Nov 10 2014 meeting (Attachment 3a - MWG Nov 10 2014 Minutes) and the MWG Nov 18-19 2014 meeting (Attachment 3b - MWG Nov 18-19 2014 Minutes). No changes were made and the minutes were deemed approved as posted.

Agenda Item 3a — Working Group/Committee Updates: MOTF 2014 Amber Metzker (Xcel) provided an update from the MOTF-2014 December 15 2014 meeting. Amber reported that the group approved recommendation of an MPRR that makes adjustments to the timeline for fuel cost submission. This MPRR will be officially submitted and then presented for consideration by the MWG at a future meeting. Amber also reported that the 12/15/14 meeting was the final meeting of the MOTF-2014 and that the Task Force is dissolving for now. The group still has 7 or 8 items from their topics list that will be handed off to the MWG to continue working on as needed. SPP Staff will work with Amber to prepare those items for the MWG. Agenda Item 3b — Working Group/Committee Updates: SPP Board of Directors Meeting Richard Ross (AEP) provided an update to the group from the SPP Board of Directors (BOD) meeting held on December 9, 2014. Richard reported that MPRR197-VOM Cost Clarification was sent back by the BOD to the MOPC/MWG for additional work on reaching a consensus amongst SPP Members and MPs and the SPP MMU regarding VOM costs and Mitigated Offers. Richard Ross announced that Richard Dillon (SPP) would be speaking to the MWG later in this meeting as part of agenda item #7 regarding plans resulting from the SPP BOD’s decision and directive. After the BOD update, Sam Ellis (SPP) asked to

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announce to the MWG that SPP Staff will be submitting Comments in opposition to MPRR22 at the January 2015 meeting of the MOPC. MPRR222 proposes a system change to allow Market Participants to submit a resource into the market with an economic maximum of zero MW’s. This MPRR was approved by the MWG on 11/19/14 and is on the agenda for consideration by the MOPC in January 2015. Agenda Item 3c — Working Group/Committee Updates: 2015 MOPC MPRR Schedule Jared Greenwalt (SPP) reminded the group of important dates for submitting MPRRs for the January 2015 and April 2015 MOPC meetings (Attachment 4 - 2015 MOPC MPRR Schedule). Agenda Item 4 — Organizational Survey Results Richard Ross (AEP) directed the attention of the group to the SPP Organization Survey Results in the background materials (Attachment 5 - 2014 MWG org survey_analysis) and spoke specifically to some of the recommendations for improvements provided in the comments section. Regarding the timeliness of meeting materials, Richard reported that SPP Staff will continue to improve on this and do the best that they can, but reminded the MWG that they do always have discretion to table because the meeting materials were not provided with ample time for review. Regarding comments about small size of the meeting room in Dallas, Richard suggested that any MWG member can make a motion about moving the meetings to another location and the group will vote on it. Regarding comments about difficulties in being able to hear the meeting conversations via the phone, Richard reminded the group that the MWG meetings are meant to be a face-to-face meeting and that providing the phone attendance should be a considered a convenience. SPP Staff also reported that an update to the phone system in the AEP meeting room in Dallas is being worked on and will be complete in early 2015. That upgrade should alleviate some of the difficulties of hearing when participating via phone. Richard also mentioned other informal comments that had gotten back to him from some stakeholders that he may sometimes inappropriately try to sway the group one way or another, so he encouraged anyone feeling this way or with any feedback on how he could do better to please let him know or to please approach Carl Monroe (SPP) to suggest someone else to chair the MWG if that feel that is needed. Matt Moore (GSEC) commented that he really appreciates the efforts of Richard as MWG Chair of Gene Anderson (OMPA) as Vice-Chair and of SPP Staff and encourages the Members of MWG in general to become more engaged if they are not and to speak up on issues. Other Members and Stakeholders in the room concurred with Matt. Debbie James (SPP) asked to comment on other comment from survey regarding a request to see rankings of MWG goals and accomplishments on a regular basis. Debbie reminded the group of the “MWG initiatives list” that they have been asked to help prioritize, and Richard Ross encouraged the group to bring up their suggestions and concerns with that process later in the meeting when that agenda items comes up for discussion.

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Agenda Item 5 — MPRR227 LTCR Compliance Filing Wayne Camp (SPP), Charles Cates (SPP), and Steve Purdy (SPP) led the continued discussion on MPRR227 (Attachment 6 - MPRR 227 Recommendation Report), which contains proposed Protocol language and proposed Tariff language revisions in response to the FERC Order issued on 10/28/14 conditionally accepting the LTCR design, subject to a compliance filing by SPP. The proposed revisions specifically address FERC’s main directives for SPP to allow incremental LTCRs (ILTCRs) to be issued to entities for associated Sponsored Upgrades, and to allow LTCRs and ILTCRs to be nominated prior to the SFT instead of selecting LTCRs after the SFT. Gene Anderson (OMPA) made a motion and Matt Johnson (CUS) seconded to expedite and to approve MPRR227 as modified and as being compliant with the FERC Order. The motion passed with one opposition (Westar) and no abstentions. Agenda Item 6 — DVER Logic Update Carrie Simpson (SPP) and Raleigh Mohr (SPP) presented analysis results in response to requests and inquiries from SPP Members and Stakeholders on how the Dispatchable Variable Energy Resource (DVER) logic in Marketplace is working so far (Attachment 7 - DVER logic Update). The data does show a decrease in the number of directives issued to VERs and SPP Staff commented that the Marketplace centralized unit commitment and the ability for DVERS to be a part of that is contributing to that decrease. There was also data presented to show the effects on LMP if a unit is run as a DVER versus a non-dispatchable VER (NDVER). The conclusion from this and other comparisons between DVERs and NDVERs does show that market is able to be more efficient with regards to VERs if more of the VERs are DVERs. Carrie Simpson (SPP) commented that NDVERs are not generally a part of the market solution, but instead are reacting to the solution by following price on their own. The data presented here shows some of the economic impact of that behavior, but there is also a significant reliability impact. There was agreement from the group about the general conclusions from the analysis showing that the SPP Market could be more efficient if more NDVERs were able to become DVERs, so the discussion turned to possible ideas on how to incent or to possibly force that conversion, and a request from SPP Staff on feedback and direction from MWG on where to go next. Would MWG like to see more data? Should SPP propose a change in the DVER registration requirement, such as moving the “commercially operational” data for grandfathering in as an NDVER? There was some discussion about how the contracts play into this and how to engage those involved in the contracts in the incentive building and realization of benefits. The group concluded that the data shown today is compelling and does show possible need for more analysis and possibly some incentive proposals by someone, but not necessarily by SPP Staff at this time. The group was encouraged to continue to brainstorm ideas for making the move from NDVER to DVER to prove to be a good investment, and to bring forth any proposals for discussion. Agenda Item 7 — MPRR197 VOM Cost Clarification – SPP Board of Directors Decision Richard Dillon (SPP) announced and explained the decision from the SPP Board of Directors regarding MPRR197, which was to send the MPRR back to the MOPC/MWG for continued efforts to gain consensus amongst SPP Members and Market Participants and SPP MMU. Richard informed the group of a plan from SPP Staff to form a small group made up of representation from both MPRR197 and MPRR213, and from a neutral party. So far, it has been decided that John Olson (Westar) will be representing MPRR197, and Gene Anderson (OMPA) will be the neutral party. SPP Staff is still looking for the MPRR213 representative. Richard Dillon (SPP) and Alan McQueen (SPP MMU) will represent SPP Staff and MMU Staff respectively. Richard announced that all MOPC Members will be requested to

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document their concerns on VOM costs and mitigated offer with regards to the status quo, with MPRR197 and with MPRR213. Richard is asking MWG Members to do the same thing, and to please include pros of all of the above. He asked that MWG Members please send this information to him via email. Richard said the small group will be acting quickly, since the SPP Board of Directors wants an update at their meeting in January, 2015. Agenda Item 8 — Marketplace Re-Pricing – Request to FERC for Tariff Waiver Joe Ghormley (SPP) presented information on a Marketplace possible re-pricing need that has been identified. Since the possible re-pricing would take place after the issuance of the final Settlements statement, then FERC permission to re-price is necessary (Attachment 8 - Repricing Event - Approval for FERC Filing). Also, the Marketplace Protocols state that any such re-pricing request to FERC must be decided and approved by the MWG. Brent Wilcox (SPP) of the SPP Settlements Department reported that based on their analysis of the dollar impact of the proposed re-pricing on the 8800 pricing records for that re-pricing period, 31% had no change, 32% had less than a $.10 change, 35% had a change between $.10 and $1.00, and 1% had a change of more than $1.00. Brent also reported that there had not been any disputes so far over the lack of re-pricing. Joe Ghormley clarified that the Tariff speaks of a determination of “necessary” re-pricing and that it is the opinion of SP Legal that it is necessary. The MWG discussed the re-pricing and the group concluded that given the information and data submitted here, it was not worth the rigor of a FERC filing and the additional work for the MPs on Settlements. John Varnell (Tenaska) made a motion and Jim Flucke (KCPL) seconded that MWG has considered the information regarding the proposed re-pricing event and does not believe this re-pricing is necessary. The motion passed with no opposition and no abstentions. Agenda Item 9 — Resource Hub Request Process Nick Parker (SPP) delivered a presentation (Attachment 9 - Resource Hub Inconsistency and Approval) to describe an inconsistency recently discovered that currently exists between the Marketplace Protocols and the SPP Tariff with regards to the process for requesting and approving Resource Hubs. FERC had rejected Tariff language contained in MPRR90, which referenced the request and approval process for Hubs as defined in the Protocols. Because of the FERC rejection, no change was ever actually made to the Tariff, so the language thought to be referenced in the Protocols is now null and void. Basically, the current binding Tariff language, which has priority over the conflicting Protocol language, states that requests for Market Hubs must be approved by the MOPC and the Board of Directors (BOD), and the use of term Market Hubs in that context is meant to encompass both Resource Hubs and Trading (Market) Hubs. Since that is what is in the current Tariff, then all Resource Hubs must follow that process. Also, SPP Staff wishes to now request approval through the same Tariff process for the six existing Resource Hubs, so that they too are in compliance with the Tariff language. Those six Resource Hubs had not been previously approved through the Tariff process because they had followed the process defined in the Protocols, which was what was recently discovered to be in conflict with the Tariff. So, the MWG action being requested today is to approve the existing six Resource Hubs, and to consider approval of a newly submitted Resource Hub request, including a waiver of the current Tariff requirement to post the Hub data for approval 6 months prior to the effective date. These approvals are needed during this MWG meeting in order for them to go before the MOPC and SPP BOD in January, 2015. A spreadsheet with detailed information on each Hub being considered was also made available to the MWG Members (Attachment 10 - ResourceHubs_12112014). Additionally, Debbie James (SPP) reported from the SPP

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Staff leaders of the SPP Integrated System (IS) project that other requests for Resource Hubs could be coming as part of the IS integration. The details on those Resource Hubs are not available yet, but will also need to be approved at the January MOPC and BOD. The group agreed to a future email vote on the requests for Resource Hubs associated with the IS integration, with direction to SPP Staff to send the details of the requests once they are available. As a result of this agreement, a motion was made and seconded to approve the Resource Hubs necessary for the IS project, then a subsequent motion and second was made to table the approval motion. It will remain tabled until such IS Resource Hub requests are made. All of the requested actions of the MWG with regards to Resource Hubs resulted in the following motions, seconds, and approvals by the MWG:

• Jim Flucke (KCPL) motioned and Rick Yanovich (OPPD) seconded to recommend that the SPP Board of Directors approve the six existing Resource Hubs in SPP Marketplace. The motion passed with no opposition and no abstentions.

• Rick McCord (EDE) motioned and Ron Thompson (NPPD) seconded to recommend that the SPP Board of Directors approve the new resource hub GSPR2015HUB, and as necessary direct SPP Staff to seek or support a waiver from the 6-month notification for new resource hub requests. The motion passed with no opposition and no abstentions.

• Jim Flucke (KCPL) motioned and Matt Johnson (CUS) seconded to approve the requested resource hubs necessary for the Integrated System project, information which is to be emailed to MWG voting members with email votes requested and returned no later than 48 hours of the email request. This motion was tabled, according to the vote below:

o Gene Anderson (OMPA) made a motion and John Varnell (Tenaska) seconded to table the motion to approve the requested resource hubs necessary for the Integrated System project. The motion to table passed with no opposition and no abstentions.

Agenda Item 10 — MPRR221 Transitional ARR Allocation Process – SPP Comments Nick Parker (SPP) presented the SPP Comments to MPRR221 (Attachment 11 - MPRR 221 Recommendation Report), which added language to clarify what base flow inputs to the Transitional ARR Allocation Process are to be used. The language for the monthly allocation section was clear, but it was determined that the language in annual allocation section needed an extra sentence of clarification. The SPP comments to MPRR221 add that extra sentence of clarification. Shawn McBroom (OGE) motioned and Ron Thompson (NPPD) seconded to incorporate the SPP Comments into the MPRR221 Recommendation Report. The motion passed with no opposition and no abstentions. Agenda Item 11 — MPRR215 Product Substitution – SPP Comments Wayne Camp (SPP) presented the SPP Comments to MPRR215 (Attachment 12 - MPRR 215 Recommendation Report), which propose additional Tariff changes, requested after a further later review of MPRR215 by SPP Legal and Regulatory, to coincide with existing Protocol language already approved by MWG to specify which offer will be used to calculate make whole payment costs. Rick Yanovich (OPPD) motioned and Shawn McBroom (OGE) seconded to incorporate the SPP Comments into the MPRR215 Recommendation Report. The motion passed with no opposition and no abstentions.

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Agenda Item 12 — MPRR214 Adequate Fuel Cost Recovery Gay Anthony (SPP) reported that MPRR214 is tabled at the request of the submitter, Rob Janssen (Dogwood), who submitted the following statement regarding the MPRR: “I think that we can keep [MPRR]214 on the table for another meeting or two as we go through this winter and see if any issues remain. I think that some might, but I also think that since 214 can't get to FERC to be effective this winter, there is no reason to push it forward right away, and every reason to wait for a while as we see the results of [MPRR]223. Agenda Item 13a & 13b — FTR Portfolio Netting & MPRR219 TCR Shortpay Calculation Correction Andrew Hartshorn (Boston Energy Trading and Marketing - BETM) and Justin Foster (BETM) brought MPRR219 back up for discussion (Attachment 13 - MPRR 219 Recommendation Report). This MPRR proposes to correct the calculation of a short pay for TCR holders, so that instead of charging a position in both directions as it currently does, it would net counterflows. The BETM representatives presented information in November 2014 MWG meeting defending the need for the design changes in this MPRR, which they stated is because MPs with counterflow TCRs are getting an additional charge in DA MKT for shortpay that the MPRR submitters do not think they should get, because they are already getting charged for counterflow in the DA MKT. As part of today’s discussion on MPRR219 and to assist MWG Members and Stakeholders with education on this topic, Howard Haas of Monitoring Analytics was asked to deliver a presentation for the MWG on changes currently being proposed in the PJM market design related to netting of counterflows (Attachment 14 - MA SPP Portfolio Netting). Howard reported that two main aspects of the proposed PJM changes are: 1) elimination of portfolio netting; and 2) adopt an equitable uplift of FTRs in relation to prevailing and counter flow. Item 1 above is the topic of Howard’s presentation today, and reports that although the PJM design does currently net the prevailing flow and counterflow, the proposed changes would eliminate that netting. One of the concerns from Monitoring Analytics is that the current PJM design is subsidizing the counter-flow positions and over-incenting counter-flow purchasing. Netting does not currently exist in the SPP Marketplace, but MPRR219 from BETM proposes to add the netting design to the SPP Marketplace. SPP’s current design is slightly different from where the proposed PJM design is heading in that SPP uses absolute values. Richard Ross (AEP) thanked Monitoring Analytics for their time and information, and summarized the discussion on MPRR219 as coming down to a question of does SPP keep our current design, or does SPP move in the direction of where the Monitoring Analytics proposal is taking PJM, or does SPP approve MPRR219 and move towards the addition of portfolio netting? Richard stated his position as not prepared to change anything in the SPP design at this time. Seth Cochran (DC Energy) commented that he has concerns with the MWG not approving MPRR219 and provided the following statement to explain his position and reasons: our concern is that the status quo, as compared to the MPRR 219 changes, disincentives counterflow positions, which a) increases the percent share of total underfunding for any one owner of prevailing direction TCRs and b) provides less opportunity for market participants to acquire hedges, which hurts liquidity. Rick McCord (EDE) made a motion and Shawn McBroom (OGE) seconded to reject MPRR219. The motion passed with one opposition (BETM) and one abstention (Tenaska). Agenda Item 14 — MPRR181 Mirrored JOU Share Option Jared Greenwalt (SPP) and Cliff Franklin (Westar) brought MPRR181 back up for discussion (Attachment 15 - MPRR 181 SPP Comments 12-4-2014), which originally proposed to establish an additional (3rd) JOU registration option, for any unit type, allowing a single designated owner offer to apply to the total unit

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3-part offer and will have all charges & payment settled according to JOU entity MP shares. At the MWG’s direction, SPP Staff has been researching options for achieving what this MPRR proposes to do. Upon hearing the results of some of that research, the MWG is now directing SPP to provide Impact Assessment information on some of the possible options, so this MPRR was tabled again, pending that additional work on the Impact Assessment(s). Agenda Item 15 — MPRR207 Staggered Start-Up Time (pending Impact Analysis) Jared Greenwalt (SPP) reported that the Impact Analysis for MPRR207 is still in the process of being completed and is not available for this MWG meeting, therefore it is requested that the Impact Analysis be tabled until a future MWG Meeting. Agenda Item 16 — MPRR217 Regulation Certification Testing Procedure Raleigh Mohr (SPP) introduced MPRR217 (Attachment 16 - MPRR 217 SPP Comments 11-14-2014), which proposes to change the regulation certification testing procedure requirements for resources. The current test’s rate of response interval is 5 minutes, which is appropriate to test for energy deployment, not regulation deployment. MPRR217 proposes a shorter rate of response interval, which will better test a resource’s AGC response for regulation deployment. The group discussed the proposal and asked questions of Raleigh and other SPP Staff. One concern from some of the group is that the proposed testing procedures are still not close enough to reality when determining a resource’s ability to regulate. MWG tabled this MPRR for now and asked SPP Staff to continue to research more options for regulation testing and certification. Agenda Item 17 — MPRR220 Poor Regulation Performance Disqualification This item was tabled at the request of the submitter. Agenda Item 18 — MPRR222 - Impact Analysis Jared Greenwalt (SPP) introduced the MPRR222 Impact Analysis, which reported an estimated cost of $15,813 and an estimated duration of 5 months (Attachment 17 - MPRR 222 Recommendation Report). Ron Thompson (NPPD) made a motion and Rick Yanovich (OPPD) seconded to approve the MPRR222 Impact Assessment. The motion passed with no opposition and no abstentions. Agenda Item 19 - MPRR218 Market Registration Naming Conventions Jared Greenwalt (SPP) introduced MPRR218 (Attachment 18 - MPRR 218 Market Registration Naming Conventions), which proposes to establish SPP naming conventions to insure that the names for all Market assets meet specific criteria so that 1) the naming structure of Settlement Locations, MDSLs, Source/Sinks, etc. is consistent and 2) the name of assets is easily identifiable in all SPP Reliability and Market models, systems, etc. The naming conventions will only apply to market assets going forward. The MWG discussed the proposed naming conventions as shown in the MPRR and offered feedback and suggested alternative naming convention changes. The MWG tabled MPRR218 for now and asked SPP Staff to consider their suggested changes and possibly other naming convention options and to bring those back as SPP Comments to MPRR218 for the MWG to consider.

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Agenda Item 20 — MPRR224 Second Round to the SPP TCR Annual Auction Noha Sidhom (Interia Power) introduced MPRR224 (Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction) and delivered a presentation describing the proposed changes and their purpose and benefit (Attachment 20 - Inertia Power III MPRR 224 Presentation). MPRR224 proposes to add another round to the SPP Annual TCR Auction, so that it becomes a two round process as opposed to the current single round process. Noha stated several reasons for the proposed change including: 1) a two round auction leads to better price discovery; 2) a two round auction is more productive for entities attempting to hedge. Currently, when trying to hedge a unit, there is only one opportunity to clear, which means the resource owner must bid high to ensure the hedge. Therefore, the one round auction incents price insensitive bidding; 3) a two round auction is more in line with other ISO practices. SPP is the only ISO with a one round annual auction; and 4) monthly auctions held from October through May are two round auctions and this would create symmetry between the annual auction and these monthly auctions. After some discussion, some MWG members voiced their concern and opposition regarding this MPRR, while others desired to have more time to research it and to consider it at a future meeting. The opinions resulted in the following motions and decisions by the MWG: Shawn McBroom (OGE) made a motion and Richard Ross (AEP) seconded to reject MPRR224, followed by Matt Johnson (CUS) making a motion and Cliff Franklin seconding to table the motion to reject on MPRR224. The motion passed with two oppositions (OGE, AEP) and one abstention (Tenaska). Based on these voting results, MPRR224 will be brought back up for discussion at a future MWG meeting with a motion and second on the table to reject the MPRR. Agenda Item 21 — MPRR225 Ramp Reservation Requirements Shari Brown (SPP) introduced MPRR225 (Attachment 21 - MPRR 225 Recommendation Report), which proposes Protocol changes requested from the SPP Business Practices Working Group (BPWG) to remove language describing functionality that would allow MPs to shift or extend schedules if needed for acquiring ramp reservation without being required to purchase corresponding transmission. This functionality was deemed out of scope during Marketplace implementation, but was inadvertently never removed from the Protocols. BPWG proposes to remove the functionality rather than starting the process of implementing it. Shari reports that no MP has asked for or tried to use the functionality. Rick McCord (EDE) made a motion and Rick Yanovich (OPPD) seconded to approve the MPRR225 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 22 — MPRR Quick RUC This item was tabled due to time constraints Agenda Item 23 — MPRR226 Settlement Area Definition Change Debbie James (SPP introduced MPRR226 (Attachment 22 - MPRR 226 Recommendation Report), which proposes Protocol and Tariff changes allowing SPP to update the physical model such that multiple Settlement Areas can exist within a single SPP BA Participant Area so that actual Settlement Area losses can be calculated correctly for use in Settlement. The MPRR proposes changes in the use of the Settlement Area term in load forecasting and in the local MWP cost allocation. The need for this MPRR arose from a request by an non-LegacyBA SPP Market Participant to form and model its own Settlement Area. SPP Staff is asking for expedited treatment of MPRR226 today, so that the MPRR can be

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considered by the MOPC and SPP Board of Directors (BOD) in January, 2015, as the model changes to accommodate the MP request are scheduled to be effective on April 1, 2015, which is prior to the April MOPC and BOD meetings. The following motions and voting results regarding MPRR226 were recorded:

• Aaron Rome (Midwest) made a motion and Rick Yanovich (OPPD) seconded to treat MPRR226 as expedited. The motion passed with no opposition and no abstentions.

• Aaron Rome (Midwest) made a motion and Cliff Franklin (Westar) seconded to

approve MPRR226 as modified in the meeting. The motion passed with no opposition and no abstentions.

Agenda Item 24 — FCA Analysis Results John Hyatt (SPP MMU) presented a report of analysis results (Attachment 23 - FCA 2014 Study – MWG) on Frequently Constrained Areas (FCAs), which included recommendations for new FCA definitions to be taken to the MOPC and SPP Board of Directors (BOD) at their January 2015 meetings (Attachment 24 - FCA 2014 Report - MWG December 2014). If approved by the Board of Directors, the new FCA list will then be filed with FERC for inclusion in the SPP Tariff. John reported that significant changes have happened since the last FCA definitions. The recommendations to MOPC and SPP BOD are: 1) The Texas Panhandle area shall remain an FCA with a few modifications to the defining constraints and Resource group indicated in the FCA report; 2) the Kansas City and the NW Kansas areas no longer require designation as FCAs; 3) No other areas in the SPP footprint meet the criteria for designation as an FCA. Agenda Item 25 — RTO Marketplace Update This item was not verbally presented due to time constraints (Attachment 25 - December RTO Update final), but MWG Members and Stakeholders are encouraged to submit any questions they may have regarding this report. Agenda Item 26 — MMU Marketplace Update Catherine Tyler Mooney (SPP MMU) presented the MMU Marketplace update (Attachment 26 - 201411 MWG MMU Market Update) and answered questions from the group. Agenda Item 27 — Regulatory Report This item was not verbally presented due to time constraints (Attachment 27 - 2014 12 Regulatory Report to MWG), but MWG Members and Stakeholders are encouraged to submit any questions they may have regarding this report. Agenda Item 28 — MWG Initiatives Prioritization This item was tabled due to time constraints.

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Agenda Item 29 - Review of Motions, Action Items and Future Meetings

Motions: Agenda Item 5 – MPRR227-LTCR Compliance Filing Gene Anderson (OMPA) made a motion and Matt Johnson (CUS) seconded to expedite and approve MPRR227 as modified and as being compliant with the FERC Order. The motion passed with one opposition (Westar) and no abstentions. Agenda Item 8 – Marketplace Re-Pricing – Request to FERC for Tariff Waiver John Varnell (Tenaska) made a motion and Jim Flucke (KCPL) seconded that MWG has considered the information regarding the proposed re-pricing event and does not believe this re-pricing is necessary. The motion passed with no opposition and no abstentions. Agenda Item 9 – Resource Hub Request Process Jim Flucke (KCPL) motioned and Rick Yanovich (OPPD) seconded to recommend that the SPP Board of Directors approve the six existing Resource Hubs in SPP Marketplace. The motion passed with no opposition and no abstentions. Rick McCord (EDE) motioned and Ron Thompson (NPPD) seconded to recommend that the SPP Board of Directors approve the new resource hub GSPR2015HUB, and as necessary direct SPP Staff to seek or support a waiver from the 6-month notification for new resource hub requests. The motion passed with no opposition and no abstentions. Jim Flucke (KCPL) motioned and Matt Johnson (CUS) seconded to approve the requested resource hubs necessary for the Integrated System project, information which is to be emailed to MWG voting members with email votes requested and returned no later than 48 hours of the email request. This motion was tabled, according to the vote below:

Gene Anderson (OMPA) made a motion and John Varnell (Tenaska) seconded to table the motion to approve the requested resource hubs necessary for the Integrated System project. The motion to table passed with no opposition and no abstentions.

Agenda Item 10 – MPRR221 – Transitional ARR Allocation Process – SPP Comments

Minutes No. [240]

Shawn McBroom (OGE) motioned and Ron Thompson (NPPD) seconded to incorporate the SPP Comments into the MPRR221 Recommendation Report. The motion passed with no opposition and no abstentions. Agenda Item 11 – MPRR215 – Product Substitution Cost Calculation – SPP Comments Rick Yanovich (OPPD) motioned and Shawn McBroom (OGE) seconded to incorporate the SPP Comments into the MPRR215 Recommendation Report. The motion passed with no opposition and no abstentions. Agenda Item 13 – MPRR219 – TCR Shortpay Calculation Correction Rick McCord (EDE) made a motion and Shawn McBroom (OGE) seconded to reject MPRR219. The motion passed with one opposition (BETM) and one abstention (Tenaska). Agenda Item 18 – MPRR222 Impact Assessment Ron Thompson (NPPD) made a motion and Rick Yanovich (OPPD) seconded to approve the MPRR222 Impact Assessment. The motion passed with no opposition and no abstentions. Agenda Item 20 – MPRR224 – Second Round to the SPP TCR Annual Auction Shawn McBroom (OGE) made a motion and Richard Ross (AEP) seconded to reject MPRR224, followed by Matt Johnson (CUS) making a motion and Cliff Franklin seconding to table the motion to reject on MPRR224. The motion passed with two oppositions (OGE, AEP) and one abstention (Tenaska). Agenda Item 21 – MPRR225 Ramp Reservation Requirements Change Rick McCord (EDE) made a motion and Rick Yanovich (OPPD) seconded to approve the MPRR225 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 23 – MPRR226 – Settlement Area Definition Change Aaron Rome (Midwest) made a motion and Rick Yanovich (OPPD) seconded to treat MPRR226 as expedited. The motion passed with no opposition and no abstentions. Aaron Rome (Midwest) made a motion and Cliff Franklin (Westar) seconded to approve MPRR226 as modified in the meeting. The motion passed with no opposition and no abstentions. Action Items:

• Regarding the MPRR217-Regulation Certification Testing Procedure agenda item, SPP Staff

will continue to research possibilities for regulation testing, as well as regulation disqualification (related to MPRR220), and bring back information and possibly other alternatives for the group.

Minutes No. [240]

Future Meetings: January 20, 2015 (8:15 a.m. – 6:00 p.m.) January 21, 2015 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor February 10, 2015 (8:15 a.m. – 6:00 p.m.) February 11, 2015 (8:15 a.m. – 12:00 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor Agenda Item 30 — MPRR186 - Mitigated Offer – External Dynamic Resource This item was tabled. Agenda Item 31 — MPRR126 - Real-Time Regulation Make Whole Payment This item was tabled. Agenda Item 32 — MPRR211 Self-Commit Run Time MWG Exemption This item was tabled pending SPP Staff analysis. Agenda Item 33 — MPRR213 – Default VOM for Mitigated Offers This item was tabled.

Agenda Item 34 – Adjournment Richard Ross (AEP) adjourned the meeting at 11:56 a.m.

Respectfully Submitted, Debbie James Secretary Attachments Attachment 1 - MWG Attendance December 16-17 2014 Attachment 1a - Ann Scott Proxy Attachment 1b - Proxy for Amber Metzker Attachment 2 - MWG Agenda for December 16-17 2014

Minutes No. [240]

Attachment 3a - MWG Nov 10 2014 Minutes Attachment 3b - MWG Nov 18-19 2014 Minutes Attachment 4 - 2015 MOPC MPRR Schedule Attachment 5 - 2014 MWG org survey_analysis Attachment 6 - MPRR 227 Recommendation Report Attachment 7 - DVER logic Update Attachment 8 - Repricing Event - Approval for FERC Filing Attachment 9 - Resource Hub Inconsistency and Approval Attachment 10 - ResourceHubs_12112014 Attachment 11 - MPRR 221 Recommendation Report Attachment 12 - MPRR 215 Recommendation Report Attachment 13 - MPRR 219 Recommendation Report Attachment 14 - MA SPP Portfolio Netting Attachment 15 - MPRR 181 SPP Comments 12-4-2014 Attachment 16 - MPRR 217 SPP Comments 11-14-2014 Attachment 17 - MPRR 222 Recommendation Report Attachment 18 - MPRR 218 Market Registration Naming Conventions Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction Attachment 20 - Inertia Power III MPRR 224 Presentation Attachment 21 - MPRR 225 Recommendation Report Attachment 22 - MPRR 226 Recommendation Report Attachment 23 - FCA 2014 Study – MWG Attachment 24 - FCA 2014 Report - MWG December 2014 Attachment 25 - December RTO Update final Attachment 26 - 201411 MWG MMU Market Update Attachment 27 - 2014 12 Regulatory Report to MWG

X = In PersonP = By Phone* = By Proxy

Day 1 Day 1 Full Name Company E-mail Business PhoneX X Richard Ross (Chair) AEP rross@aep.com (918) 382-9285X X Gene Anderson (V-Chair) OMPA geneaengr@ecewb.com (405) 645-2280P P Aaron Rome Midwest Energy arome@mwenergy.com (785) 625-1431* P Amber Metzker Xcel Energy amber.l.metzker@xcelenergy.com (303) 571-6202* * Ann Scott Tenaska ascott@tnsk.com (817) 462-1514P P Bruce Walkup AECC bwalkup@aecc.com (501) 570-2639

Chris Lyons Exelon chris.lyons@exeloncorp.com (410) 470-2465X X Cliff Franklin Westar clifford.franklin@westarenergy.com (443) 226-7787X X Debbie James (Sec) SPP djames@spp.org (501) 614-3577X X Jim Flucke KCPL jim.flucke@kcpl.com (816) 701-7836X X Lee Anderson LES landerson@les.com (402) 467-7591* * Marguerite Wagner Boston Energy Trading & Marketing marguerite.wagner@betm.com (617) 529-3127X X Matt Johnson City Utilities, Springfield mjohnson@teainc.org (904) 360-1460P P Matt Moore Golden Spread Electric Coop mmoore@gsec.coop (806) 379-7766P P Neal Daney KMEA daney@kmea.com (913) 660-0242X X Rick McCord EDE rmccord@empiredistrict.com (417) 625-5129X X Rick Yanovich OPPD ryanovich@oppd.com (402) 514-1031X X Ron Thompson NPPD rfthomp@nppd.com (402) 845-5202X Shawn McBroom OGE mcbroosr@oge.com (405) 239-0255X Alan McQueen SPP amcqueen@spp.orgP Alfred Busbee SPP abusbee@spp.orgP Andrew Hartshorn BETM andrew.hartshorn@betm.comP P Barbara Stroope SPP bestroope@spp.org (501) 688-1792P P Bill Nolte SECI bdnolte@sunflower.net (420) 272-5458P Brent Wilcox SPP bwilcox@spp.org (501) 688-8267X X Carrie Simpson SPP csimpson@spp.org (501) 688-1757P Casey Cathey SPP ccathey@spp.org (501) 614-3267X X Catherine Mooney SPP cmooney@spp.orgX X Chandler Brown SECI cwbrown@sunflower.netP Charles Cates SPP ccates@spp.orgP P Chris Ziembko TEA cziembko@teainc.orgP Daniel Baker SPP dbaker@spp.orgP P David Adamczyk KCPL david.adamczyk@kcpl.comP David Charles Basin Electric Power Co. dcharles@bepc.com (701) 557-5631P David Hastings DHASTCO david@dhast.com (317) 217-9563P David Smith Shell dave.l.smith@shell.com

X Dennis Reed Westar dennis.l.reed@westarenergy.comP Eddie Watson SPP ewatson@spp.org

P P Eric Alexander GRDA ealexander@grda.com (918) 824-7245P Ericka Inertia Power ericka@inertiaispower.comP Erik Winsand DATC ewinsand@atcllc.com

Market Working Group12/16 - 17/2014

Face to Face Conference

X X Gay Anthony SPP ganthony@spp.org (501) 688-1722X Geoffrey M Rush Oklahoma Corp Comm g.rush@occemail.comP Grant Wilkerson Westar grant.wilkerson@westarenergy.comp P Hailey McKewon GRDA hmckewon@grda.comp Howard Haas Monitoring Analytics howard.haas@monitoringanalytics.comX X Jack Madden GDA Associates jack.madden@gdsassociates.comX X Jared Greenwalt SPP jgreenwalt@spp.orgX X Jason Minalga INV Energy jminalga@invenergyllc.comP Jason Robison SPP jrobison@spp.org (501) 688-1711P Jennifer Swierczek SPP jswierczek@spp.orgP Jerin Purtee KBPU jpurtee@bpu.comP P Jerry Stone SPP jastone@spp.orgP P Jerry Tielke MREnergy jtielke@mrenergy.comP P Jill Jones NMPP jjones@nmppenergy.orgP P Jim Gonzales SPP jgonzalez@spp.org

P Joe Byers SPP jbyers@spp.orgX X Joe Ghormley SPP jghormley@spp.orgP P Joey Schrepel BEPC jschrepel@bepc.com

P John Bell KCC j.bell@kcc.ks.govX John Hyatt SPP jhyatt@spp.org

X X John Knofczynski Basin Electric Power Co. jknofczynski@bepc.com (605) 270-1335P John Krajewski Energy Consulting jk@jkenergyconsulting.com (402) 440-0227X X John Tennyson City Utilities john.tennyson@cityutilities.netX X John Varnell Tenaska jvarnell@tnsk.com (817) 462-1037P P Jon Sunneberg NPPD jmsunne@nppd.comP P Julie Gerush SPP jgerush@spp.orgP Kara Sidman BP Energy kara.sidman@bp.com

P Ken Quimby SPP kquimby@spp.orgX X Kim Sullivan WFEC k_sullivan@wfec.comP Lawson Arnett Xcel james.l.arnett@xcelenergy.comP P Lisa Szot Enel lisa.szot@enel.comP Marisa Choate SPP mchoate@spp.org (501) 688-1707P Mark Trumble OPPD mtrumble@oppd.comP Matthew Harward SPP mharward@spp.orgP P Michael Daly SPP mdaly@spp.orgP Michael Nesmith Basin Electric Power Co. mnesmith@bepc.comX X Mike Mushrush OMPA mmushrush@ompa.comP P Natasha Brown SPP nbrown@spp.orgP P Nick Parker SPP nparker@spp.org (501) 614-3574P P Nicole Wagner SPP jwagner@spp.orgP Noha Sidhom Inertia Power noha@inertiaispower.comP P Patti Kelly SPP pkelly@spp.org (501) 614-3381X X Raleigh Mohr SPP rmohr@spp.orgP P Randy Root GRDA rroot@grda.comP Rebecca Atkins MPUA ratkins@mpua.orgX Richard Dillon SPP rdillon@spp.org (501) 614-3228

P Robert Pick NPPD rjpick@nppd.comP P Robert Safuto Customized Energy Solutions rsafuto@ces-ltd.com (917) 446-2579P Robert Stillwell IPL rstillwel@indepmo.org (813) 325-7482X Roy True Aces Power Marketing (APM) royt@acespower.com (317) 695-4146P Russ McRae Alstom russ.mcrae@alstom.comP P Ryan Turner CUS ryan.turner@cityutilities.netX X Sam Ellis SPP sellis@spp.orgP P Sarah Pettus Wind Coalition sarah@windcoalition.orgX P Seth Cochran DC Energy cochran@dc-energy.com (512) 971-8767P Seth Hayik Monitoring Analytics seth.hayik@monitoringanalytics.comP Shari Brown SPP sbrown@spp.orgX X Shawn Geil KEPCo sgeil@kepco.orgX X Shawnee Claiborn-Pinto PUCT shawnee.claiborn-pinto@puc.state.tx.us (512) 936-7388P P Sherry Hamilton SPP shamilton@spp.orgX X Steve Gaw Wind Capital Group RSGaw1@gmail.com (573) 645-0727P Steve Purdy SPP spurdy@spp.orgP P Terry Gates AEP tlgates@aep.com (614) 583-6574P P Terry Wright EDE twright@empiredistrict.comP P Tim Hooker GRDA thooker@grda.comP Tim Smith SPP tsmith@spp.orgP P Tom DeBaun KCC t.debaun@kcc.ks.govP Turner Crow SPP tcrow@spp.orgP Vince Vandaveer CUS vince.vandaveer@cityutilities.netX X Walt Cecil MOPSC walter.cecil@psc.mo.govX X Walt Shumate Shumate & Associates waltshumate@sbcglobal.net (512) 496-7704P P Wayne Camp Accenture wayne.camp@accenture.com (856) 204-0298P Yohan Sutjandra TEA ysutjandra@teainc.org

108 72

1

Micha Bailey

From: Debbie JamesSent: Thursday, January 23, 2014 5:06 PMTo: Scott, Ann; Ross, Richard C. (AEP)Cc: Varnell, John; Gay Anthony; Jared Greenwalt; Micha BaileySubject: RE: standing proxy for SPP MWG

Thank you.  Debbie James Manager of Market Design Office: 501‐614‐3577|Mobile: 501‐960‐3338 201 Worthen Drive Little Rock, AR 72223‐4936 djames@spp.org 

 

From: Scott, Ann [mailto:AScott@tnsk.com] Sent: Tuesday, January 21, 2014 3:31 PM To: Debbie James; Ross, Richard C. (AEP) Cc: Varnell, John Subject: standing proxy for SPP MWG  I would like give a standing proxy to John Varnell for any SPP MWG that I am not able to attend.  Thank you,  Ann Scott Director, Development Tenaska, Inc. 817‐462‐1514 office 817‐807‐5210 mobile  

1

Gay Anthony

From: Debbie JamesSent: Tuesday, December 16, 2014 9:09 AMTo: Arnett, LawsonCc: Gay Anthony; Ross, Richard C. (AEP)Subject: RE: Proxy for MWG

Thank you.  Debbie James Southwest Power Pool Manager of Market Design Office: 501‐614‐3577|Mobile: 501‐960‐3338 201 Worthen Drive Little Rock, AR 72223‐4936 djames@spp.org  

From: Arnett, Lawson [mailto:James.L.Arnett@xcelenergy.com] Sent: Tuesday, December 16, 2014 9:05 AM To: Debbie James Subject: FW: Proxy for MWG  Good Morning Debbie,  Here is the email that Amber sent last week.  Let me know if you need anything else.  Regards, Lawson  Lawson Arnett P: 303.571.6520 C: 720.469.0403 From: Metzker, Amber L Sent: Tuesday, December 09, 2014 9:12 AM To: Debbie James (djames@spp.org) Cc: Arnett, Lawson Subject: Proxy for MWG  Hey Debbie,  I had an unexpected meeting pop up in Minnesota next week on Tuesday December 16th.  Lawson will have my proxy for the MWG when I am unavailable.  I plan to teleconference in on Wednesday.    

Amber L. Metzker

Xcel Energy | Responsible By Nature

Manager, Market Operations

1800 Larimer Street, 10th Floor Denver, CO 80202

2

P: 303.571.6202 C: 920.650.2040 F: 303.571.2779

E: Amber.L.Metzker@xcelenergy.com ________________________________________________

XCELENERGY.COM

Please consider the environment before printing this email 

MARKET WORKING GROUP MEETING

December 16-17, 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 ............................................................................ Richard Ross

2. Minutes Approval ................................................................................................................. Richard Ross

a. November 10, 2014

b. November 18-19, 2014

3. Working Group/Committee Updates ................................................................................... Richard Ross

a. MOTF 2014 .................................................................................................... Amber Metzker

b. SPP Board of Directors Meeting ......................................................................... Richard Ross

c. 2015 MOPC MPRR Schedule ........................................................................ Jared Greenwalt

4. Organizational Survey Results .............................................................................................. Richard Ross

5. LTCR – Compliance Filing Update ....................................................................................... Charles Cates

a. MPRR227 – LTCR Compliance Filing

6. DVER Logic Update ............................................................................................................. Raleigh Mohr

7. MPRR197-VOM Cost Clarification – SPP Board of Directors Decision ............................... Richard Dillon

8. Marketplace Re-Pricing – Request to FERC for Tariff Waiver (approval item) ................... Joe Ghormley

9. Resource Hub Request Process .............................................................................................. Nick Parker

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

10. MPRR221 Transitional ARR Allocation Process - SPP Comments (approval item) ................. Nick Parker

11. MPRR215 Product Substitution Cost Calculation – SPP Comments (approval item) .......... Wayne Camp

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

13. MPRR219 – TCR Shortpay Calculation Correction

a. FTR Portfolio Netting (related to MPRR219) .........................................Monitoring Analytics

b. MPRR219 – TCR Shortpay Calculation Correction (approval item) ........ Marguerite Wagner

14. MPRR 181 Mirrored JOU Share Option .................................................... Cliff Franklin/Jared Greenwalt

15. MPRR207 - Staggered Start-Up Time (pending Impact Analysis) ................................... Jared Greenwalt

16. MPRR217 - Regulation Certification Testing Procedure (approval item) ........................... Raleigh Mohr

17. MPRR220 - Poor Regulation Performance Disqualification (table) .................................... Raleigh Mohr

18. MPRR222 Impact Assessment (approval item) .............................................................. Jared Greenwalt

19. MPRR218 - Market Registration Naming Conventions (approval item) ........................ Jared Greenwalt

20. MPRR 224 Second Round to the SPP TCR Annual Auction (approval item) ....................... Noha Sidhom

Day 2 – 8:15 a.m. – 12:00 p.m.

21. MPRR 225 Ramp Reservation Requirements change (approval item) ..................................Shari Brown

22. MPRR Quick RUC .............................................................................................................. Carrie Simpson

23. MPRR 226 Settlement Area Definition Change (expedited approval item) ....................... Debbie James

24. FCA Analysis Results ................................................................................................................ John Hyatt

25. RTO Marketplace Update ................................................................................................. Carrie Simpson

26. MMU Marketplace Update ............................................................................... Catherine Tyler Mooney

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

27. Regulatory Report ............................................................................................................. Marisa Choate

28. MWG Initiatives Prioritization ............................................................................................. Gay Anthony

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

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

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

32. MPRR211 - Self-Commit Run Time MWP Exemption (tabled pending SPP Staff analysis) ...... Jim Flucke

33. MPRR213 Default VOM for Mitigated Offers (table) ................................................................. Roy True

34. Adjournment ........................................................................................................................ Richard Ross

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

Southwest Power Pool

MARKET WORKING GROUP MEETING

November 10, 2014

Net Conference

• Summary of Motions • Agenda Item 3 – MPRR197 VOM Cost Clarification Richard Ross (AEP) made a motion and Ron Thompson (NPPD) seconded to approve the MPRR197 prior recommendation report, incorporating Xcel comments to the Tariff language as modified and AEP comments to the Protocol language as modified. The motion passed in a roll call vote with seven yes votes (AEP, KCPL, AECC, WR, NPPD, Xcel, OGE), four oppositions (OMPA, CUS, Midwest, LES), and six abstentions (KMEA, Exelon, Boston Energy, Tenaska, GSEC, OPPD).

Minutes No. [237]

Southwest Power Pool

MARKET WORKING GROUP MEETING

November 10, 2014

Net Conference

• 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 1:00 p.m. The attendance was recorded and the following Members were represented by proxy (Attachment 1 – MWG Attendance November 10 2014):

• John Varnell (TNSK) for Ann Scott (TNSK) (Attachment 1a – Ann Scott Proxy) • Chris Lyons (Exelon) for Marguerite Wagner (BETM) (Attachment 1a – Marguerite Wagner

Proxy)

The group reviewed the agenda (Attachment 2—MWG Agenda for November 10 2014) and Gene Anderson (OMPA) informed the group of a requested change to the order of discussion for agenda items #2 (MPRR213) and #3 (MPRR197), so that item #3 (MPRR197) was discussed first. There were no objections to this agenda change. Agenda Item 2 — MPRR213 Default VOM for Mitigated Offers After the discussion and the resulting approval of MPRR197 (agenda item #3), the decision was made to table MPRR213 (Attachment 3 - MPRR 213 Default VOM for Mitigated Offers) until after the MOPC and BOD meetings in December when they will consider approval of MPRR197 as recommended by MWG. Agenda Item 3 — MPRR197 VOM Cost Clarification Richard Ross (AEP) brought MPRR197 back up for discussion (Attachment 4 - MPRR 197 Recommendation Report) and pointed out the addition of proposed Tariff language and other proposed changes that had been submitted via Comments to MPRR197. The group was reminded that the MOPC in their October meeting directed MWG to either bring back MPRR197 with the addition of Tariff language or to bring another MPRR to replace it, and to be prepared to present an MWG recommendation to MOPC in a special MOPC teleconference meeting on December 2, 2014. There was discussion on MPRR213 as a possible replacement to MPRR197, with proponents of MPRR213 stating that it simplifies things for both MPs and MMU, while proponents of MPRR197 stated that it also simplifies things for all through the use of FERC accounts, and that it actually attempts to clarify a definition of short-run marginal cost, whereas MPRR213 does not. SPP MMU added that they still maintain that all language, both the initial approved language and the newly proposed language in MPRR197, includes costs that are not considered short-run marginal costs, particularly those costs in the FERC accounts. Some MWG Members and Stakeholders stated their agreement with this MMU position.

Minutes No. [237]

Comments to MPRR197 submitted from several entities were reviewed and considered and some were used as a basis for several modifications made during the meeting to both the proposed Protocol language and the proposed Tariff language. The most significant changes included the addition of other FERC accounts to those already listed in MPRR197. Richard Ross (AEP) made a motion and Ron Thompson (NPPD) seconded to approve the MPRR197 prior recommendation report, incorporating Xcel comments to the Tariff language as modified and AEP comments to the Protocol language as modified. The motion passed in a roll call vote with seven yes votes (AEP, KCPL, AECC, WR, NPPD, Xcel, OGE), four oppositions (OMPA, CUS, Midwest, LES), and six abstentions (KMEA, Exelon, Boston Energy, Tenaska, GSEC, OPPD). Agenda Item 4 — LTCR Order Update Nicole Wagner (SPP) reported that the FERC Order on LTCR will be discussed at a joint net conference meeting with RTWG, CAWG, and MWG scheduled for Wednesday, November 12, 2014 at 3:00-5:00. Agenda Item 5 — Review of Motions, Action Items and Future Meetings Motions: Agenda Item 3 – MPRR197 VOM Cost Clarification Richard Ross (AEP) made a motion and Ron Thompson (NPPD) seconded to approve the MPRR197 prior recommendation report, incorporating Xcel comments to the Tariff language as modified and AEP comments to the Protocol language as modified. The motion passed in a roll call vote with seven yes votes (AEP, KCPL, AECC, WR, NPPD, Xcel, OGE), four oppositions (OMPA, CUS, Midwest, LES), and six abstentions (KMEA, Exelon, Boston Energy, Tenaska, GSEC, OPPD). Action Item: No action items were recorded. Future Meetings: 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.) Location: AEP Office – Dallas, TX Room: 8th Floor

Minutes No. [237]

Agenda Item 6 – Adjournment Gene Anderson (OMPA) adjourned the meeting at 3:35 p.m.

Respectfully Submitted, Debbie James Secretary Attachments Attachment 1 - MWG Attendance November 10 2014 Attachment 1a - Ann Scott Proxy Attachment 1b - Marguerite Wagner Proxy Attachment 2 - MWG Agenda for November 10 2014 Attachment 3 - MPRR 213 Default VOM for Mitigated Offers Attachment 4 - MPRR 197 Recommendation Report

Southwest Power Pool

MARKET WORKING GROUP MEETING

November 18-19, 2014

AEP Offices – Dallas, TX

• Summary of Motions • Agenda Item 5 – MPRR212-Over Collected Losses Design Change – Implementation Prioritization Amber Metzker (Xcel) made a motion and Ann Scott (Tenaska) seconded to bundle MPRR212 with MPRR206 and continue to work towards a 4/1/15 implementation date. The motion passed with one opposition (AEP) and no abstentions. Agenda Item 7 – Must Offer – MOPC Action Item #225 Matt Moore (GSEC) made a motion and Amber Metzker (Xcel)) seconded to recommend to MOPC that no action be taken on Day-Ahead Must Offer until the deadline of reporting to FERC on how the Day-Ahead Must Offer is working, which is a report in 15 months after Marketplace go-live with 12 months of Market data. The motion passed with three oppositions (AEP, EDE, CUS) and seven abstentions (NPPD, LES, OGE, Westar, Tenaska, Midwest, Boston Energy). Richard Ross (AEP) made a motion and Rick McCord (EDE) seconded to advise MOPC that the MWG recommendation at this time is that having no Day-Ahead must offer is a better solution than the current limited Day-Ahead Must Offer. Therefore, there is no need to address changes to the current Day-Ahead must offer design at this time. The motion passed with two oppositions (GSEC, Xcel) and two abstentions (KMEA, AECC). Agenda Item 8 – MPRR223 - SPP Conservative Operations During Multi-Day RUC Ron Thompson (NPPD) made a motion and Rick McCord (EDE) seconded to treat MPRR223 as expedited. The motion passed with no opposition and one abstention (AEP). Richard Ross (AEP) made a motion and Cliff Franklin (Westar) seconded to approve MPRR223 as submitted. The motion passed with one opposition (OGE) and one abstention (GSEC). Agenda Item 13 – MPRR209 – Change Start-Up Offer from Daily to Hourly Jim Flucke (KCPL) made a motion and Lee Anderson (LES) seconded to approve MPRR209 as submitted. The motion passed with no opposition and two abstentions (CUS, AEP). Agenda Item 14 – MPRR210 – Sync to Min Costs in Mitigated Start-Up Offer Richard Ross (AEP) made a motion and Shawn McBroom (OGE) seconded to reject MPRR210. The motion passed with one opposition (KCPL) and four abstentions (Tenaska, Westar, Xcel, OPPD).

Minutes No. [238]

Agenda Item 16 – MPRR216 – Regulation Qualification Richard Ross (AEP) made a motion and Neal Daney (KMEA) seconded to approve MPRR216 with SPP Regulatory Legal Comments and as modified in the meeting. The motion passed with no opposition and no abstentions. Agenda Item 20 – MPRR221 – Transitional ARR Allocation Process Shawn McBroom (OGE) made a motion and Ron Thompson (NPPD) seconded to approve MPRR221 as modified in the meeting and with direction to SPP Staff to make conforming changes to the Tariff. The motion passed with no opposition and no abstentions. Agenda Item 24 – MPRR222 – Remove Maximum and Minimum Limitation for Self Schedule Resources Shawn McBroom (OBE) made a motion and Amber Metzker (Xcel) seconded to treat MPRR222 as expedited. The motion passed with no opposition and no abstentions. Amber Metzker (Xcel) made a motion and Jim Flucke (KCPL) seconded to approve MPRR222 as modified in the meeting with a ranking of medium. The motion passed with no opposition and one abstention (OMPA).

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Southwest Power Pool

MARKET WORKING GROUP MEETING

November 18-19, 2014

AEP Offices – Dallas, TX

• 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 November 18-19 2014). The following members were represented by proxy:

Ann Scott (Tenaska) for Marguerite Wagner (BETM) (Attachment 1a - Marguerite Wagner Proxy) The group reviewed the agenda (Attachment 2 - MWG Agenda for November 18-19 2014) and agreed to some minor changes in agenda order to accommodate presenters and audience. Agenda Item 2 — Minutes Approval Gene Anderson (OMPA) asked for feedback on the minutes from the MWG October 21-22 2014 meeting (Attachment 3 - MWG Oct 18-19 2014 Minutes). No changes were made and the minutes were deemed approved as posted.

Agenda Item 3a — Working Group/Committee Updates: MOPC MPRR Schedule Micha Bailey (SPP) presented reminded the group of important dates for submitting MPRRs for the January 2015 and April 2015 MOPC meetings (Attachment 4 - 2015 MOPC MPRR Schedule). Agenda Item 3b — Working Group/Committee Updates: MOTF-2014 Update Amber Metzker (Xcel) provided an update from the MOTF-2014 and reminded the group that there was no meeting in November pending the MOPC decision on MPRR197 at the MOPC Net Conference meeting on December 2. Amber also reported that in addition to MPRR197, there are a few other items that need to be wrapped up by the Task Force, so the MOTF-2014 will meet in December on 12/15, and any remaining items from that meeting will likely be handed off to the MWG and the MOTF-2014 will disband. Agenda Item 4 — Long-Term Congestion Rights (LTCR) – FERC Filing Discussion Richard Ross (AEP) provided an update on SPP’s current efforts related to the recent FERC Order on LTCRs. Joe Ghormley (SPP) reported that SPP will be requesting an extension of 60 extra days to respond to the order with a compliance filing. If the extension is granted, the new filing deadline would be January 30, 2015. Also, SPP and some MPs are evaluating a request for re-hearing from FERC. There is

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concern at MWG that a Jan 30 compliance filing is too late to meet the original LTCR implementation date of February 1, 2015, but SPP Staff is not as concerned and explained that we just need the language only in place for go-live and not the actual software changes, since there will not likely be any existing upgrades in place for the February go-live. Richard Ross summarized the work that needs to be done for the filing into five main areas and said that SPP Staff is in the best position to decide who all needs to be involved in crafting the language around those areas (Attachment 5 - Action items related to Order 681 LTCR Filing). There was agreement amongst the group that the RTWG should mainly focus on any decisions or changes related to Z2 credits and that the MWG and CAWG should focus on source/sink design decisions and on the LTCR process related to Market Participant upgrades. Many MWG Members and stakeholders voiced a preference to have either Z2 credits or LTCRs for participant-funded upgrades but not both. The MWG and CAWG will have a joint net conference meeting on December 10 at 8:00-10:00 a.m. (CST) to make decisions related to their action items. Debbie James (SPP) developed and presented a proposed schedule to move the design changes related to the LTCR filing through the SPP Stakeholder process (Attachment 6 - Schedule for LTCR filing). Agenda Item 5 — MPRR212-Over Collected Losses Design Change - Implementation Prioritization Jodi Woods (SPP) presented options for when the design changes to OCL contained in MPRR212 could possibly be implemented (Attachment 7 - MPRR Prioritization-MWG-1). Jodi reported that design changes related to MPRR206 Re-pricing are scheduled for implementation on 4/1/2015 and design changes related to MPRR215 Product Substitution are scheduled for implementation no earlier than 6/1/2015. The options, as described in Jodi’ presentation, propose either bundling the implementation of MPRR212 OCL with MPRR206 Re-pricing with a risk of delaying that change until May, or bundling MPRR212 OCL with MPRR215 Product Substitution, which means the OCL changes are not implementated until at least June. Jodi is asking for the desire of the group regarding these two implementation schedule proposals. Debbie James (SPP) reported that SPP Regulatory and Legal are uncomfortable with the risk of delaying MPRR206, because it contains changes related to a compliance issue. MWG Members and MPs have concerns potentially pushing the OCL changes out to 6/1/15 or even after, and pointed out that even though the OCL issue is not currently a compliance issue, it could become one the further it gets pushes out. Philip Bruich (SPP Settlements Staff) reported that he and his team have confidence that they can get both MPRR206 and MPRR212 changes implemented by April 1. The risk he reported will be having enough time to test the changes and fix any issues that arise form that testing. In summary, MPRR206 is the most important because it’s a compliance issue. MPRRs 215 and 212 are important Market Design issues and the direction needed from MWG is around the prioritization of those two. Amber Metzker (Xcel) made a motion and Ann Scott (Tenaska) seconded to bundle MPRR212 with MPRR206 and continue to work towards a 4/1/15 implementation date. The motion passed with one opposition (AEP) and no abstentions.

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Agenda Item 6 — Day-Ahead Market Head Room Matt Moore (GSEC) requested to bring up the discussion of headroom again now that the Marketplace has been in production for several months, and on the heels of the RUC education that SPP Staff recently provided, which Matt stated that he thought was very helpful. Matt reminded the group that there is currently no headroom in the Day-Ahead (DA) Market and that there is a substantial amount of RUC activity. Matt feels it’s more efficient to have headroom in DA Market instead of committing so many units in the RUC, because having more headroom in the DA MKT would mean procuring more energy economically, instead of procuring them through RUC. Representatives from SPP Operations Staff agreed that bringing this back up now that Marketplace has gone live is a good idea, because now there is real data to analyze. SPP Operations sees benefit in having the DA MKT and the Real-Time Market inputs look as close to the same as possible. They maintain that cannot happen as long as the headroom is different in the two Markets. There was also discussion on the possible effects to make whole payments (MWPs) if there was more headroom in DA and potentially less units committed through RUC. Catherine Tyler Mooney (SPP MMU) commented that if there was a way to accurately predict what amount of headroom is needed in RT, then we could know what do add in DA, and could match up more accurately. She also suggested that if headroom is predictable, then it really could be a product, in the same way the Operating Reserve is a product. Several agreed that this discussion does lead to further confirmation for the need for a ramp product. In the end, both SPP Staff and MWG Members agreed that it would be good to see some analysis on how things might clear differently if there was more headroom in the DA Market. So, an MWG Action Item was recorded directing SPP Staff to perform analysis and report results back to MWG on how things would clear with more headroom in DA, including affects to the number of RUC commitments and make whole payments.

Agenda Item 7 — Must Offer - MOPC Action Item #225 Jared Greenwalt (SPP) reminded the group of the MOPC Action item related to Day-Ahead Must Offer (Attachment 8 - MOPC Action Item 225 - Day-Ahead Must Offer), and of the analysis results that were presented in October. The question before the group now is how do we respond to MOPC? Richard Ross (AEP) stated his opinion as being a proponent of a DA Must Offer for Designated Resources, (DR), with an exemption for VERs if needed and feels it’s a bad idea is to keep what we currently have now in any form. Matt Moore (GSEC) stated his opinion as being a proponent of current design, which he sees no issues with, and suggests that we keep the keep the current design and continue to analyze it’s affects for the full 15 months that FERC requested. There was agreement that the results of the 6-month analysis presented at the MWG in October showed no evidence of wrong-doing, manipulative behavior, or other market-related issues because of the current DA Must Offer design. Cliff Franklin (Westar) requested an opinion from the SPP MMU on the question of is a DA Must Offer even necessary. Catherine Tyler Mooney (SPP MMU) stated the opinion that she thinks Market incentives to participate in DA MKT are strong, and that the MMU has not seen the Must Offer add extra value to the existing incentives. Gene Anderson (OMPA) stated the opinions that “real life” has proven that we don’t need the Must Offer, and suggested that we either remove it or leave it alone. After hearing and discussing the various opinions on this, the following two motions were made and approved, and will be presented to the MOPC as an update to MOPC action item #225:

• Matt Moore (GSEC) made a motion and Amber Metzker (Xcel)) seconded to recommend to MOPC that no action be taken on Day-Ahead Must Offer until the deadline of reporting to FERC on how the Day-Ahead Must Offer is working, which is a report in 15 months after

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Marketplace go-live with 12 months of Market data. The motion passed with three oppositions (AEP, EDE, CUS) and seven abstentions (NPPD, LES, OGE, Westar, Tenaska, Midwest, Boston Energy).

• Richard Ross (AEP) made a motion and Rick McCord (EDE) seconded to advise MOPC that the

MWG recommendation at this time is that having no Day-Ahead must offer is a better solution than the current limited Day-Ahead Must Offer. Therefore, there is no need to address changes to the current Day-Ahead must offer design at this time. The motion passed with two oppositions (GSEC, Xcel) and two abstentions (KMEA, AECC).

Agenda Item 8 — MPRR223 - SPP Conservative Operations During Multi-Day RUC Jim Gonzalez (SPP) introduced MPRR223 (Attachment 9 - MPRR 223 Recommendation Report), which adds language to say that Resources may be committed in the Multi-Day Reliability Assessment as part of SPP Conservative Operations, a further adds language that Resources committed out of the Multi-Day Reliability Assessment as part of SPP Conservative Operations will not be de-committed by SPP except to address Emergency conditions. Jim is asking for expedited treatment on this MPRR because as we approach winter operations, there is a need to clarify what we are during in these situations, since they are more likely to occur in winter. Some clarification was requested around the term “emergency condition” in the language. Jim Gonzalez (SPP) explained that an emergency condition could be a number of things, such as flowgate overloading, voltage issues, etc. Basically, anything that a Reliability Coordinator would take action on, which would not be anything related to economics. Catherine Tyler Mooney (SPP MMU) pointed out another side of this MPRR for the group to consider, which is that does tie operations to not de-committing; this would take away the discretion of being able to de-commit in these situations if needed, and it’s discretion that they currently have today, even though they don’t use it much.

• Ron Thompson (NPPD) made a motion and Rick McCord (EDE) seconded to treat MPRR223 as expedited. The motion passed with no opposition and one abstention (AEP).

• Richard Ross (AEP) made a motion and Cliff Franklin (Westar) seconded to approve MPRR223

as submitted. The motion passed with one opposition (OGE) and one abstention (GSEC).

Agenda Item 9 — MPRR214 - Adequate Fuel Cost Recovery With the approval of MPRR223-SPP Conservative Operations During Multi-Day RUC (agenda item #8 above), there was some discussion as to whether or not that MPRR negates the need for MPRR214. The consensus was that it doesn’t necessarily negate the need and that MPRR214 should still be considered. However, it is not quite ready for discussion again today and the MPRR submitter is not available at this time, so MPRR214 is being tabled for now.

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Agenda Item 10 — Hub Activity Nick Parker (SPP) presented analysis on activity since Marketplace go-live at the SPP Hubs (Attachment 10 - Hub Activity), which was requested by the MWG via an Action Item. This presentation is informational only and does not require any action from the MWG. Nick point out his observation that this hub activity is extremely low compared to other RTOs, and the group discussed possible reasons for that, such as the price volatility between Day-Ahead and Real-Time occurring at the North Hub, or maybe it’s just a new Market and participants are getting used to it. Matt Moore (GSEC) reminded the group that this analysis was requested as part of the IS Integration and how the hub definitions may need to change for that. Matt suggested that this question now is does this data give the IS representatives or MWG any information on their decisions one way or the other, and the consensus was that it really just further confirms that the existing hubs need to stay in place. Someone, such as Basin, may propose a new hub, but there is nothing in the requested data shown here today that suggests any changes to existing hubs should be made. Agenda Item 11 — MPRR219 - TCR Shortpay Calculation Correction Andrew Hartshorn (BETM) introduced MPRR219 and presented information to explain and support the proposed changes, which correct the calculation of a short pay for TCR holders, so that instead of charging a position in both directions as it currently does, it would net counterflows. (Attachment 11 - MPRR 219 TCR Shortpay Calculation Correction & Attachment 12 - Absolute Revenue Shortfall Slide Deck). Andrew stated that the reason for their submission of this MPRR is because MPs with counterflow TCRs are getting an additional charge in DA MKT for shortpay that the MPRR submitters do not think they should get, because they are already getting charged for counterflow in the DA MKT. Catherine Tyler Mooney (SPP MMU) commented on this MPRR and asked the group to keep in mind that counterflow can also create additional capacity for a financial position and not just a load-serving position, as the examples show. Andrew shifted the examples to try and show that that does not make a difference. Overall, there were concerns from the group that this MPRR is netting all activity, and further general concerns that there has not been enough time for SPP Staff and maybe others to research this proposal and look at all angles, so the consensus of the group is to table this MPRR for now, pending further research and subsequent education, including if possible a look at the history of the current design. Agenda Item 12 — MPRR207 - Staggered Start-Up Time Jim Flucke (KCPL) introduced MPRR207 (Attachment 13 - MPRR 207 Staggered Start-Up Time), which introduces the idea for the creation of new parameters that would allow for the staggered start of a group of units. For example, this would allow for four CTs at a plant to have start times no less than 60 minutes apart based on plant and personnel limitations. The group decided it would rather make an exception to the process and see an Impact Assessment for this before considering approval of it, so the decision was made to table MPRR207 until the December MWG, pending an Impact Assessment.

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Agenda Item 13 — MPRR209 - Change Start-Up Offer from Daily to Hourly Jim Flucke (KCPL) introduced MPRR209 (Attachment 14 - MPRR 209 Recommendation Report), which changes Start-Up Offer from a daily parameter to an hourly parameter, just as the previously approved MPRR191 changed Start-Up Time from daily to hourly. It is recommended that MPRR209, if approved here, and MPRR191 be implemented together. Jim Flucke (KCPL) made a motion and Lee Anderson (LES) seconded to approve MPRR209 as submitted. The motion passed with no opposition and two abstentions (CUS, AEP). Agenda Item 14 — MPRR210 - Sync to Min Costs in Mitigated Start-Up Offer Jim Flucke (KCPL) introduced MPRR210 (Attachment 15 - MPRR 210 Recommendation Report), which proposes to add calculations to Appendix G that support inclusion of the fuel costs from synchronization to minimum output and to offset those costs with an estimate of the corresponding market revenues, which decreases the risk in the current design in which the LMP may or may not cover all of the startup fuel costs. This MPRR was approved by the MOTF-2014 and recommended to MWG. There was some discussion about the possibly risk of compliance issues with this functionality and whether or not the benefit is worth that risk. Richard Ross (AEP) made a motion and Shawn McBroom (OGE) seconded to reject MPRR210. The motion passed with one opposition (KCPL) and four abstentions (Tenaska, Westar, Xcel, OPPD). Agenda Item 15 — MPRR211 - Self-Commit Run Time Make Whole Payment Exemption Jim Flucke (KCPL) introduced MPRR211 (Attachment 16 - MPRR 211 Self-Commit Run Time Make Whole Payment Exemption_MWG), which proposes a design correction one of the market manipulation risks the SPP Market may have related to resources which are self-committed with multi-day minimum run times. This potential risk was exposed and discussed in December 2013 when SPP MMU made a presentation to the MWG regarding FERC’s investigation into JP Morgan’s activities in other RTO Markets. The presentation included an assessment of the SPP Market risk(s) related to FERC’s investigation. The current risk being addressed by MPRR211 is related to the fact that Resources with a single hour of Self commitment aren’t eligible for make whole payments for the full day, but a self-committed resource with multiple days of minimum run time could self-commit for the first day, and the market would have to pay make whole payments for all subsequent days of the min run time. The submitter of this MPRR proposes that when making a decision to self-commit resources, Market Participants should be fully responsible for all the subsequent costs that aren’t recovered from the LMP payment during the minimum run time because the market cannot decommit the unit during this time. Furthermore, Make Whole Payments should be paid by the market when the market makes a commitment decision, not when the Market Participant makes a commitment decision that the market cannot change. There was much discussion amongst MWG Members, Stakeholders and SPP Staff about how exactly the Marketplace handles self-commits and market commits across days, etc., and the decision was made to table this MPPR for now, with direction to SPP Staff via an MWG Action Item to bring details and examples to MWG showing how self-commits and market commits are handled with regard to make whole payment eligibility periods, and discuss possible options for changing the market design.

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Agenda Item 16 — MPRR216 - Regulation Qualification Raleigh Mohr (SPP) introduced MPRR216 (Attachment 17 - MPRR 216 Recommendation Report), which proposes changes to the regulation qualification testing requirements for resources. The current language does not allow self-certification for MP’s resources that have to regulate at a BA level or inside other markets. This MPRR provides a streamline process for resources coming into the Integrated Marketplace hat have historical data available which proves their ability to regulate. This revision will allow MPs to provide historical data and/or internal testing to certify for regulation within the SPP Marketplace. Richard Ross (AEP) made a motion and Neal Daney (KMEA) seconded to approve MPRR216 with SPP Regulatory Legal Comments and as modified in the meeting. The motion passed with no opposition and no abstentions. Agenda Item 17 — MPRR217 - Regulation Certification Testing Procedure This item was tabled due to time constraints. Agenda Item 18 — MPRR220 - Poor Regulation Performance Disqualification Raleigh Mohr (SPP) introduced MPRR220 (Attachment 19 - MPRR 220 Poor Regulation Performance Disqualification), which adds back language that was removed in MPRR65. The removed language provided for a mechanism allowing SPP to disqualify poor performance regulators from being able to provide regulation. The reason behind MPRR 65 was to “relax the requirements for Resources to pass a retest if they are disqualified from providing Operating Reserve or if their ability to provide Operating Reserve has been reduced by SPP as a result of performance during normal Regulation Deployment and Contingency Reserve Deployment events”, but the unintended consequences was the removal of language that provided SPP its only mechanism for disqualifying Resources as Regulating Resources based on poor performance. This is not believed to be the intent of MPRR 65, and SPP needs a mechanism in which it may disqualify a Resource from being a Regulating Resource based on historically consistent poor regulating response performance. The group had many questions around the exact process or procedure that would be used to enforce this language and therefore decided to table this MPRR for now, pending the addition by the MPRR submitter of additional procedural detail and clarifying language. Agenda Item 19 - MPRR218 - Market Registration Naming Conventions This item was tabled due to time constraints. Agenda Item 20 — MPRR221 - Transitional ARR Allocation Process Charles Cates (SPP) introduced MPRR221 (Attachment 20 - MPRR 221 Recommendation Report), which proposes Protocol and Tariff changes to allow for a new transitional ARR Allocation that will give new Transmission Owners who are unable to participate in an Annual TCR Auction, the opportunity to receive ARRs prior to the Monthly ARR Allocation. Charles reminded the group that this MPRR reflects the decisions by the MWG regarding a generic transitional ARR Allocation process that is what will be used for the IS Integration, as well as other entities in the future who come into SPP at a date when they are not able to participate in a full TCR auction. A question was asked if this new allocation process could result in underfunding and Charles answered that yes, the normal underfunding could occur. Shawn

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McBroom (OGE) made a motion and Ron Thompson (NPPD) seconded to approve MPRR221 as modified in the meeting and with direction to SPP Staff to make conforming changes to the Tariff. The motion passed with no opposition and no abstentions. Agenda Item 21 — TCR Process Calendar Adjustments Charles Cates (SPP) made the group aware of some adjustments to the TCR calendar, with the main one being to satisify a request from MPs to post results before the last day of the month instead of one the last of the month (Attachment 21 - MP Guide_SPP 2014 Congestion Hedging.v3). Agenda Item 22 — Outage Language in TCR Market Modeling Practices Charles Cates (SPP) made the group aware that the TCR modeling practices have been updated to reflect the new practice for outage scheduling decided on in the last MWG meeting. He also clarifiied that this new practice will go into effect beginning with the January 2015 auction (Attachment 22 - TCR Market Modeling Practices). Agenda Item 23 — MPRR181 - Mirrored JOU Share Option This item was tabled due to time constraints. Agenda Item 24 — MPRR222 - Remove Maximum & Minimum Limitation for Self Scheduled Resources Amber Metzker (Xcel) introduced MPRR22 (Attachment 23 - MPRR 222 Recommendation Report), which will allow market participants to submit a resource into the market with an economic maximum of zero MWs. This is a validation change only and does not require any Protocol or Tariff changes. Amber pointed that her main goal is to just get this added back to the software enhancement list, and is using the MPRR process to get the request into the SPP Stakeholder process, since there is currently not a mechanism for putting software changes such as this through the stakeholder process. This MPRR, if approved, will go to MOPC as an indication to SPP that this is something that MPs want, and it can therefore be put on a quarterly change report and it cannot be removed. Casey Cathey (SPP) clarified for the group that SPP Operations did remove this as a software change and documented the reasons for the removal. SPP Operations believes that the MPs should use the Market statuses of “not participating” or “outage” to reflect when a unit’s forecast is at zero. The status more accurately reflects the state of the unit than submitting a max of zero. Amber and other MPs report that the use of “not participating” increases risk of error and is administratively laborious, and that is the main reason for requesting this validation change. Amber did request expedited treatment of MPRR22, and the following two votes were recorded for this MPPR:

• Shawn McBroom (OBE) made a motion and Amber Metzker (Xcel) seconded to treat MPRR222 as expedited. The motion passed with no opposition and no abstentions.

• Amber Metzker (Xcel) made a motion and Jim Flucke (KCPL) seconded to approve MPRR222 as

modified in the meeting with a ranking of medium. The motion passed with no opposition and one abstention (OMPA).

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Agenda Item 25 — MWG Initiatives Prioritization Gay Anthony (SPP) presented the results of the MWG Members’ prioritization of MWG initiatives (Attachment 24 - MWG Initiatives Prioritization_MWG). The purpose of this effort is to give SPP Market Design staff an indication of the priority order of the items in case Staff is not able to be working on all of the initiatives at the same time. SPP Staff will bring the list back up at the December MWG meeting for more discussion. Agenda Item 26 — MMU Marketplace Update Catherine Tyler Mooney presented the MMU Marketplace Update and answered questions from the group (Attachment 25 - 201410 MWG MMU Market Update). Agenda Item 27 — RTO Marketplace Update Casey Cathey (SPP) presented specific commentary on slides 6 and 7 of the RTO Marketplace Update (Attachment 26 - November RTO Update) and pointed out to the group that the remaining slides consist of the standard data sections of the RTO Marketplace Update. Those standard sections can be considered as a “written report” for the MWG Members and Stakeholders to review on their own and let Casey know if they have any questions. Casey’s commentary on slide 6, which points out that there is now no MCP price separation among Reserve Zones, is reflective of recent upgrades resulting in the fact that we no longer have to carry a minimum threshold. Casey’s commentary on slide 7, which points out unit commitment improvement in Marketplace vs. EIS Market, is that there are lots of assumptions and caveats with showing the Marketplace benefit using this data and the huge differences between Marketplace and EIS. Casey reported that SPP Staff is in the process of trying to quantify the benefits of Marketplace. An MWG Action Item was recorded for SPP Staff to present at the December 2014 MWG meeting a draft of the analysis results and presentation on Marketplace benefits, including assumptions. This will give MWG a chance to see the data and assumptions before the final report goes to MOPC and BOD in January, 2015. Agenda Item 28 — RTBM Availability Analysis Annette Holbert (SPP) presented a report on the RTBM availability for the first 8 months of the Marketplace (Attachment 27 - Marketplace Availability Update_Nov2014). The results of the analysis show better than target availability on all critical systems, and Annette reported that SPP Staff is pleased with availability to date and feel this is a success story. Roy True (ACES) complimented SPP IT on this data and on the great job regarding availability. Amber Metzker (Xcel) asked a question regarding October 17 event shown in the data where there was a problem with shared shortage. Amber would like to know the communication process for that type of outage. She reported that Xcel was on the blast call for that and was disconnected and had no information on how to get back on. In response to Amber’s question, Jodi Wood (SPP) and Casey Cathey (SPP) reported that SPP Staff is working on improvements to the blast call and communication process. An MWG Action Item was recorded for SPP Staff to document improvements to the blast call/MP communication process and to report back to the MWG on the status and progress of the improvements.

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Agenda Item 29 — Regulatory Report This item was not verbally presented due to time constraints (Attachment 28 - 2014 11 Regulatory Report to MWG), but MWG Members and Stakeholders are encouraged to submit any questions they may have regarding this report. Agenda Item 30 - Review of Motions, Action Items and Future Meetings

Motions: Agenda Item 5 – MPRR212-Over Collected Losses Design Change – Implementation Prioritization Amber Metzker (Xcel) made a motion and Ann Scott (Tenaska) seconded to bundle MPRR212 with MPRR206 and continue to work towards a 4/1/15 implementation date. The motion passed with one opposition (AEP) and no abstentions. Agenda Item 7 – Must Offer – MOPC Action Item #225 Matt Moore (GSEC) made a motion and Amber Metzker (Xcel)) seconded to recommend to MOPC that no action be taken on Day-Ahead Must Offer until the deadline of reporting to FERC on how the Day-Ahead Must Offer is working, which is a report in 15 months after Marketplace go-live with 12 months of Market data. The motion passed with three oppositions (AEP, EDE, CUS) and seven abstentions (NPPD, LES, OGE, Westar, Tenaska, Midwest, Boston Energy). Richard Ross (AEP) made a motion and Rick McCord (EDE) seconded to advise MOPC that the MWG recommendation at this time is that having no Day-Ahead must offer is a better solution than the current limited Day-Ahead Must Offer. Therefore, there is no need to address changes to the current Day-Ahead must offer design at this time. The motion passed with two oppositions (GSEC, Xcel) and two abstentions (KMEA, AECC). Agenda Item 8 – MPRR223 - SPP Conservative Operations During Multi-Day RUC Ron Thompson (NPPD) made a motion and Rick McCord (EDE) seconded to treat MPRR223 as expedited. The motion passed with no opposition and one abstention (AEP). Richard Ross (AEP) made a motion and Cliff Franklin (Westar) seconded to approve MPRR223 as submitted. The motion passed with one opposition (OGE) and one abstention (GSEC). Agenda Item 13 – MPRR209 – Change Start-Up Offer from Daily to Hourly Jim Flucke (KCPL) made a motion and Lee Anderson (LES) seconded to approve MPRR209 as submitted. The motion passed with no opposition and two abstentions (CUS, AEP). Agenda Item 14 – MPRR210 – Sync to Min Costs in Mitigated Start-Up Offer Richard Ross (AEP) made a motion and Shawn McBroom (OGE) seconded to reject MPRR210. The motion passed with one opposition (KCPL) and four abstentions (Tenaska, Westar, Xcel, OPPD).

Minutes No. [238]

Agenda Item 16 – MPRR216 – Regulation Qualification Richard Ross (AEP) made a motion and Neal Daney (KMEA) seconded to approve MPRR216 with SPP Regulatory Legal Comments and as modified in the meeting. The motion passed with no opposition and no abstentions. Agenda Item 20 – MPRR221 – Transitional ARR Allocation Process Shawn McBroom (OGE) made a motion and Ron Thompson (NPPD) seconded to approve MPRR221 as modified in the meeting and with direction to SPP Staff to make conforming changes to the Tariff. The motion passed with no opposition and no abstentions. Agenda Item 24 – MPRR222 – Remove Maximum and Minimum Limitation for Self Schedule Resources Shawn McBroom (OBE) made a motion and Amber Metzker (Xcel) seconded to treat MPRR222 as expedited. The motion passed with no opposition and no abstentions. Amber Metzker (Xcel) made a motion and Jim Flucke (KCPL) seconded to approve MPRR222 as modified in the meeting with a ranking of medium. The motion passed with no opposition and one abstention (OMPA). Action Items:

• From the Day-Ahead Market headroom agenda item, SPP Staff to perform analysis and report

results back to MWG on how things would clear with more headroom in DA, including affects to the number of RUC commitments and make whole payments.

• From the MPRR211 (Self-Commit Run Time Make Whole Payment Exemption) SPP Staff will bring details and examples to MWG showing how self-commits and market commits are handled with regard to make whole payment eligibility periods, and discuss possible options for changing the market design.

• From the RTBM availability agenda item, SPP Staff to document improvements to the blast call/MP communication process and to report back to the MWG on the status and progress of the improvements.

• From the RTO Marketplace Update agenda item, SPP Staff to present at the December 2014 MWG a draft of the analysis results and presentation on Marketplace benefits, including assumptions; this gives MWG a chance to see the data and assumptions before the final report goes to MOPC and BOD in January,2015.

Future Meetings: December 2, 2014 (2:00 p.m. – 4:00 p.m.) MOPC – Special Meeting Location: Net Conference

Minutes No. [238]

December 10, 2014 (8:00 a.m. – 12:00 p.m.) MWG/CAWG Joint Meeting Location: Net Conference December 16, 2014 (8:15 a.m. – 6:00 p.m.) December 17, 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. Agenda Item 32 — MPRR126 - Real-Time Regulation Make Whole Payment This item was tabled. Agenda Item 33 — MPRR213 – Default VOM for Mitigated Offers This item was tabled.

Agenda Item 34 – Adjournment Gene Anderson (OMPA) adjourned the meeting at 12:05 p.m.

Respectfully Submitted, Debbie James Secretary Attachments Attachment 1 - MWG Attendance November 18-19 2014 Attachment 1a - Marguerite Wagner Proxy Attachment 2 - MWG Agenda for November 18-19 2014 Attachment 3 - MWG Oct 21-22 2014 Minutes Attachment 4 - 2015 MOPC MPRR Schedule Attachment 5 - Action items related to Order 681 LTCR Filing Attachment 6 - Schedule for LTCR filing Attachment 7 - MPRR Prioritization-MWG-1 Attachment 8 - MOPC Action Item 225 - Day-Ahead Must Offer Attachment 9 - MPRR 223 Recommendation Report

Minutes No. [238]

Attachment 10 - Hub Activity Attachment 11 - MPRR 219 TCR Shortpay Calculation Correction Attachment 12 - Absolute Revenue Shortfall Slide Deck Attachment 13 - MPRR 207 Staggered Start-Up Time Attachment 14 - MPRR 209 Recommendation Report Attachment 15 - MPRR 210 Recommendation Report Attachment 16 - MPRR 211 Self-Commit Run Time Make Whole Payment Exemption_MWG Attachment 17 - MPRR 216 Recommendation Report Attachment 18 - MPRR 216 and 217 Attachment 19 - MPRR 220 Poor Regulation Performance Disqualification Attachment 20 - MPRR 221 Recommendation Report Attachment 21 - MP Guide_SPP 2014 Congestion Hedging.v3 Attachment 22 - TCR Market Modeling Practices Attachment 23 - MPRR 222 Recommendation Report Attachment 24 - MWG Initiatives Prioritization_MWG Attachment 25 - 201410 MWG MMU Market Update Attachment 26 - November RTO Update Attachment 27 - Marketplace Availability Update_Nov2014 Attachment 28 - 2014 11 Regulatory Report to MWG

3/26/2015

MOPC Meeting Materials due date

4/3/2015

MWG Meeting before MOPC for MPRRs

3/17/2015

ORWG Meeting before MOPC for MPRRs

Apr-14

RTWG Meeting before MOPC for MPRRs

2/24/2015

MPRR Posting Deadline for Non-Expedited

2/27/2015

MPRR April 2015 MOPC Internal Schedule

MPRR Submission Deadline for Non-Expedited

1

MPRRs going to April 2015 MOPC

2014 2013 2012 2011 2010 2009 2014 2013 2012 2011 2010 *2009Business Practices Working Group 55% 71% 60% 64% 82% n/a 4.4 4.4 4.2 4.3 4.6 3.8Change Working Group 52% 63% 61% 44% 65% 38% 4.2 4.1 3.9 4.3 4.2 3.3Corporate Governance Committee 88% 100% 88% 88% 75% 43% 4.9 4.5 4.7 4.4 4.5 3.2Cost Allocation Working Group 25% 67% 67% 50% 33% 27% 5.0 4.7 4.3 3.8 4.0 3.3Credit Practices Working Group 78% 75% 80% 67% n/a n/a 4.4 4.0 4.5 4.0 n/a n/aCritical Infrastructure Protection Working Group 65% 53% 71% 75% 69% 27% 4.0 4.5 4.3 4.6 4.6 4.3Economic Studies Working Group #REF! #REF! #REF! 67% 71% 38% #REF! #REF! #REF! #REF! 3.9 4.3Finance Committee #REF! #REF! #REF! 86% 86% 30% #REF! #REF! #REF! #REF! 4.2 3.7Generation Working Group #REF! #REF! #REF! 22% 50% 38% #REF! #REF! #REF! #REF! 4.2 2.8Human Resources Committee #REF! #REF! #REF! 100% 86% 40% #REF! #REF! #REF! #REF! 4.3 3.3Market Working Group 47% 74% 41% 63% 81% 38% 4.7 3.9 4.1 4.3 4.2 3.2Markets and Operations Policy Committee #REF! #REF! #REF! 48% 47% 33% #REF! #REF! #REF! #REF! 3.9 3.2Model Development Working Group #REF! #REF! #REF! 100% 92% 48% #REF! #REF! #REF! #REF! 3.9 2.8Project Cost Working Group #REF! #REF! #REF! N/a N/a N/a #REF! #REF! #REF! N/a N/a N/aOperating Reliabilty Working Group #REF! #REF! #REF! 87% 77% 38% #REF! #REF! #REF! #REF! 4.2 3.6Operations Training Working Group #REF! #REF! #REF! 83% 92% 45% #REF! #REF! #REF! 4.6 4.7 3.7Oversight Committee #REF! #REF! #REF! 100% 100% 100% #REF! #REF! #REF! #REF! 4.8 3.5Project Cost Working Group #REF! #REF! #REF! N/a N/a N/a #REF! #REF! #REF! N/a N/a N/aRegional Compliance Working Group #REF! N/a N/a N/a N/a N/a #REF! N/a N/a N/a N/a N/aRegional Tariff Working Group #REF! #REF! #REF! 71% 67% 43% #REF! #REF! #REF! #REF! 4.2 3.5Seams Steering Committee #REF! #REF! #REF! N/a N/a N/a #REF! #REF! #REF! N/a N/a N/aStrategic Planning Committee #REF! #REF! #REF! 100% 92% 43% #REF! #REF! #REF! #REF! 4.2 3.1Systems Protection and Control Working Group #REF! #REF! #REF! 77% 77% 38% #REF! #REF! #REF! #REF! 3.5 3.6Transmission Working Group #REF! #REF! #REF! 79% 67% 41% #REF! #REF! #REF! #REF! 4.0 3.4

Average #### #REF! #REF! 74% 74% 42% #### #### #### #### 4.2 3.5

Every score across all groups and questions was 3.0 or higher.

2014 Organizational Group Survey Analysis

Group

* Note: Overall effectiveness was measured in a different way in 2009

Overall effectivenessResponse rate

OverviewRespondents were asked to select a score from 1 - 5 with 1 being a strong disagreement to the statement and 5 being a strong agreement with statement.

The table below shows overal response rates and overall effectiveness scores by Organizational Group in alphbetical order. Many group responses rates were down this year, and the average response overall is the lowest in five years.Overall average effectiveness is 4.4, which is a new record

Business Practices Working Group 2014 2013 2012 2011 2010Number of members 11 7 10 11 11

Number of responses 6 5 6 7 9Response rate 55% 71% 60% 64% 82%

Overall effectiveness score 4.4 4.4 4.2 4.3 4.6Lowest scoreHighest score

2014 2013 2012 2011 2010The agenda reflects the actions to be taken during the meeting. 4.8 4.4 4.0 4.1 4.2Meeting materials are provided in a timely manner. 4.3 4.4 4.0 4.0 4.1The information provided prior to the meeting is utilized during the meeting. 4.8 4.5 4.3 4.1 4.2The information presented in meetings is clear. 4.7 4.3 4.2 n/a n/aMeeting minutes are an accurate reflection of the meeting. 4.8 4.4 4.3 4.1 4.2

Membership represents the diversity of the SPP organization. 4.3 4.0 4.2 4.3 4.1Membership has the necessary expertise and/or skills to accomplish its goals. 4.3 4.4 4.3 4.0 4.1Members come prepared to meetings. 4.3 4.0 4.2 3.4 3.8Members are committed to participate and accomplish the group's goals. 4.5 4.0 4.3 3.9 4.3Members are supportive and respectful of the individual needs and differences of group members. 4.5 4.6 4.3 4.3 4.3

Members are engaged during the meeting. 4.3 4.0 4.2 4.0 4.2Decisions are identified and action is recommended. 4.8 4.4 4.0 4.1 4.1Facilitation is sufficient to guide discussion. 4.7 4.4 4.0 4.1 3.9

Dissenting voices are heard. 4.8 4.6 4.2 4.0 3.9I depart with a feeling that we have accomplished something. 4.5 4.4 4.0 4.0 4.2

The chair seeks input, and organizational group members are able to influence key decisions and plans. 4.8 4.4 4.8 4.4 4.3The chair is supportive and respectful of the individual needs and differences of group members. 4.8 4.6 4.5 4.6 4.2The chair keeps the group on task to achieve appropriate outcomes. 4.8 4.4 4.5 4.1 4.1The chair ensures follow-through on questions and commitments. 4.8 4.5 4.5 4.3 4.2

Question

Please provide three or more recommendations for improvement of this particular group and/or SPP's overall organizational group structure

Additional comments:

Additional comments:

Item #3. Meeting materials not consistently provided to Secretary in a timely manner for public posting.

Additional comments:

Additional comments:

Average score

Well organized group.

Better coordination among organizational groups. Groups often schedule meetings that conflict with other SPP organizational group meetings. Likewise, many groups have common members, but meeting are scheduled on consecutive days in different cities.

Other comments

Change Working Group 2014 2013 2012 2011 2010Number of members 33 35 41 41 20

Number of responses 17 22 25 18 13Response rate 52% 63% 61% 44% 65%

Overall effectiveness score 4.2 4.1 3.9 4.3 4.5Lowest scoreHighest score

2014 2013 2012 2011 2010The agenda reflects the actions to be taken during the meeting. 4.4 4.3 4.2 4.0 4.5Meeting materials are provided in a timely manner. 4.0 3.5 3.5 3.7 4.2

The information provided prior to the meeting is utilized during the meeting. 4.4 4.3 4.1 4.1 4.1The information presented in meetings is clear. 4.2 4.1 3.9 n/a n/aMeeting minutes are an accurate reflection of the meeting. 4.4 4.4 4.0 3.9 4.4

Membership represents the diversity of the SPP organization. 4.3 4.3 4.3 4.1 3.8

Membership has the necessary expertise and/or skills to accomplish its goals. 4.4 4.3 4.1 3.6 3.8Members come prepared to meetings. 3.8 3.7 3.6 3.3 3.9Members are committed to participate and accomplish the group's goals. 4.2 4.1 3.7 3.5 4.1Members are supportive and respectful of the individual needs and differences of group members. 4.5 4.4 4.2 3.9 4.4

Members are engaged during the meeting. 3.9 3.9 3.7 3.6 4.2Decisions are identified and action is recommended. 4.1 4.0 3.9 3.7 4.5Facilitation is sufficient to guide discussion. 4.1 4.2 4.1 4.0 4.4Dissenting voices are heard. 4.2 3.7 4.1 3.8 4.3I depart with a feeling that we have accomplished something. 3.8 4.5 3.7 3.4 4.3

The chair seeks input, and organizational group members are able to influence key decisions and plans. 4.2 4.5 4.3 4.1 4.5The chair is supportive and respectful of the individual needs and differences of group members. 4.4 4.6 4.5 4.3 4.6The chair keeps the group on task to achieve appropriate outcomes. 4.1 4.2 4.3 4.1 4.5The chair ensures follow-through on questions and commitments. 4.3 4.2 4.4 4.1 4.6

More engagement from members and market participants who are not currently represented on the CWG.

1- More use of net-conferences when practical to avoid travel expenses and time away from office.

Please provide three or more recommendations for improvement of this particular group and/or SPP's overall organizational group structure

Some sort of documentation/training for new members would be of benefit - showing how the CWG fits in the SPP structure and how what we do affects the organization as a whole. (i.e. CWG recommends an action, MWG votes on it, goes to MOPC, etc.)I would like to spend more time in the group before making any recommendations for improvements. 1. Currently I am attending this meeting and the MWG. It is nice that the meetings are scheduled back - to - back but it would be nice if they were in the same location to eliminate having to travel in between meetings and check into an additional hotel. 2. 1. I like having the meetings in Dallas due to the fact that it is a direct flight but I find it more valuable to have SPP staff available at the meetings and think it may be unproductive to have many of them fly to dallas when they have a good facility in Little Rock. 3. We get to interact with SPP staff quite often. Staff will tell us their job title and what their job somewhat encompasses, but looking at it from the Operational perspective, it would be nice to see where they are in the SPP org Chart. Who do they supervise or who is their supervisor.

I have been on the CWG for less than a year and find that the group performs well and is aware of agenda timelines and has opted for net conferences several times to avoid unnecessary trips to Dallas. I have enjoyed the group thus far.

Would like to see more meetings in Little Rock in 2015.

Please announce changes in face to face meeting schedules as far as advance as possible. Most people make flight reservations more than 2 weeks in advance.

Other comments

Average score

Additional comments:

Additional comments:

Additional comments:I very much enjoy working with this group of members.

Question

Additional comments:It would be great if Agendas could be distributed a little further in advance, as well as determining if meetings will be held face-to-face or net conference. Travel cancellation fees can be costly, as well as waiting to book when agenda is distributed.Timeliness of materials are improving as the backlog of project especially Integrated Marketplace have slowed.

Most CWG meetings are a waste of time.I believe there are, at times, side conversations that would benefit the whole group, as well as members working together outside the group would benefit as a whole as well.Their haven't been many decisions and recommendations since I joined the committee.

Corporate Governance Committee 2014 2013 2012 2011 2010Number of members 8 8 8 8 8

Number of responses 7 8 7 7 6Response rate 88% 100% 88% 88% 75%

Overall effectiveness score 4.9 4.5 4.7 4.4 4.5Lowest scoreHighest score

2014 2013 2012 2011 2010The agenda reflects the actions to be taken during the meeting. 4.7 4.3 4.7 4.4 4.5Meeting materials are provided in a timely manner. 4.6 4.4 4.6 4.4 4.3The information provided prior to the meeting is utilized during the meeting. 4.4 4.3 4.6 4.1 4.5The information presented in meetings is clear. 4.4 4.3 4.4 n/a n/aMeeting minutes are an accurate reflection of the meeting. 4.7 4.5 4.4 4.9 4.5

Membership represents the diversity of the SPP organization. 4.9 4.7 4.7 4.4 4.5Membership has the necessary expertise and/or skills to accomplish its goals. 4.6 4.5 4.6 4.6 4.3Members come prepared to meetings. 4.7 4.5 4.7 4.6 4.2Members are committed to participate and accomplish the group's goals. 4.9 4.6 4.7 4.6 4.3Members are supportive and respectful of the individual needs and differences of group members. 4.7 4.5 4.7 4.4 4.5

Members are engaged during meetings. 4.9 4.5 4.4 4.3 4.0Decisions are identified and action is recommended. 4.7 4.5 4.6 4.4 4.3Facilitation is sufficient to guide discussion. 4.7 4.6 4.7 4.6 4.5Dissenting voices are heard. 4.7 4.6 4.7 4.6 4.7I depart with a feeling that we have accomplished something. 4.7 4.3 4.6 4.4 4.2

The chair seeks input, and organizational group members are able to influence key decisions and plans. 4.7 4.6 4.7 4.5 4.6The chair is supportive and respectful of the individual needs and differences of group members. 4.7 4.6 4.7 4.5 4.6The chair keeps the group on task. 4.7 4.6 4.7 4.3 4.6The chair ensures follow-through on questions and commitments. 4.7 4.8 4.7 4.2 4.4

Additional comments:

In most circumstances, the group accomplishes its goal, especially with regard to making candidate recommendations. Sometimes items are brought before the group and it is not clear if the CGC is really the appropriate body to address the items, but the group does a good job of discussing the issue and determining the appropriate committee of jurisdiction.

Additional comments:

Additional comments:

Additional comments:

Other comments

Follow through on director succession.

When legal negotiation is required, the negotiation should be preparatory to the Committee meeting. Need to be constantly aware of processes that could lead to parochial power being used in the nomination processes.

Since I am a relatively new addition to the group, I appreciate hearing the history of how prior decisions were made and what events transpired that lead us to our current state.

Please provide three or more recommendations for improvement of this particular group and/or SPP's overall organizational group structure

Question

I continue to be impressed with the active engagement of the members and staff that participate in the meetings.

I think we have made valuable improvements to the material and formating of the information for candidates for committees and working groups.

Average score

Cost Allocation Working Group 2014 2013 2012 2011 2010Number of members 8 9 9 10 12

Number of responses 2 6 6 5 4Response rate 25% 67% 67% 50% 33%

Overall effectiveness score 5.0 4.7 4.3 3.8 4.0Lowest scoreHighest score

2014 2013 2012 2011 2010The agenda reflects the actions to be taken during the meeting. 5.0 4.8 4.9 4.2 3.8Meeting materials are provided in a timely manner. 4.5 4.5 4.3 3.2 2.5The information provided prior to the meeting is utilized during the meeting. 5.0 4.8 4.9 4.0 3.5The information presented in meetings is clear. 5.0 4.5 4.1 n/a n/aMeeting minutes are an accurate reflection of the meeting. 4.5 4.7 4.6 2.6 3.3

Additional comments: s

Membership represents the diversity of the SPP organization. 4.5 5.0 4.3 4.2 3.0Membership has the necessary expertise and/or skills to accomplish its goals. 4.5 4.8 4.0 4.0 3.3Members come prepared to meetings. 4.5 4.5 4.3 3.6 3.0Members are committed to participate and accomplish the group's goals. 4.5 5.0 4.4 4.0 3.5Members are supportive and respectful of the individual needs and differences of group members. 4.0 5.0 4.7 4.4 3.3

Members are engaged during the meeting. 4.0 4.5 4.3 3.8 3.8Decisions are identified and action is recommended. 4.5 4.8 4.7 4.2 3.5Facilitation is sufficient to guide discussion. 4.5 4.7 4.3 3.8 3.8

Dissenting voices are heard. 3.0 4.2 4.3 3.8 3.5I depart with a feeling that we have accomplished something. 4.0 4.7 4.1 4.2 2.8

The chair seeks input, and organizational group members are able to influence key decisions and plans. 5.0 5.0 4.8 3.8 3.3The chair is supportive and respectful of the individual needs and differences of group members. 5.0 5.0 4.6 3.8 3.0The chair keeps the group on task to achieve appropriate outcomes. 5.0 5.0 4.7 3.8 3.0The chair ensures follow-through on questions and commitments. 5.0 5.0 4.6 3.6 3.3

Additional comments:

Average score

Other comments

Question

Additional comments:

Additional comments:

Please provide three or more recommendations for improvement of this particular group and/or SPP's overall organizational group structure

Credit Practices Working Group 2014 2013 2012 2011 2010Number of members 9 8 10 6 N/a

Number of responses 7 6 8 4 N/aResponse rate 78% 75% 80% 67% N/a

Overall effectiveness score 4.4 4.0 4.5 4.0 N/aLowest score N/aHighest score N/a

2014 2013 2012 2011 2010The agenda reflects the actions to be taken during the meeting. 5.0 4.5 4.5 4.5 N/aMeeting materials are provided in a timely manner. 4.9 4.2 4.4 3.8 N/aThe information provided prior to the meeting is utilized during the meeting. 5.0 4.3 4.4 4.3 N/aThe information presented in meetings is clear. 4.6 4.0 4.3 n/a n/aMeeting minutes are an accurate reflection of the meeting. 5.0 4.0 4.4 4.3 N/a

Membership represents the diversity of the SPP organization. 4.3 3.5 3.9 4.0 N/aMembership has the necessary expertise and/or skills to accomplish its goals. 4.6 3.7 4.0 3.5 N/aMembers come prepared to meetings. 4.0 3.3 3.9 3.5 N/aMembers are committed to participate and accomplish the group's goals. 4.3 3.7 4.0 3.5 N/aMembers are supportive and respectful of the individual needs and differences of group members. 4.7 4.3 4.1 4.0 N/a

Members are engaged during the meeting. 4.4 3.5 4.0 3.8 N/aDecisions are identified and action is recommended. 4.4 3.8 4.3 4.0 N/aFacilitation is sufficient to guide discussion. 4.7 4.0 4.3 4.0 N/a

Dissenting voices are heard. 4.4 3.7 4.0 4.0 N/aI depart with a feeling that we have accomplished something. 4.3 3.7 4.3 4.0 N/a

The chair seeks input, and organizational group members are able to influence key decisions and plans. 4.5 4.3 4.6 4.0 N/aThe chair is supportive and respectful of the individual needs and differences of group members. 4.5 4.5 4.7 4.0 N/aThe chair keeps the group on task to achieve appropriate outcomes. 4.3 4.3 4.6 3.8 N/aThe chair ensures follow-through on questions and commitments. 4.3 4.3 4.6 4.3 N/a

Question

Additional comments:

Additional comments:

Additional comments:

Additional comments:

more opinions would be good

Average score

1. Solicit more topics of discussion from Market Participants. 2. Solicit guess speakers internally to SPP and external industry experts on credit topics. 3. Conduct an annual CPWG face-to-face meeting.

Other commentsI am relatively new to the group. The only change I have seen come through is the TCR collateral netting. It was executed quickly in response to market participants' wishes. I thought the CPWG did well handling the request.Scott Smith is an effective SPP representative for the CPWG.

Please provide three or more recommendations for improvement of this particular group and/or SPP's overall organizational group structure

I think the biggest improvement would come from increased member participation.

the timeliness of system implementations for CPWG is not very fast, but not sure if there is an opportunity to improve given bottleneck of all SPP projects.

Critical Infrastructure Protection Working Group 2014 2013 2012 2011 2010Number of members 17 17 17 16 16

Number of responses 11 9 12 12 11Response rate 65% 53% 71% 75% 69%

Overall effectiveness score 4.0 4.5 4.3 4.8 4.6Lowest score Highest score

2014 2013 2012 2011 2010The agenda reflects the actions to be taken during the meeting. 4.6 4.6 4.6 4.8 4.6Meeting materials are provided in a timely manner. 4.6 4.3 4.5 4.4 4.4The information provided prior to the meeting is utilized during the meeting. 4.6 4.3 4.5 4.5 4.5The information presented in meetings is clear. 4.6 4.3 4.6 n/a n/aMeeting minutes are an accurate reflection of the meeting. 4.5 4.6 4.5 4.7 4.5

Membership represents the diversity of the SPP organization. 4.4 4.2 4.4 4.5 4.3Membership has the necessary expertise and/or skills to accomplish its goals. 4.4 4.6 4.6 4.7 4.3Members come prepared to meetings. 4.2 4.1 4.4 4.3 4.2Members are committed to participate and accomplish the group's goals. 4.3 4.3 4.5 4.7 4.5Members are supportive and respectful of the individual needs and differences of group members. 4.6 4.6 4.7 4.7 4.6

Members are engaged during the meeting. 4.4 4.7 4.5 4.7 4.5Decisions are identified and action is recommended. 4.3 4.2 4.5 4.5 4.3Facilitation is sufficient to guide discussion. 4.6 4.4 4.6 4.6 4.5

Dissenting voices are heard. 4.6 4.4 4.4 4.6 4.5I depart with a feeling that we have accomplished something. 4.1 4.1 4.3 4.5 4.6

The chair seeks input, and organizational group members are able to influence key decisions and plans. 4.6 4.5 4.5 4.8 4.9The chair is supportive and respectful of the individual needs and differences of group members. 4.6 4.8 4.5 4.8 4.9The chair keeps the group on task to achieve appropriate outcomes. 4.5 4.5 4.4 4.7 4.7The chair ensures follow-through on questions and commitments. 4.5 4.6 4.5 4.8 4.6

This group is already doing an amazing job!

This group is doing a very good job of staying on top of the cyber security issues. Changes seem to be never ending and challenges to staff on cyber security get more difficult. This working group is a very valuable resource to our utility.

1) Ask for CIP v5 interpretations from the group and work with the SPP-RE to ensure that the SPP and the entities agree. 2) We need more discussion on Low Impact Physical Security. This will include the required controls, how people are meeting them, and cost effective solutions for those entities that may still need more controls.

Other commentsMeetings are concluded with meeting summarization, made decisions, delegation of task, deadlines and required actions by members.

These comments are specific to Robert McClanahan and not the new chair. We need to insure the chair and vice chair positions have some diversity in experience and companies that they represent.

The Chair is an excellent meeting leader and facilitator. He always sets the meeting tone and ties discussions together between interrelated topics.

Diversity in leadership of this group in experience and company representation.

Please provide three or more recommendations for improvement of this particular group and/or SPP's overall organizational group structure

Additional comments:

Additional comments:

Productive discussions. Everyone has a chance of being heard.

Though the discussions are great, there are rarely action items. However, this group started the CIP v5 Transition User Group, which has been beneficial.

Question

Additional comments:

Good allocation of time. Well organized for attaining objectives. The agenda is structured to provide for direction and focus.The CIPWG Secretary does an excellent job in ensuring that meeting materials are provided in a timely fashion.

Additional comments:

Average score

Market Working Group 2014 2013 2012 2011 2010Number of members 19 19 17 16 16

Number of responses 9 14 7 10 13Response rate 47% 74% 41% 63% 81%

Overall effectiveness score 4.7 3.9 4.1 4.3 4.2Lowest scoreHighest score

2014 2013 2012 2011 2010The agenda reflects the actions to be taken during the meeting. 4.6 4.3 4.1 4.6 4.3Meeting materials are provided in a timely manner. 3.8 3.4 4.1 4.0 3.7The information provided prior to the meeting is utilized during the meeting. 4.4 4.1 4.3 4.4 4.3The information presented in meetings is clear. 4.2 4.2 4.1 n/a n/aMeeting minutes are an accurate reflection of the meeting. 4.7 4.2 4.1 4.1 4.2

Additional comments:

Membership represents the diversity of the SPP organization. 4.4 4.3 4.0 4.5 4.2Membership has the necessary expertise and/or skills to accomplish its goals. 4.4 4.3 4.1 4.4 3.9Members come prepared to meetings. 4.1 3.6 3.9 4.1 3.5Members are committed to participate and accomplish the group's goals. 4.4 4.0 4.1 4.4 3.9Members are supportive and respectful of the individual needs and differences of group members. 4.3 4.1 4.3 4.5 4.2

Members are engaged during the meeting. 4.2 3.9 4.0 4.3 3.8Decisions are identified and action is recommended. 4.6 4.2 4.1 4.4 4.1Facilitation is sufficient to guide discussion. 4.4 4.3 4.1 4.4 4.1Dissenting voices are heard. 4.2 4.2 4.1 4.4 4.3I depart with a feeling that we have accomplished something. 4.3 4.1 4.0 4.2 4.0

Additional comments:

The chair seeks input, and organizational group members are able to influence key decisions and plans. 4.4 4.2 4.3 4.3 4.4The chair is supportive and respectful of the individual needs and differences of group members. 4.1 4.1 4.0 4.5 4.3The chair keeps the group on task to achieve appropriate outcomes. 4.6 4.4 4.6 4.5 4.3The chair ensures follow-through on questions and commitments. 4.6 4.3 4.4 4.5 4.4

Additional comments:

The Chair and Vice-Chair of the MWG do a great job of facilitating the meetings to keep us moving through the many technical discussions.

Question

Would like to see meeting materials out sooner and get them as they are ready. Not all at one time shortly before the meeting.

Additional comments:

Average score

Accomplished with a lot of items still on the groups plate. This group requires a great deal of work for the members.

Very good Group with a diverse knowledge base. Do believe they look at the betterment of SPP overall at the same time analysis the impact to their company when determining what is best. At times a middle ground can be found

MWG meetings have a good discussion. Some members are not as vocal as others

Other comments

1. Get materials out sooner if possible 2. At times the room is to small however we seem to be able to manage it 3. Phone system could be better however improvement would enhance less face to face by Members 4. A short summary of topics to be discussed provided before the meeting would be helpful 5. Webcast for the MOPC meeting would be helpful. Everyone is interested however each entity only sends one or two to be face to face. Hard to keep on track on the phone without Webcas. Me being on the MWG as a member being on the call for MOPC helps me in future MWG meetings

1. I like having the meetings in Dallas due to the fact that it is a direct flight but I find it more valuable to have SPP staff available at the meetings and think it may be unproductive to have many of them fly to dallas when they have a good facility in Little Rock. 2. I appreciate AEP hosting the MWG meetings at their building in Dallas, but many times the room is very full. Maybe room could be larger or tables better situated. 3. We get to interact with SPP staff quite often. Staff will tell us their job title and what their job somewhat encompasses, but looking at it from the Operational perspective, it would be nice to see where they are in the SPP org Chart. Who do they supervise or who is their supervisor.

Please provide three or more recommendations for improvement of this particular group and/or SPP's overall organizational group structure

I would like to see a ranking of goals and accomplishments on a regular basis. Sometimes we can get derailed during a meeting on a MPRR that may have less of a financial impact to its members. It is challenging at times because all members have different resource mixes, different agendas and it is challenging to stay on task at times. With that being said, the group as a whole does an effective job of reviewing the information, providing input and pushing decisions along to other SPP org groups.The MWG is very effective and I do not have any recommendations for improvement.

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Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 2 of 59

revisions related to receiving Incremental LTCRs from Sponsored Upgrades requires modifications to Attachments J, O, and Z2 of the Tariff to allow for a Transmission Planning study process to take place which will grant candidate Incremental LTCRs in lieu of Z2 credits. Modifications to the Protocols and Attachment AE of the Tariff are required to define the process for candidate Incremental LTCRs to be included in the LTCR and TCR processes.

To comply with Guideline (5), changes were made to the Protocols and Attachment AE to allow LTCRs and Incremental LTCRs to be nominated prior to the Simultaneous Feasibility Test (SFT) instead of selecting LTCRs after the SFT.

Tariff Implications or Changes

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

I. Common Service Provisions: 1. Definitions

Attachment J: V. Other Network Upgrades Schedule 1 to Attachment J

Attachment Z2: I. Creditable Upgrade IV. Incremental LTCRs

Attachment AE: 7.0 Transmission Congestion Rights Markets 7.1 Annual Long-Term Congestion Right/Auction Revenue Right and Incremental LTCR Verification 7.1.1 Transmission Service and Incremental Long-Term Congestion Rights Verification 7.1.2 Candidate Long-Term Congestion Rights/Auction Revenue Rights 7.2 Annual Long-Term Congestion Right Allocation 7.2.1 LTCR and ILTCR Surrender 7.2.2 LTCR and ILTCR Nomination 7.2.3 Available Long-Term Congestion Rights for Load Serving Entities 7.2.4 Available Long-Term Congestion Rights for Load Serving Entities 7.2.5 LTCR and ILTCR Awards 7.3 Annual Auction Revenue Right Allocation 7.3.3 Annual Auction Revenue Right Awards

No

Criteria Impact or Changes

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

No

MWG Review PRR Recommendation

Date of Vote: 12/16/2014 Vote: Approved with modifications

Opposed: Westar

Abstained: N/A

RTWG Review Date of Vote: Vote:

ORWG Review Date of Vote: Vote:

MOPC Recommendation Date of Vote: Vote:

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 3 of 59

Board Review Date of Vote: Vote:

Date 12/16/2014

SponsorName Nick Parker E-mail Address nparker@spp.org Company Southwest Power Pool Phone Number 501.614.3574

Comments ReceivedComment Author Debbie James on behalf of MWG Date 12/16/2014

Comment Description

SPP staff provided a complete re-write of this MPRR based on feedback from stakeholders for discussion at the 12/16/2014 MWG meeting. These comments include the staff re-write and the MWG modifications on 12/16/2014. Since the staff changes were significant, the comments do not include redlines to the original MPRR previously posted.

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

Reasons for Opposing

Dissenter Clifford Franklin – Westar Date 12/16/2014

Reason

Westar votes no on MPRR 227. Westar has significant concerns over MPRR 227 allowance for participant funding parties to select geographically remote transmission capacity paths for ILTCRs in which their participant funded projects have released latent incremental ATC. SPP will be required that TOs maintain the financial ILTCR latent capacity path, despite the fact that the participant funding parties have not funded any of the infrastructure costs associated with the released latent transmission capacity. The latent transmission capacity should remain available for system expansion to those paying the infrastructure costs. Further, SPP will be required to not allow ILTCR path capacity to be used as available for Firm TSRs, LTCR allocation, ARR allocation, or TCR Auctions. The remote latent transmission capacity will only be available for non-firm RTBM schedules. Westar believes that the appropriate ILTCR would be to grant the funding participant a path across the upgrade project(s) that they funded.

Proposed Protocol Language Revision

1. Glossary

Incremental Long-Term Congestion Right (ILTCR)

As defined in Attachment AE of the Tariff.

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 4 of 59

3.2 Transmission Congestion Rights Markets The structure of the TCR Markets includes annual nomination and allocation of Long-Term

Congestion Rights (LTCRs) to Eligible Entities, allocation of Incremental Long-Term

Congestion Rights (ILTCRs) associated with Sponsored Upgrades and annual and monthly

nomination and allocation of Auction Revenue Rights (ARRs) to Eligible Entities followed by

annual and monthly TCR Auctions. Eligible Entities for ARRs include Transmission Customers

with firm SPP transmission service and entities with firm non-SPP transmission service

(commonly referred to as a “grandfathered agreement or GFA”) into, out of, within or through

the SPP Region that have identified such service during the annual LTCR/ARR verification

process. Eligible Entities for LTCRs include Transmission Customers with qualifying firm SPP

transmission service and entities with qualifying firm non-SPP transmission service (commonly

referred to as a “grandfathered agreement or GFA”) into, out of, within and through the SPP

Region that have identified such qualifying service during the annual LTCR/ARR verification

process. Entities with firm non-SPP transmission service (GFA) must agree between the parties

as to which party is eligible to nominate LTCRs and/or ARRs. Additionally, Eligible Entities

may request NITS, GFA NITS, FPTP and/or GFA FPTP Candidate ARRs for firm transmission

service confirmed following completion of the annual TCR auction.

Key features of the annual LTCR allocation process include:

(1) Eligible Entities are awarded LTCRs that apply to the entire TCR year. Holders of

candidate ILTCRs are awarded ILTCRs that apply to the entire TCR year. Load Serving

Entities (LSEs) are awarded LTCRs prior to consideration of LTCR awards for Eligible

Entities that are not LSEs and ILTCR awards. Candidate LTCRs are only associated

with eligible long-term firm transmission service with rollover rights. Candidate

ILTCRs are only associated with Sponsored Upgrades that have been placed in-service;

(2) All Nominated Ccandidate LTCRs candidate ILTCRs are modeled in order to determine

simultaneous feasibility of the Ccandidate LTCRs and candidate ILTCR. LTCRs and

ILTCRs are only awarded up to the selected amount of simultaneously feasible Candidate

LTCRs and ILTCRs;

(a) Candidate LTCRs and candidate ILTCRs are evaluated for simultaneous

feasibility for flows in the prevailing direction only with no simultaneous

consideration of LTCR flows and ILTCRs flows in the opposite direction (i.e.

counterflow is not considered in the feasibility analysis);

(b) 50% of the SPP transmission system capability is available for allocation;

Comment [A1]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A2]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A3]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A4]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A5]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A6]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 5 of 59

(3) Awarded LTCRs and ILTCRs are of the obligation type which means that the TCRs

associated with the awarded LTCR could result in a payment or charge to the TCR holder

in the Day-Ahead Market settlement of TCRs;

(a) Once awarded, the awarded LTCRs are guaranteed in subsequent years as long as

the associated long-term firm SPP transmission service reservation remains in

effect;

(b) Once awarded, the awarded ILTCRs are guaranteed in subsequent years;

(a)(c) Awarded LTCRs and awarded ILTCRs may be surrendered in subsequent years at

the Market Participant's request;

(1)(4) Awarded LTCRs and awarded ILTCRs are directly converted to TCRs prior to the

annual ARR allocation for the current allocation year.

Key features of the annual ARR allocation process include:

(1) Eligible Entities nominate candidate ARRs separately for On-Peak and Off-Peak periods

each month and season of the annual period in a three-round process;

(2) Nominated candidate ARRs are awarded up to the amount that is simultaneously feasible;

(3) 100% of the SPP transmission system capability is available for allocation;

(a) All awarded LTCRs are directly converted to TCRs and are accounted for prior to

assessing nominated ARR feasibility;

(b) Awarded ARRs are of the obligation type which means that the awarded ARR

could result in a payment or charge to the ARR holder.

(4) Holders of ARRs receive positive or negative revenue resulting from the annual and

monthly TCR auctions, including those ARRs that were self-converted to TCRs.

Positive auction revenue results when the sink Auction Clearing Price (ACP) is greater

than the source ACP for a given ARR. Negative revenue results when the sink ACP is

less than the source ACP, in other words, a counterflow ARR.

(a) For the annual TCR auction, the amount of ARRs eligible to receive auction

revenues is equal to the greater of ARRs self-converted to TCRs or the amount of

ARRs awarded multiplied by the following percentages: June – 100%; July

through September, 90%; and Fall, Winter, Spring – 60%.

(b) For the monthly TCR auction for the months of July through September, the

amount of ARRs eligible to receive auction revenues is equal to the amount of

Formatted: Outline numbered + Level: 2 +Numbering Style: a, b, c, … + Start at: 1 +Alignment: Left + Aligned at: 0.63" + Indentat: 1"

Formatted: Outline numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0.13" + Indentat: 0.5"

Comment [A7]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A9]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A8]: MPRR171 Awaiting FERC Approval. #ER14-2553

Formatted: Outline numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0.13" + Indentat: 0.5"

Comment [A10]: MPRR138 Awaiting FERC Approval. #ER14-2553

Formatted: Outline numbered + Level: 2 +Numbering Style: a, b, c, … + Start at: 1 +Alignment: Left + Aligned at: 0.63" + Indentat: 1"

Comment [A11]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A13]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A12]: MPRR171 Awaiting FERC Approval. #ER14-2553

Formatted: Outline numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0.13" + Indentat: 0.5"

Comment [A15]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A14]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A16]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A17]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 6 of 59

ARRs awarded in the monthly ARR allocation process plus: the lesser of (i) 10%

of the annual ARR award or (ii) the difference between the annual ARR award

and the amount of self-converted TCRs in the annual TCR auction;

(c) For the monthly TCR auction for the months of October through May, the amount

of ARRs eligible to receive auction revenues is equal to the amount of ARRs

awarded in the monthly ARR allocation process plus: the lesser of (i) 40% of the

annual ARR award or (ii) the difference between the annual ARR award and the

amount of self-converted TCRs in the annual TCR auction.

Key features of the annual TCR auction include:

(1) Any Market Participant that meets the applicable credit requirements may submit TCR

Bids to purchase and/or TCR Offers to sell separately for On-Peak and Off-Peak periods

in the annual TCR auction for each month and season in the annual period;

(c)(a) TCRs directly converted from LTCRs may be offered for sale in the annual or

monthly TCR auction process;

(2) TCRs are of the obligation type which means that the awarded TCR could result in a

payment or charge to the TCR holder in the DA Market settlement;

(3) The annual TCR auction is a single round process for the month of June that makes 100%

of the available SPP transmission system capability available, is a single round process

for the months of July, August and September that makes 90% of the available SPP

transmission system capability available and is a single round process for the Fall, Winter

and Spring seasons that makes 60% of the available SPP transmission system capability

available;

(4) Market Participants who have TCR bids cleared in the annual TCR auction will be

charged (or get paid in the case of a counter-flow TCR) based on the amount of TCR

MWs cleared and the annual TCR auction clearing prices associated with the source and

sink of the purchased TCR;

(5) Market Participants who have TCR offers cleared in the annual TCR auction will be paid

(or get charged in the case of a counter-flow TCR) based on the amount of TCR MWs

cleared and the annual TCR auction clearing prices associated with the source and sink of

the TCR sold;

Comment [A18]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A19]: MPRR138 Awaiting FERC Approval. #ER14-2553

Formatted: Indent: Left: 0.12", Hanging: 0.38", Outline numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0.5" + Indent at: 1", Tab stops: 0.5", List tab + Not at 1"

Comment [A20]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A21]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A22]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A23]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A24]: MPRR138 Awaiting FERC Approval. #ER14-2553

Formatted: Indent: Left: 0.12", Hanging: 0.38", Outline numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0.5" + Indent at: 1", Tab stops: 0.5", List tab + Not at 1"

Comment [A25]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A26]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A27]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A28]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 7 of 59

(6) Market Participants holding ARRs may self-convert their ARRs into TCRs for the

applicable period subject to simultaneous feasibility. TCRs from self-converted ARRs

are included as awarded TCRs.

Key features of the monthly ARR allocation include:

(1) SPP verifies new firm transmission service reservations and performs a monthly ARR

allocation process beginning five days prior to the applicable monthly TCR auction

process.

(a) Eligible Entities may nominate candidate ARRs from their verified NITS

Candidate ARRs not to exceed the difference between their NITS ARR

Nomination Cap and those ARRs awarded in the annual ARR allocation process;

(b) Eligible Entities may nominate candidate ARRs from their verified FPTP

Candidate ARRs not to exceed the difference between their FPTP Nomination

Cap and those ARRs awarded in the annual ARR allocation processes;

(c) Eligible Entities may nominate candidate ARRs from their verified GFA NITS

Candidate ARRs not to exceed the difference between their GFA NITS

Nomination Cap and those ARRs awarded in the annual ARR allocation process;

(d) Eligible Entities may nominate candidate ARRs from their verified GFA FPTP

Candidate ARRs not to exceed the difference between their GFA FPTP

Nomination Cap and those ARRs awarded in the annual ARR allocation process;

(e) Nominated candidate ARRs are awarded up to the amount that is simultaneously

feasible;

(f) All TCRs previously awarded in the Annual TCR Auction Process and all

remaining ARRs not accounted for in the Annual TCR Auction Process for the

applicable month are modeled as fixed injections at the specified sources and

fixed withdrawals at the specified sinks prior to assessing nominated candidate

ARR feasibility.

(2) Awarded ARRs are of the obligation type which means that the awarded ARR could

result in a payment or charge to the ARR holder; and

(3) 100% of the SPP transmission system capability is available for allocation.

Key features of the monthly TCR auction include:

Comment [A29]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A30]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A31]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A32]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A33]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A34]: MPRR138 Awaiting FERC Approval. #ER14-2553

Formatted: Indent: Left: 0.12", 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"

Comment [A35]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A36]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A37]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A38]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A39]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A40]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A41]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A42]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A43]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A44]: MPRR138 Awaiting FERC ... [1]

Comment [A45]: MPRR138 Awaiting FERC ... [2]

Comment [A46]: MPRR138 Awaiting FERC ... [3]

Comment [A47]: MPRR138 Awaiting FERC ... [4]

Comment [A48]: MPRR138 Awaiting FERC ... [5]

Comment [A49]: MPRR138 Awaiting FERC ... [6]

Comment [A50]: MPRR138 Awaiting FERC ... [7]

Comment [A51]: MPRR138 Awaiting FERC ... [8]

Comment [A52]: MPRR138 Awaiting FERC ... [9]

Formatted ... [10]

Comment [A53]: MPRR138 Awaiting FERC ... [11]

Comment [A54]: MPRR138 Awaiting FERC ... [12]

Comment [A55]: MPRR138 Awaiting FERC ... [13]

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 8 of 59

(1) The monthly TCR auction process allows any Market Participants that have met the

applicable credit requirements to submit TCR Bids to purchase additional TCRs or TCR

Offers to sell currently held TCRs in a single-round process for the months of July,

August and September and in a two-round process for the months of October through

May;

(2) 100% of the SPP transmission system capability is made available; and

(3) Market Participants may self-convert their remaining ARRs (including ARRs remaining

from the annual TCR auction process and ARRs awarded in the monthly ARR allocation

process) into TCRs for the applicable period subject to simultaneous feasibility.

Exhibit 3-3 provides an overview of the TCR Markets structure.

Comment [A56]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 9 of 59

Exhibit 0-1: Overview of TCR Markets Structure

The TCR Markets are operated in parallel with the timeline depicted in Exhibit 3-2 to ensure the

Market Participants are able to obtain TCRs prior to DA Market operation. A representative

timeline for the TCR Market processes is shown in Exhibit 3-4.

MPs Submit Bids to

Buy TCRs

Verification Annual TCR Auction

Annual ARR Awards

TCR MarketSettlements

TCs identify and confirm NITS and

Firm PTP

TCsNominate

Annual ARRs

IncrementalARR

Awards

TCsNominate

Incremental ARRs

Monthly TCR Auction

MPs Submit Bids to Buy TCRs and Offers to Sell

TCRs

Receive Annual and

Monthly Auction Revenue

Receive Monthly Auction

RevenueCleared Bids Pay

Cleared Offers are Paid

DA MarketSettlements

Annual ARR Award MW

Cleared Bids PayCleared Offers are Paid

Incremental ARR Award

MW

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 10 of 59

Exhibit 0-2: LTCR/ILTCR/ARR Allocation/TCR Auction Processes Timeline

The Energy and Operating Reserve Markets processes are described in detail in Section Error!

Reference source not found. and the TCR Markets processes are described in detail in Section

0.

5. Transmission Congestion Rights Markets Process

The annual TCR Markets Process includes an annual LTCR allocation process, an annual and

monthly ARR allocation process and annual and monthly TCR Auctions.

LTCRs and ILTCRs are multi-year instruments, ARRs are annual, monthly or seasonal

instruments, and TCRs are monthly and seasonal financial instruments whose values are

determined as part of the DA Market settlement based on the MW amount of the TCR (including

LTCRs converted to TCRs) and the DA Market differential of the Marginal Congestion

Component of LMP between specified sinks and sources. TCRs are of the obligation type which

means they can result in a credit or a charge. They provide a financial hedge against congestion

costs in the DA Market as long as the MCC of the TCR sink Settlement Location is greater than

the MCC of the TCR source Settlement Location. If the MCC at the TCR sink Settlement

Location is less than the MCC of the TCR source Settlement Location, the TCR holder is

charged (this type of TCR is commonly referred to as a “Counter-Flow TCR”). Awarded LTCRs

12 / 15 5/31

1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5

6 /1 - 9/ 30 Annual ARR Awards

And TCR Auction Awards

by Month On - Peak and Off - Peak

12 / 15 - 5/31LTCR/ ARR Allocation / TCR Auctions

10/1 - 5/31Annual ARR Awards

And TCRAuction Awards

by SeasonOn-Peak and Off-Peak

7/1 - 5/31

Monthly TCRAuction AwardsMonth to Month

On-Peak and Off-Peak

5/ 3 - 5/ 23 Annual

TCR Auction

4/5 - 4 /23 Annual ARR

Allocation

6 / 8 - 6/ 18

TCR Monthly Auction for July

Repeats for Each

Month

5/ 25 - 6/5Monthly ARR Allocation and

Awards . Repeats Each Month

2/ 3 - 3/ 4MP Verification of

Transmission Entitlements

3 /10 - 3 / 28 Annual LTCR/ILTCR

Allocation

6/1 - 5/31Annual LTCR Awards

Comment [A57]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A58]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A59]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A60]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A61]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 11 of 59

are directly converted into TCRs prior to the annual ARR allocation for the current allocation

year.

Auction Revenue Rights (ARRs) are obtained by Eligible Entities during the annual ARR

allocation process and/or monthly ARR allocation process. Holders of ARRs are entitled to

receive the Annual and Monthly TCR Auction revenues associated with awarded TCR Bids.

However, ARRs are of the obligation type which means they can result in the holder receiving a

portion of the TCR auction revenues or contributing to the TCR auction revenues.

TCRs are obtained by Market Participants through the annual LTCR allocation and the Annual

and Monthly TCR Auctions. Optionally, ARR holders may convert their ARRs into TCRs in the

Annual and Monthly TCR Auctions and either hold the TCRs or offer these TCRs for sale in the

auctions.

The TCR Markets Process is subject to review by the Market Monitor, consistent with

Attachment AG of the SPP OATT.

There are 8 key steps associated with obtaining an LTCR or TCR and/or offering an awarded

LTCR or TCR for sale.

(1) Annual LTCR/ILTCR/ARR Verification Process;

(2) Annual LTCR Allocation Process;

(3) Annual ARR Allocation Process;

(4) Annual TCR Auction Process;

(5) Monthly ARR Allocation Process;

(6) Monthly TCR Auction Process;

(7) ARR Allocation and TCR Auction Settlements; and

(8) TCR Secondary Markets.

Exhibit 5-1 provides an overall representative timeline related to the LTCR Allocation, ARR

Allocation and TCR Auction processes and Exhibit 5-2 provides additional details related to

auction timing and available transmission system capability of the TCR Auction processes.

Exhibit 0-1: LTCR/ILTCR/ARR Allocation and TCR Auction Processes Timeline

Comment [A62]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A63]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A64]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A65]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A66]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A67]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A68]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A69]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A70]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A71]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A72]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A73]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A74]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A75]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 12 of 59

12 / 15 5/31

1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5

6 /1 - 9/ 30 Annual ARR Awards

And TCR Auction Awards

by Month On - Peak and Off - Peak

12 / 15 - 5/31LTCR/ ARR Allocation / TCR Auctions

10/1 - 5/31Annual ARR Awards

And TCRAuction Awards

by SeasonOn-Peak and Off-Peak

7/1 - 5/31

Monthly TCRAuction AwardsMonth to Month

On-Peak and Off-Peak

5/ 3 - 5/ 23 Annual

TCR Auction

4/5 - 4 /23 Annual ARR

Allocation

6 / 8 - 6/ 18

TCR Monthly Auction for July

Repeats for Each

Month

5/ 25 - 6/5Monthly ARR Allocation and

Awards . Repeats Each Month

2/ 3 - 3/ 4MP Verification of

Transmission Entitlements

3 /10 - 3 / 28 Annual LTCR/ILTCR

Allocation

6/1 - 5/31Annual LTCR Awards

Market Proto

Attachment 6

1 October an2 December, 3 April and M

Auction Month May A (System Ca Jun M(System Cap Jul M(System Cap Aug (System Cap Sep M(System Cap Oct M(System Cap Nov (System Cap Dec M(System Cap Jan M(System Cap Feb M(System Cap Mar M(System Cap Apr M(System Cap

ocols for SPP Int

- MPRR 227 Reco

nd November

January, FebruarMay

Auction Type

Annual apability %) Monthly pability %)

Monthly pability %) Monthly pability %) Monthly pability %)

Monthly pability %) Monthly pability %) Monthly pability %) Monthly pability %) Monthly pability %) Monthly pability %) Monthly pability %)

tegrated Marketpl

mmendation Repor

ry, March

TCR Award Pe

Jun (100)

Jul (90

Jul (100)

Aug (100)

Sep (100)

Oct (100)

Nov (100)

Dec (100)

Jan (100)

Feb (100)

Mar (100)

Apr (100)

May (100)

lace

rt.docx 12/16/

Exhibit 0-2:

eriods

0) Aug

(90)

/2014

TCR Auction

Sep (90)

Fall(60)

n Processes Su

l1 )

Winter2

(60)

P

ummary

TCPr

Spring3 (60)

OnOf

OnOf

OnOf

OnOf

OnOf

OnOf

OnOf

OnOf

OnOf

OnOf

OnOf

OnOf

Page 13 of 59

CR roducts

AuRo

n-Peak/ ff-Peak

1

n-Peak/ ff-Peak

1

n-Peak/ ff-Peak

1

n-Peak/ ff-Peak

1

n-Peak/ ff-Peak

2

n-Peak/ ff-Peak

2

n-Peak/ ff-Peak

2

n-Peak/ ff-Peak

2

n-Peak/ ff-Peak

2

n-Peak/ ff-Peak

2

n-Peak/ ff-Peak

2

n-Peak/ ff-Peak

2

uction ounds

TotalAucti14

2

2

2

4

4

4

4

4

4

4

4

l ions

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 14 of 59

Key process and design assumptions of each of these eight (8) key steps are described in

the following sub-sections.

5.1 Annual LTCR/ILTCR/ARR Verification Process

Only Eligible Entities are eligible to nominate candidate LTCRs and/or ARRs as

described under Sections 0 and Error! Reference source not found.. Only Upgrade

Sponsors that have received candidate ILTCRs through the process described under

Section IV of Attachment Z2 to the Tariff are eligible to nominate candidate ILTCRs.

Eligible Entities for ARRs are Transmission Customers with firm SPP transmission

service and entities with firm non-SPP transmission service (commonly referred to as a

“grandfathered agreement or GFA”) into, out of, within or through the SPP Region that

has been confirmed prior to the Annual ARR Allocation Process. Eligible Entities for

LTCRs are Transmission Customers with qualifying firm SPP transmission service and

entities with qualifying firm non-SPP transmission service (commonly referred to as a

“grandfathered agreement or GFA”) into, out of, within or through the SPP Region that

has been confirmed prior to the Annual LTCR Allocation Process. Eligible Entities must

verify such services with SPP during the Annual LTCR/ARR Verification Process in

order to be eligible to nominate candidate LTCRs and/or ARRs. All Eligible Entities

must be a Market Participant and/or Asset Owner. The following rules apply to

verification of transmission service for conversion to LTCRs and/or ARRs.

5.1.1 Transmission Service Verification

In order for Eligible Entities to obtain candidate LTCRs and/or ARRs, SPP must first

verify existing transmission service entitlements, including transmission service

entitlements which have been renewed in accordance with rollover rights since their

initial term. In order to qualify for candidate LTCRs, an Eligible Entity’s firm

transmission service must contain rollover rights and must span the entire allocation year.

In order to qualify for candidate ILTCRs for the current allocation year, the upgrade

associated with the candidate ILTCRs must be in-service prior to the start of the annual

ILTCR verification. In order to qualify for candidate ARRs in a particular month and/or

season, an Eligible Entity’s transmission service must span the entire monthly or seasonal

period within the applicable allocation year. For Transmission Service with rollover

rights whose deadline for providing notice of rollover occurs after the annual LTCR/ARR

verification but before June 1, the Transmission Provider shall assume that the rollover

will occur and shall consider the Transmission Service entitlement to span the entire

allocation year, provided, however, that, if rollover rights for such Transmission Service

are not exercised by the applicable deadline, any ARRs, TCRs, or LTCRs associated with

Comment [A76]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A77]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A78]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A79]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A80]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A81]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A82]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A83]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A84]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A85]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A86]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A87]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A88]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A89]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A90]: MPRR171 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 15 of 59

such Transmission Service shall revert to the Transmission Provider effective on the date

such Transmission Service terminates. SPP will verify each Eligible Entity's existing

transmission service entitlements as follows:

(1) For Eligible Entities taking Network Integration Transmission Service (NITS)

and/or Firm Point-To-Point Transmission Service (FPTP) under the SPP Tariff:

(a) SPP will obtain source, sink and Reserved Capacity information from the

SPP OASIS for each monthly and seasonal period for the applicable year

in which the transmission service spans the entire period for ARR

purposes and for the annual period for the applicable year for LTCR

purposes, or would if or when rolled over;

(b) Eligible Entities taking NITS with rollover rights shall be considered an

LSE for purposes of LTCR allocation;

(c) Eligible Entities taking FPTP service with rollover rights shall not be

considered an LSE for that service unless the Eligible Entity provides an

attestation to SPP confirming that the Eligible Entity is an LSE as defined

in Attachment AE of the Tariff for such service;

(d) For a TSR with a source inside the SPP Market that is not a specific

Resource or Resource Hub, the load Settlement Location that most closely

corresponds to the source on the reservation will be utilized as the source

for candidate LTCRs and/or ARRs. Eligible Entities may create Resource

specific TSRs that represent their current TSRs using the process

described under Section Error! Reference source not found.;

(e) For a TSR with a source outside of the SPP Market, the Interface

Settlement Location associated with the Balancing Authority of the source

will be utilized as the source for candidate LTCRs and/or ARRs;

(f) For a TSR with a sink outside of the SPP Market, the Interface Settlement

Location associated with the Balancing Authority of the sink will be

utilized as the sink for candidate LTCRs and/or ARRs;

(g) SPP will provide this information to each Eligible Entity for verification;

(h) Eligible Entities will notify SPP within two (2) weeks following receipt of

this information identifying and correcting inaccurate data. Otherwise, the

SPP provided data will be considered verified.

(2) For Eligible Entities taking GFA service without Carve Out treatment:

Comment [A91]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A92]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A93]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A94]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A95]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A96]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A97]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A98]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 16 of 59

(a) If the transmission customer under the GFA desires to nominate ARRs

associated with the GFA sources and sinks identified in the Grandfathered

Agreement, the GFA Parties must register such GFA with SPP and

provide sources, sinks and reserved capacity information. SPP will obtain

source, sink and reservation capacity information from the GFA

registration for each monthly and seasonal period for the applicable year

in which the transmission service spans the entire period;

(b) Eligible Entities taking the equivalent of SPP NITS with rollover rights

shall be considered an LSE for purposes of LTCR allocation;

(c) Eligible Entities taking the equivalent of SPP FPTP service with rollover

rights shall not be considered an LSE for that service unless the Eligible

Entity provides an attestation to SPP confirming that the Eligible Entity is

an LSE as defined in Attachment AE of the Tariff for such service;

(d) For a GFA with a source inside the SPP Market that is not a specific

Resource or Resource Hub, the load Settlement Location that most closely

corresponds to the source on the reservation will be utilized as the source

for candidate LTCRs and/or ARRs;

(e) For a GFA with a source outside of the SPP Market, the interface

associated with the Balancing Authority of the source will be utilized as

the source for candidate LTCRs and/or ARRs;

(f) For a GFA with a sink outside of the SPP Market, the interface associated

with the Balancing Authority of the sink will be utilized as the sink for

candidate LTCRs and/or ARRs;

(g) In addition, the parties to the GFA must agree that the transmission

customer under the GFA is eligible to nominate the LTCRs and/or ARRs

associated with the GFA and both parties must confirm such with SPP. To

the extent that the transmission service specified in the GFA is identified

as the equivalent of SPP NITS, the transmission customer under the GFA

must provide the historical non-coincident peak loads (“GFA Annual Peak

Load”) being served under the GFA for the previous three years.

(3) For entities that have been granted GFA Carve Out treatment:

(a) GFAs with GFA Carve Out treatment are not eligible for candidate ARRs;

(b) The parties to the GFA must register the GFA with SPP, identify the GFA

Responsible Entity, and provide source, sink and reserved capacity

information. SPP will obtain source, sink and reserved capacity

Comment [A99]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A100]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A101]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A102]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A103]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 17 of 59

information from the GFA registration for each monthly and seasonal

period for the applicable year in which the transmission service spans the

entire period;

(c) To the extent that the transmission service specified in the GFA Carve Out

is identified as the equivalent of SPP NITS, the transmission customer

under the GFA must provide the historical non-coincident annual peak

loads (“GFA Annual Peak Load”) being served under the GFA for the

previous three years.

5.1.2 Candidate LTCRs/ARRs

Following verification of Eligible Entity transmission service and candidate ILTCRs,

candidate LTCRs and ARRs associated with such transmission service and candidate

ILTCRs associated with in-service upgrades are assigned as follows:

(1) For each Eligible Entity with NITS, the Eligible Entity’s NITS Candidate LTCRs

and/or ARRs from a specific source is equal to the source Reserved Capacity.

(a) An Eligible Entity may select nominate NITS Candidate LTCRs, as

described under Section 5.2.6 from a specific source to one or more sinks

up to the amount of its available NITS Candidate LTCRs associated with

the source such that the total of such selections nominations does not

exceed the lesser of the sum of NITS Candidate LTCRs or the limit

described under Section Error! Reference source not found.(1)(b) for

that Eligible Entity;

(b) An Eligible Entity may nominate NITS Candidate ARRs, as described

under Section 5.3.1 from a specific source to one or more sinks up to the

amount of its NITS Candidate ARRs associated with the source subject to

the total nomination limit described under Section 5.1.3.

(2) For each Eligible Entity with FPTP service, the Eligible Entity’s FPTP Candidate

LTCRs and/or ARRs for a specific source and sink is equal to the Reserved

Capacity associated with that source and sink.

(a) An Eligible Entity may select nominate FPTP Candidate LTCRs, as

described under Section 5.2.6, for this specific source and sink up to the

amount of its available FPTP Candidate LTCRs such that the total of such

selections nominations does not exceed the total FPTP Candidate LTCRs

available for that Eligible Entity.

Comment [A104]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A105]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A106]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A107]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A108]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A109]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A110]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A111]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A112]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A113]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A114]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A115]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A116]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A117]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A118]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A119]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A120]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A121]: MPRR171 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 18 of 59

(b) An Eligible Entity may nominate FPTP Candidate ARRs, as described

under Section 5.3.1, for this specific source and sink up to the amount of

its FPTP Candidate ARRs subject to the total nomination limit described

under Section 5.1.3

(3) A holder of candidate ILTCRs may nominate the candidate ILTCRs up to the

MW amount for the specific source and sink path documented through the process

described under Section IV of Attachment Z2 to the Tariff less previously

awarded ILTCRs.

(4) For each Eligible Entity with equivalent NITS GFA service, the Eligible Entity’s

GFA NITS Candidate LTCRs and/or ARRs from a specific source is equal to the

source Reserved Capacity.

(a) An Eligible Entity may select nominate GFA NITS Candidate LTCRs, as

described under Section 5.2.6, from a specific source to one or more sinks

up to the amount of its available GFA NITS Candidate such that the total

of such selections nominations does not exceed the lesser of the sum of

GFA NITS Candidate LTCRs or the limit described under Section Error!

Reference source not found.(3)(b) for that Eligible Entity LTCRs;

(b) An Eligible Entity may nominate GFA NITS Candidate ARRs, as

described under Section 5.3.1, for this specific source and sink up to the

amount of its GFA NITS Candidate ARRs subject to the total nomination

limit described under Section 5.1.3;

(5) For each Eligible Entity with equivalent FPTP GFA service, the Eligible Entity’s

GFA FPTP Candidate LTCRs and/or ARRs for a specific source and sink is equal

to the Reserved Capacity associated with that source and sink.

(a) An Eligible Entity may select nominate GFA FPTP Candidate LTCRs, as

described under Section 5.2.6, for this specific source and sink up to the

amount of its available GFA FPTP Candidate LTCRs such that the total of

such selections nominations does not exceed the total GFA FPTP

Candidate LTCRs available for that Eligible Entity.

(b) An Eligible Entity may nominate GFA FPTP Candidate ARRs, as

described under Section 5.3.1, for this specific source and sink up to the

amount of its GFA FPTP Candidate ARRs subject to the total nomination

limit described under Section 5.1.3.

Comment [A122]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A123]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A124]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A125]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A126]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A127]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A128]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A129]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A130]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A131]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A132]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A133]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A134]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A135]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A136]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A137]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 19 of 59

5.2 Annual LTCR Allocation Process

The Annual LTCR Allocation Process addresses how candidate LTCRs and candidate

ILTCRs verified in the Annual LTCR/ILTCR/ARR Verification Process may be selected

nominated and awarded as LTCRs. The annual allocation process determines the portion

of the nominated candidate LTCRs and candidate ILTCRs that are simultaneously

feasible and available to each Eligible Entity to select. 50% of the SPP Residual

Transmission System Capability, as defined under Section 5.2.2(2), is made available

during the Annual LTCR Allocation Process. Nominated Candidate LTCRs and

candidate ILTCRs are evaluated on an annual basis in a two-step, single round process.

The first step evaluates nominated LSE candidate LTCRs to determine LSE available

LTCRs. The and the second step evaluates nominated non-LSE candidate LTCRs and

candidate ILTCRs associates. No later than five (5) Business Days prior to the start of

the Annual LTCR Allocation Process, SPP will post the transmission system network

topology data for the annual model, along with corresponding Parallel Flow assumptions,

that SPP will use in the upcoming allocation process for use by Eligible Entities in

developing their available candidate LTCR selection strategies. The following rules

apply to the annual allocation of LTCRs.

5.2.1 LTCR/ILTCR Surrender

Eligible Entities may surrender previously awarded LTCRs and ILTCRs in 0.1 MW

increments. Prior to annual LTCR allocation, Eligible Entities submit the following

information:

(1) Source (valid candidate LTCR or ILTCR source Settlement Location);

(2) Sink (valid candidate LTCR or ILTCR sink Settlement Location);

(3) Surrendered LTCR MW (cannot exceed previously awarded LTCR);.

(3)(4) Surrendered ILTCR MW (cannot exceed previously

awarded ILTCR).

5.2.2 LTCR/ILTCR Nomination

Eligible Entities and holders of candidate ILTCRs must submit the following information

in order to select LTCRs and ILTCRs:

(1) Source (valid candidate LTCR and/or candidate ILTCR source Settlement

Location);

(2) Sink (valid candidate LTCR and/or ILTCR sink Settlement Location);

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 20 of 59

(3) Nominated LTCR MW (total LTCR MW nominated from a source Settlement

Location cannot exceed the source candidate available LTCR MW as previously

determined under Section 5.1.2, less previously awarded LTCRs plus surrendered

LTCRs);

(4) Nominated ILTCR MW (total ILTCR MW nominated from a source Settlement

Location cannot exceed the source candidate ILTCR MW as previously

determined under Section 5.1.2, less previously awarded ILTCRs plus

surrendered ILTCRs).

5.2.23 Candidate LTCR Simultaneous Feasibility for LSEs

A simultaneous feasibility test (SFT) is performed to determine the feasibility of all

nominated NITS Candidate LTCRs, FPTP Candidate LTCRs, GFA NITS Candidate

LTCRs and GFA FPTP Candidate LTCRs identified as described under Section 5.1.2 for

all LSEs. All nominated LSE candidate LTCRs are modeled as a generation injection at

the source and a corresponding load withdrawal at the sink. The feasibility analysis

assures the modeling of the LSE candidate LTCRs does not violate any normal

transmission line thermal ratings under normal system conditions and does not violate

short-term Emergency transmission line thermal ratings following a single contingency

(N-1 contingency analysis). The SFT is performed consistent with the transmission

system loading analysis that is performed as part the Security Constrained Economic

Dispatch process in the DA Market and includes consideration of the impact of Parallel

Flow.

(1) The SPP Transmission System topology used in the SFT is the most up-to-date

Network Model.

(a) For withdrawals at Settlement Locations containing more than one PNode,

SPP will distribute the Settlement Location withdrawal down to the PNode

level using load distribution percentages from the peak hour of the

corresponding most recent historical period (i.e. prior year peak). These

load distribution percentages are calculated using the methodology

described under Section 4.1.2.1.6.

(b) For injections at Market Hubs, SPP will distribute the hub injection down

to the PNode level on a pro-rata basis using the weighting factors defined

when the hub is created.

(2) Prior to assessing simultaneous feasibility, the normal and emergency ratings of

all flowgates and monitored transmission system elements are adjusted as follows

to arrive at an SPP Residual Transmission System Capability:

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(a) Adjusted Monitored Transmission Line Rating (normal and Emergency) =

(Monitored Transmission Line Rating [normal and

Emergency – Parallel Flow impact])

(b) Adjusted Flowgate Rating (normal and Emergency) =

(Flowgate Rating – Parallel Flow impact)

(3) The feasibility analysis evaluates the candidatenominated LTCR feasibility by

evaluating line flows against path limits in a single direction only without

simultaneous consideration of line flows created by candidate nominated LTCRs

in the opposite direction (i. e. counter-flow will not act to increase the feasibility

of candidate LTCRs).

(4) The feasibility analysis uses an iterative process to ensure that previously awarded

LTCRs that have not been surrendered as indicated pursuant to Section 5.2.1

continue to be available.

(5) For the initial feasibility analysis, no previously awarded LSE LTCRs or

surrendered LSE LTCRs are modeled. Only candidate LSE LTCRs are modeled.

(6)(4) Previously The feasibility analysis models previously awarded LTCRs

associated with qualified transmission service as verified under Section 5.1.1 and

which were not surrendered as indicated pursuant to Section 5.2.1, associated with

non-LSEs are modeled as fixed injections and withdrawalsand previously

awarded ILTCRs which were not surrendered as indicated pursuant to Section

5.2.1 as fixed injections and withdrawals. To the extent that these fixed injections

and withdrawals are not feasible, SPP will increase the ratings of the applicable

transmission lines to ensure feasibility prior to assessing LSE LTCR

availabilityfeasibility. SPP will report back to the MWG when transmission line

ratings had to be adjusted to ensure feasibility.

(a) If the results of the initial feasibility analysis show that the amount of LSE

LTCRs feasible on specific paths are less than those LSE LTCRs

previously awarded on those paths, net of any surrendered LSE LTCRs,

the feasibility analysis is rerun with all previously awarded LSE LTCRs,

net of any surrendered LSE LTCRs, on such paths modeled as fixed

injections/withdrawals and all candidate LSE LTCRs on all other paths are

modeled as in (a) above. To the extent that these fixed injections and

withdrawals are not feasible, SPP will increase the ratings of the

applicable transmission lines to ensure feasibility. SPP will report back to

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the MWG when transmission line ratings had to be adjusted to ensure

feasibility.

5.2.34 Annual LTCR Available Awards for LSEs

If all of the nominated candidate LSE LTCRs are confirmed feasible, all nominated

candidate LSE LTCRs are availableawarded. If the nominated candidate LSE LTCRs are

not feasible, the amount of nominated candidate LSE LTCRs availableawarded will be

reduced using a weighted least squares method. The weighted least squares method

minimizes the least squares deviation from the nominated candidate LSE LTCR MW

weighted by the reciprocal of the nominated candidates resulting in a higher percentage

LSE LTCR reduction for those candidates having the greatest impact on the constraints.

LSE LTCR reductions associated with nominated candidates that have an equal impact

on the constraints are reduced by the same percentage.

5.2.45 Candidate LTCR Simultaneous Feasibility for Non-LSEs and Incremental LTCRs

A simultaneous feasibility test (SFT) is performed to determine the feasibility of all

nominated NITS Candidate LTCRs, FPTP Candidate LTCRs, GFA NITS Candidate

LTCRs and GFA FPTP Candidate LTCRs identified as described under Section 5.1.2 for

all non-LSEs and all nominated candidate ILTCRs. All nominated non-LSE candidate

LTCRs and nominated candidate ILTCRs are modeled as a generation injection at the

source and a corresponding load withdrawal at the sink. The feasibility analysis assures

the modeling of the non-LSE candidate LTCRs and candidate ILTCRs does not violate

any normal transmission line thermal ratings under normal system conditions and does

not violate short-term Emergency transmission line thermal ratings following a single

contingency (N-1 contingency analysis). The SFT is performed consistent with the

transmission system loading analysis that is performed as part of the Security Constrained

Economic Dispatch process in the DA Market and includes consideration of the impact of

Parallel Flow.

(1) The SPP Transmission System topology used in the SFT is the most up-to-date

Network Model.

(a) For withdrawals at Settlement Locations containing more than one PNode,

SPP will distribute the Settlement Location withdrawal down to the PNode

level using load distribution percentages from the peak hour of the

corresponding most recent historical period (i.e. prior year peak). These

load distribution percentages are calculated using the methodology

described under Section 4.1.2.1.6.

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(b) For injections at Market Hubs, SPP will distribute the hub injection down

to the PNode level on a pro-rata basis using the weighting factors defined

when the hub is created.

(2) Prior to assessing simultaneous feasibility, the normal and emergency ratings of

all flowgates and monitored transmission system elements are adjusted as follows

to arrive at an SPP Residual Transmission System Capability:

(a) Adjusted Monitored Transmission Line Rating (normal and Emergency) =

(Monitored Transmission Line Rating (normal and

Emergency – Parallel Flow impact))

(b) Adjusted Flowgate Rating (normal and Emergency) =

(Flowgate Rating – Parallel Flow impact)

(3) The feasibility analysis evaluates the candidate LTCR feasibility and candidate

ILTCR feasibility by evaluating line flows against path limits in a single direction

only without simultaneous consideration of line flows created by candidate

LTCRs and candidate ILTCRs in the opposite direction (i. e. counter-flow will not

act to increase the feasibility of candidate LTCRs and candidate ILTCRs).

(4) The feasibility analysis models previously awarded LTCRs associated with

qualified transmission service as verified under Section 5.1.1 and which were not

surrendered as indicated pursuant to Section 5.2.1, previously awarded ILTCRs

which were not surrendered as indicated pursuant to Section 5.2.1, and LSE

LTCRs awarded under Section 5.2.4 as fixed injections and withdrawals. To the

extent that these fixed injections and withdrawals are not feasible, SPP will

increase the ratings of the applicable transmission lines to ensure feasibility prior

to assessing Non-LSE LTCR and ILTCR feasibility. SPP will report back to the

MWG when transmission line ratings had to be adjusted to ensure feasibility.

(3) The feasibility analysis uses an iterative process to ensure that previously awarded

LTCRs that have not been surrendered as indicated pursuant to Section 5.2.1

continue to be available.

(a) For the initial feasibility analysis, no previously awarded non-LSE LTCRs

or surrendered non-LSE LTCRs are modeled. Only candidate non-LSE

LTCRs are modeled.

(b) Available LSE LTCRs as calculated under Section 5.2.3 are modeled as

fixed injections and withdrawals.

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(c) If the results of the initial feasibility analysis show that the amount of non-

LSE LTCRs feasible on specific paths are less than those non-LSE LTCRs

previously awarded on those paths associated with qualified transmission

service as verified under Section 5.1.1 and which were not surrendered,

net of any surrendered non-LSE LTCRs, the feasibility analysis is rerun

with all previously awarded non-LSE LTCRs, net of any surrendered non-

LSE LTCRs, on such paths modeled as fixed injections/withdrawals and

all candidate non-LSE LTCRs on all other paths are modeled as in (a)

above. To the extent that these fixed injections and withdrawals are not

feasible, SPP will increase the ratings of the applicable transmission lines

to ensure feasibility prior to LSE LTCR availability. SPP will report back

to the MWG when transmission line ratings had to be adjusted to ensure

feasibility.

5.2.56 Annual LTCR Available Awards for Non-LSEs

If all of the nominated candidate non-LSE LTCRs and ILTCRs are confirmed feasible, all

nominated candidate non-LSE LTCRs and ILTCRs are availableawarded. If the

nominated candidate non-LSE LTCRs and ILTCRs are not feasible, the amount of

nominated candidate non-LSE LTCRs and nominated ILTCRs available awarded will be

reduced using a weighted least squares method. The weighted least squares method

minimizes the least squares deviation from the nominated candidate non-LSE LTCR MW

and nominated candidate ILTCR MW weighted by the reciprocal of the nominated

candidates resulting in a higher percentage non-LSE LTCR and ILTCR reduction for

those nominated candidates having the greatest impact on the constraints. Non-LSE

LTCR and ILTCR reductions associated with nominated candidates that have an equal

impact on the constraints are reduced by the same percentage. The Transmission

Provider will post the amounts of candidate non-LSE LTCRs which are available for the

non-LSE Eligible Entity's selection.

5.2.67 LTCR/ILTCR Conversion to TCRs Selections and Awards

(1) All previously awarded LTCRs associated with qualified transmission service as

verified under Section 5.1.1 and which were not surrendered, as described under

Section 5.2.1, are automatically awarded as LTCRs and automatically converted

to TCRs for the current allocation year.

(2) All previously awarded ILTCRs which were not surrendered, as described under

Section 5.2.1, are automatically awarded as ILTCRs and automatically converted

to TCRs for the current allocation year.

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(3) All LSE LTCRs awarded under Section 5.2.4 are automatically converted to

TCRs for the current allocation year.

(4) All Non-LSE LTCRs and ILTCRs awarded under Section 5.2.6 are automatically

converted to TCRs for the current allocation year.

(1)

(2) Additional available candidate LTCRs are selected and awarded in a single-round

process. Eligible Entities may select:

(a) Available LTCRs from their NITS Candidate LTCRs as described under

Section 5.2.3 or Section 5.2.5, less any previously awarded LTCRs plus

any surrendered LTCRs associated with NITS Candidate LTCRs;

(b) Available LTCRs from their FPTP Candidate LTCRs as described under

Section 5.2.3 or Section 5.2.5, less any previously awarded LTCRs plus

any surrendered LTCRs associated with FPTP Candidate LTCRs;

(c) Available LTCRs from their GFA NITS Candidate LTCRs as described

under Section 5.2.3 or Section 5.2.5, less any previously awarded LTCRs

plus any surrendered LTCRs associated with GFA NITS Candidate

LTCRs;

(d) Available LTCRs from their GFA FPTP Candidate LTCRs as described

under Section 5.2.3 or Section 5.2.5, less any previously awarded LTCRs

plus any surrendered LTCRs associated with GFA FPTP Candidate

LTCRs;

(3) Eligible Entities must submit the following information in order to select LTCRs:

(1) Source (valid candidate LTCR source Settlement Location);

(2) Sink (valid candidate LTCR sink Settlement Location);

(3) Selected LTCR MW (total LTCR MW nominated from a source

Settlement Location cannot exceed the source candidate available LTCR

MW as previously determined under Section 5.2.3 or Section 5.2.5, less

previously awarded LTCRs plus surrendered LTCRs);

(4) All selected LTCRs are automatically awarded, and these awarded LTCRs and

those awarded as described under (1) above are directly converted to TCRs prior

to the Annual ARR Allocation Process for the current allocation year.

5.3 Annual ARR Allocation Process

The Annual ARR Allocation Process addresses how candidate ARRs verified in the

Annual LTCR/ARR Verification Process may be nominated and converted to ARRs.

Comment [A139]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A140]: MPRR138 Awaiting FERC Approval. #ER14-2553

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Eligible Entities may nominate the candidate ARRs that they wish to receive up to their

Nomination Caps less any LTCRs awarded plus any LTCRs surrendered. Any candidate

LTCRs not awarded in the Annual LTCR Allocation Process and surrendered LTCRs

become candidate ARRs. Candidate ILTCRs which were not awarded and surrendered

ILTCRs are not eligible to receive candidate ARRs. The annual allocation process

determines the portion of the nominated candidate ARRs that are simultaneously feasible

to allocate to each Eligible Entity. 100% of the SPP Residual Transmission System

Capability, as defined under Section 0(2), is made available during the Annual ARR

Allocation Process. Candidate ARRs are nominated on a monthly and seasonal basis in a

three-round process. No later than five (5) Business Days prior to the start of the Annual

ARR Allocation Process, SPP will post the transmission system network topology data

for each of the monthly and seasonal on-peak and off-peak models, along with

corresponding Parallel Flow, prohibited collocated and electrically equivalent Settlement

Location pairs, and transmission line outage assumptions, that SPP will use in the

upcoming allocation process for use by Eligible Entities in developing their candidate

ARR nomination strategies. Exhibit 5-3 provides a representative timeline of the three-

round annual ARR allocation process.

Exhibit 0-3: Annual ARR Allocation Process Timeline

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The following rules apply to the annual allocation of ARRs.

5.3.3 Simultaneous Feasibility

A simultaneous feasibility test (SFT) is performed in each round to ensure that the

nominated candidate ARRs, with nominated candidate ARR MW modeled as generation

injection at the source and a corresponding load withdrawal at the sink, do not violate any

normal transmission line thermal ratings under normal system conditions and do not

violate short-term Emergency transmission line thermal ratings following a single

contingency (N-1 contingency analysis). The SFT is performed consistent with the

transmission system loading analysis that is performed as part the Security Constrained

Economic Dispatch process in the DA Market and includes consideration of the impact of

Parallel Flow. 100% of the SPP Residual Transmission System Capability, as defined

under Section 5.2.2(2), is made available during the analysis.

(1) The SPP Transmission System topology used in the SFT is the most up-to-date

Network Model for all allocation periods, updated for planned maintenance

outages.

(a) For withdrawals at Settlement Locations containing more than one PNode,

SPP will distribute the Settlement Location withdrawal down to the PNode

level using load distribution percentages from the peak hour of the

corresponding most recent historical period (i.e. June, July, August,

September, Fall, Winter and Spring). These load distribution percentages

are calculated using the methodology described under Section Error!

Reference source not found..

(b) For injections at Market Hubs, SPP will distribute the hub injection down

to the PNode level on a pro-rata basis using the weighting factors defined

when the hub is created.

(c) For GFA Carve Outs that will be nominated, an injection at the source and

a corresponding withdrawal at the sink will be included in the Annual

ARR Allocation Process and will be subject to SFT. The capacity used in

the allocation will be the maximum allowable nomination as defined in

section Error! Reference source not found..

(2) All previously awarded TCRs associated with LTCRs and ILTCRs that have not

been surrendered are modeled as fixed injections/withdrawals. To the extent that

these fixed injections and withdrawals are not feasible, SPP will increase the

Comment [A143]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A144]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A145]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A146]: MPRR171 Awaiting FERC Approval. #ER14-2553

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ratings of the applicable transmission lines to ensure feasibility. SPP will report

back to the MWG when and which transmission line ratings had to be adjusted,

and the magnitude of each adjustment, to ensure feasibility.

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.

5.4.1 TCR Bid and Offer Submittal

(1) Any Market Participant that has satisfied the applicable credit requirements may

participate in the Annual TCR Auction;

(2) Market Participants holding ARRs may elect to self-convert all or a portion of

those ARRs into TCRs with the same source and sink by specifying the Self-

Convert option as part of the TCR Bid submittal. Directly converted TCRs from

LTCRs and ILTCRs can be offered for sale in the Annual TCR Auction.

(3) For each month and season included in the Annual TCR Auction period, Market

Participants may submit TCR Bids and TCR Offers in 0.1 MW increments

separately, for On-Peak and Off-Peak periods (8 separate transmission system

models created representing each month in an annual auction period and on-peak

and off-peak periods within each month and 6 separate transmission system

models created representing each season in an annual auction period and on-peak

and off-peak periods within each season). The following information is submitted

for a TCR Bid or a TCR Offer:

(a) Source (any valid Settlement Location);

(b) Sink (any valid Settlement Location);

(c) Class (on-peak or off-peak);

(d) Period (month or season);

(e) Type (Bid, Self-Convert, Offer);

(f) TCR MW;

(g) TCR Price ($/MW);

(i) TCR Bids and Offers cannot exceed $100,000/MW-Month;

(ii) TCR Bids and Offers cannot be less than ($100,000/MW-Month).

Comment [A147]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A148]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A149]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A150]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A151]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A152]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [A153]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A154]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A155]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A156]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A157]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A158]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [A159]: MPRR138 Awaiting FERC Approval. #ER14-2553

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(4) For each TCR Round, a Market Participant is limited to a maximum combined

submittal of 2000 TCR Bids and/or TCR Offers for each Asset Owner it

represents.

(5) Market Participants may not submit offers to buy TCRs between Settlement

Locations that are collocated and electrically equivalent.

Proposed Tariff Language Revision

I.COMMONSERVICEPROVISIONS

1 Definitions

I - Definitions

Incremental Long-Term Congestion Right (“ILTCR”): An instrument that

entitles an Upgrade Sponsor to a Transmission Congestion Right that results from

the incremental ATC created from the portion of an upgrade for which there is a

Directly Assigned Upgrade Cost which is awarded during the Transmission

Provider’s annual ILTCR/LTCR allocation process.

M - Definitions

Market Participant: An entity that generates, transmits, distributes, purchases,

or sells electricity or provides Ancillary Services with respect to such services (or

contracts to perform any of the foregoing activities) within, into, out of, or

through the Transmission System. In addition, incremental additions to the

Network paid for by a Market Participant through a Directly Assigned Upgrade

Cost. Market Participant expressly includes:

(a) Transmission Owner(s) and any of their Affiliates including Transmission

Owners providing transmission service to: (i) bundled retail load for which such

Transmission Owners are taking neither Network Integration Transmission

Service nor Firm Point-To-Point Transmission Service under this Tariff; and (ii)

load being served under Grandfathered Agreements for which such Transmission

Owners are taking neither Network Integration Transmission Service nor Firm

Point-To-Point Transmission Service under this Tariff, (b) Transmission

Customers, (c) Network Customers, (d) Generation Interconnection Customers,

(e) any Eligible Customer offering Resources for sale into the Energy and

Operating Reserve Markets that executes the Service Agreement specified in

Comment [A160]: MPRR138 Awaiting FERC Approval. #ER14-2553

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Attachment AH, or on whose behalf an unexecuted Service Agreement has been

filed at the Commission, (f) any retail customer or eligible person that is not

precluded under the laws or regulations of the relevant electric retail regulatory

authority including state-approved retail tariff(s) from participating directly in

wholesale demand response programs in the Energy and Operating Reserve

Markets and that is technically qualified to offer Demand Response Load (as

defined in Attachment AE of this Tariff) into the Energy and Operating Reserve

Markets or an aggregator of such retail customers that offers qualified Demand

Response Load into the Energy and Operating Reserve Markets under Section 2.8

of Attachment AE, and (g) an entity that executes the Service Agreement

specified in Attachment AH and registers the assets of one or more Asset Owners

and (h) an Upgrade Sponsor that executes the Service Agreement specified in

Attachment AH.

ATTACHMENT J

RECOVERY OF COSTS ASSOCIATED WITH NEW FACILITIES V. Other Network Upgrades

A. Sponsored Upgrades

The Directly Assigned Upgrade Cost of a Sponsored Upgrade shall

be borne voluntarily by the Project Sponsor. The Project Sponsor shall

execute an Agreement for Sponsored Upgrade in which it agrees to bear

these Directly Assigned Upgrade Costs. In the Agreement, the Project

Sponsor shall elect to pay for the Sponsored Upgrade by (1) a lump sum

payment or (2) periodic charges calculated in accordance with

Commission policy (both hereafter referred to as “Project Sponsor’s

Payment”). Such periodic charges shall be paid on a monthly basis over a

twenty year period unless a different frequency and/or shorter term is

established in the Agreement for Sponsored Upgrade. The present value of

the Project Sponsor’s Payment shall equal the present value of the annual

revenue requirements of the Sponsored Upgrade over a twenty year plant

life. The annual revenue requirements of the Sponsored Upgrade shall be

calculated by multiplying the levelized fixed charge rate of the

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Transmission Owner, based on full depreciation over a 20 year plant life

and including operating and maintenance expenses and any applicable tax

consequences, by the nondepreciated actual cost of the Sponsored

Upgrade.

The Transmission Provider shall file the Agreement initially

utilizing good faith estimates of the construction costs for the assigned

upgrade. Upon completion of the Sponsored Upgrade, the Transmission

Provider shall true up the Directly Assigned Upgrade Costs to the actual

construction costs as appropriate and calculate the Project Sponsor’s

Payment.

In addition, the Directly Assigned Upgrade Cost of the Sponsored

Upgrade shall be reduced as provided in Section VII of this Attachment J

and by any revenue credits granted to a Transmission Owner for the use of

the Sponsored Upgrade.

The Project Sponsor may elect to receive either transmission

revenue credits in accordance with Attachment Z2 or ILTCRs as specified

in the Agreement for Sponsored Upgrade described under Schedule 1 to

this Attachment J. If the Project Sponsor elects to receive candidate

ILTCRs, the Project Sponsor must also execute Attachment AH to this

Tariff if the Project Sponsor is not already a Market Participant.

B. Service Upgrades

The cost of a Service Upgrade shall be allocated in accordance

with Attachment Z1 to this Tariff. The Transmission Customer may elect

to receive eithershall receive transmission revenue credits in accordance

with Attachment Z2 of this Tariff or candidate ILTCRs for any Directly

Assigned Upgrade Costs. If the Transmission Customer elects to receive

revenue credits pursuant to Section II of Attachment Z2 of this Tariff then

the Transmission Customer shall not be eligible for ILTCRs for the Direct

Assigned Upgrade Costs. If the Transmission Customer elects to receive

candidate ILTCRs pursuant to Section IV of Attachment Z2 of this Tariff,

then the candidate ILTCR MW and source to sink facility(ies) paths

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related to the candidate ILTCRs shall be included in the Transmission

Service Agreement or Network Integration Transmission Service

agreement.

C. Generation Interconnection Related Network Upgrades

The cost of a generation interconnection related Network Upgrade

shall be allocated in accordance with Attachment V to this Tariff. The

Interconnection Customer shall may elect to receive either transmission

revenue credits in accordance with Section II of Attachment Z2. of this

Tariff or candidate ILTCRs for any Directly Assigned Upgrade Costs

pursuant to Section IV of Attachment Z2 of this Tariff. If the

Interconnection Customer elects to receive ILTCRs then the candidate

ILTCR MW and source to sink facility(ies) paths related to the candidate

ILTCRs shall be included in the Interconnection Customer’s Generation

Interconnection Agreement.

D. Zonal Reliability Upgrades

1. The cost of Zonal Reliability Upgrades (i) included in the

2005 SPP Transmission Expansion Plan and (ii) placed in

service prior to January 1, 2008 shall be allocated in

accordance with Section III to this Attachment.

2. The cost of all other Zonal Reliability Upgrades shall be

includable in the applicable Zonal Annual Transmission

Revenue Requirement.

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Schedule 1 to Attachment J

Agreement For Sponsored Upgrade

This Agreement For Sponsored Upgrade ("Agreement") is entered into this _______ day of _____________________, ________, by and between _____________________________ ("Project Sponsor"), and Southwest Power Pool, Inc. ("Transmission Provider") on behalf of itself and the designated Transmission Owner(s). The Project Sponsor and Transmission Provider shall be referred to as "Parties."

WHEREAS, the Transmission Provider administers an Open Access Transmission Tariff

(“Tariff”) to provide Transmission Service within the Southwest Power Pool and acts as agent for the Transmission Owners in providing service under the Tariff; and

WHEREAS, the Sponsored Upgrade identified in the Specifications attached hereto has been

endorsed by the Markets and Operations Policy Committee and the Board of Directors of the Transmission Provider; and

WHEREAS, the Project Sponsor has agreed to bear the cost of the Sponsored Upgrade; and WHEREAS, the Parties intend that capitalized terms used herein shall have the same meaning as

in the Tariff; NOW, THEREFORE, in consideration of the mutual covenants and agreements herein, the

Parties agree as follows: 1.0 This Agreement shall become effective on the later of (l) the date of the execution of this

Agreement by both Parties or (2) such other date as it is permitted to become effective by the Commission. (“Effective Date”)

2.0 This Agreement shall terminate on the later of the following events: (1) the Project

Sponsor has fulfilled its obligation to make Project Sponsor’s Payment pursuant to section 3.0; or (2) the Transmission Provider has fulfilled its obligation to pay the Project Sponsor all revenue credits pursuant to section 5.0 if the Project Sponsor has elected to receive such revenue credits, recognizing that no obligation to pay revenue credits will remain after the Sponsored Upgrade has been permanently removed from service, or (3) the candidate ILTCR termination date if the Project Sponsor has elected to receive candidate ILTCRs in lieu of revenue credits.

3.0 Project Sponsor agrees to pay the Directly Assigned Upgrade Costs of the Sponsored Upgrade pursuant to Attachment J of the Tariff. Project Sponsor has elected to pay for the Sponsored Upgrade in one of the following manners, as indicated in the Specifications attached hereto: (1) by a lump sum payment or (2) a periodic charge, both hereinafter referred to as “Project Sponsor’s Payment.” The Parties recognize that the initial Project Sponsor’s Payment will be based on an estimate of the Directly Assigned Upgrade Costs. While Transmission Provider represents that the Project Sponsor’s Payment is based on a good faith estimate of the Directly Assigned Upgrade Costs, such estimate shall not be binding, and the Project Sponsor shall compensate the Transmission Provider and designated Transmission Owner(s) for all costs incurred pursuant to the provisions of the Tariff. Promptly after the Sponsored Upgrade is placed in service, Transmission Provider shall adjust the Project Sponsor’s Payment to reflect all such costs incurred, as appropriate.

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4.0 Project Sponsor shall maintain a Letter of Credit in the amount specified in this

Agreement or such other form of security acceptable to Transmission Provider pursuant to Attachment X of the Tariff until such time as the Project Sponsor has fulfilled its obligation to make Project Sponsor’s Payment pursuant to section 3.0.

5.0 Transmission Provider agrees to provide Project Sponsor with either revenue credits

pursuant to Attachment Z2 of the Tariff or candidate ILTCRs in the amounts on specific source-to-sink paths as documented in this Schedule 1. Revenue credits or candidate ILTCRs shall be the exclusive compensation of the Project Sponsor under this Agreement. Such election shall be documented in Schedule 1.

6.0 Transmission Provider agrees to arrange for the construction of the Sponsored Upgrade in

accordance with the Tariff, the SPP Membership Agreement and the construction timeline specified herein.

7.0 Any notice or request made to or by either Party regarding this Agreement shall be made

to the representative of the other Party as indicated below.

Southwest Power Pool, Inc.:

_____________________________________

201 Worthen Drive

Little Rock, AR 72223-4936

Project Sponsor:

_____________________________________

_____________________________________

_____________________________________

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8.0 The Tariff is incorporated herein and made a part hereof for all purposes.

IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their

respective authorized officials.

Southwest Power Pool, Inc.:

By:______________________ _____________________ _____________________

Name Title Date

Project Sponsor:

By:______________________ _____________________ _____________________

Name Title Date

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 36 of 59

Specifications

1.0 Designated Transmission Owner(s): _________________________________________

2.0 Description of Sponsored Upgrade: __________________________________________

_______________________________________________________________________

_______________________________________________________________________

_______________________________________________________________________

_______________________________________________________________________

_______________________________________________________________________

3.0 Project Sponsor’s Payment:* The Project Sponsor shall elect to pay the Directly Assigned

Upgrade Grade Costs of the Sponsored Upgrade by (1) a lump sum payment or (2) a periodic

charge as indicated below:

_____ Lump Sum Payment:_________________________________________________

Payment Due Date:_____________________________________________

_____Periodic Charge:_____________________________________________________

_______________________________________________________________________

_______________________________________________________________________

* The Project Sponsor’s Payment specified herein shall initially be based on a good faith

estimate of Directly Assigned Upgrade Costs. The Project Sponsor’s Payment shall be subject to

adjustment and true up after the Sponsored Upgrade is placed in service.

4.0 Project Sponsor’s Credit. The Project Sponsor shall elect to receive compensation either through

(1) the revenue crediting process described under Section II of Attachment Z2 to this Tariff or

(2) through receipt of candidate ILTCRs where the MW amount of such candidate ILTCRs have

been determined using the process described under Section IV of Attachment Z2 of this Tariff.

If the Project Sponsor selects Option (2), a Termination Date will be mutually agreed to by the

parties such that the specified ILTCR has a life of at least ten (10) years and no more than twenty

(20) years.

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 37 of 59

_________Attachment Z2 Revenue Credits

_________Candidate Incremental LTCRs

* Source _________

* Sink ___________

* Candidate Incremental LTCR MW _______

* Termination Date (Min of 10 years) __________

54.0 Project Timeline (Milestones): ______________________________________________

_______________________________________________________________________

_______________________________________________________________________

_______________________________________________________________________

_______________________________________________________________________

_______________________________________________________________________

65.0 Letter of Credit:__________________________________________________________

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 38 of 59

ATTACHMENT X

ARTICLE TWO

Definitions

2.1 Definitions. The following definitions apply in this Credit Policy. Capitalized terms used herein and

not defined herein shall be given the meaning assigned to them under the Tariff

Incremental Long-Term Congestion Right (ILTCR) This term shall have the meaning given in Section 1 of this Tariff.

ARTICLE FIVE A

Transmission Congestion Rights (TCRs)

5A.1 Overview

5A.1.1 Transmission Congestion Rights create potential exposure of non-payment, and therefore,

have a credit requirement. SPP will establish a Total TCR Credit Requirement for each

Credit Customer holding TCRs or participating in a TCR Auction. A Credit Customer

may satisfy its Total TCR Credit Requirement by providing Financial Security.

Unsecured Credit is not available to support a Credit Customer’s holding of TCRs or

activity in TCR Auctions. Additionally, SPP’s prior approval is required for a Credit

Customer to acquire or transfer TCRs through bilateral transactions.

5A.1.2 To establish the credit requirement associated with TCRs, SPP analyzes: (i) the TCRs

the Credit Customer holds (including TCRs held via self-conversion from ARRs); (ii)

the Credit Customer’s Bids and Offers for TCRs in the TCR Auctions; (iii) TCR

payments or charges for which settlement has been calculated but not yet invoiced; and

(iv) TCR payments or charges for which an invoice has been issued but payment has

not occurred.

(a) SPP calculates the potential exposure associated with the full portfolio of TCRs

that are held by the Credit Customer including TCRs obtained from LTCRs and

ILTCRs.

(b) SPP evaluates individually each TCR Bid in the TCR Auctions to ensure that

the Credit Customer has sufficient Financial Security to cover the credit

Formatted: Font: Bold

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requirements to purchase and hold the TCR. Only the TCR Bids for which the

Credit Customer has sufficient Financial Security will be credit approved for

consideration in the TCR Auction.

(c) SPP evaluates individually each TCR Offer in the TCR Auctions to ensure that

the Credit Customer has sufficient Financial Security to cover any credit

requirements associated with the Offer and the credit requirements for the

retained TCR portfolio that would result if the TCR Offer clears in the TCR

Auction. Only the TCR Offers for which the Credit Customer has sufficient

Financial Security will be credit approved for consideration in the TCR

Auction.

(d) Additionally, SPP analyzes the credit requirements associated with TCRs that

are the subject of a proposed bilateral transfer prior to providing approval of

such transfers. SPP approval of a bilateral transfer for TCRs is required for such

bilateral transfers to be completed.

5A.1.3 As part of the determination of the credit requirement associated with TCRs, SPP

calculates the Estimated TCR Exposure (ETCRE), which is an estimate of the potential

value of the TCR over the life of the TCR. In the case of a TCR associated with a

LTCR or ILTCR, the life of the TCR shall be considered one year. It will be calculated

for all TCRs the Credit Customer holds, the Credit Customer’s TCR Bids and TCR

Offers, proposed TCR bilateral transfers, and TCRs acquired through ARR self-

conversion. SPP will determine the credit requirement associated with TCRs and

whether the Credit Customer has available Financial Security to support its TCR

activity. After the close of a TCR Auction and on an ongoing basis, SPP will update the

Credit Customer’s Total TCR Credit Requirement associated with TCRs to reflect the

actual TCRs the Credit Customer holds and TCR Auction results, including the costs to

acquire or sell TCRs in a TCR Auction.

5A.1.4 This Article addresses the calculation of the Total TCR Credit Requirement associated

with TCRs, including the ETCRE calculations for the TCRs the Credit Customer holds

and the Credit Customer’s Bids and Offers for TCRs in the TCR Auctions and the

acquisition and disposal costs of the TCR in the TCR Auctions; as well as the TCR

payments or charges for which settlement has been calculated but not yet invoiced; and

the TCR payments or charges for which an invoice has been issued but payment has not

occurred. This Article also addresses the determination whether a Credit Customer has

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 40 of 59

sufficient Financial Security available for the Credit Customer’s proposed TCR

Auction activity or proposed bilateral transfers of TCRs.

ATTACHMENT Z2

REVENUE CREDITING FOR UPGRADES I. Creditable Upgrades

A. Any Network Upgrade which was paid for, in whole or part, through revenues collected

from a Transmission Customer, Network Customer, or Generation Interconnection

Customer through Directly Assigned Upgrade Costs shall be considered a Creditable

Upgrade except where an Upgrade Sponsor has elected to receive candidate ILTCRs and

has confirmed such election through execution of the applicable agreements as described

under Section IV of this Attachment Z2.

B. A Sponsored Upgrade is not automatically a Creditable Upgrade nor is it automatically

eligible to receive revenue credits since Sponsored Upgrades are not built to satisfy a

need identified by the Transmission Provider. For a Sponsored Upgrade to become a

Creditable Upgrade, the Transmission Provider must determine that the Sponsored

Upgrade is needed as part of the Transmission System. At the time the Sponsored

Upgrade becomes a Creditable Upgrade, the Transmission Provider shall determine the

direction of flow which caused the Creditable Upgrade to be needed and the capability in

the opposite direction.

C. A Creditable Upgrade shall cease being a Creditable Upgrade when: (1) the facility is

permanently removed from service, (2) all the Upgrade Sponsors have been fully

compensated, or (3) the costs have been fully included in rates in accordance with

Section III of this Attachment Z2.

II. Revenue Crediting

An Upgrade Sponsor shall be eligible to receive revenue credits in accordance with this

Attachment Z2. The Directly Assigned Upgrade Costs are recoverable, with interest calculated in

accordance with 18 CFR §35.19a(a)(2), from new transmission service using the facility as defined

below until the amount owed the Upgrade Sponsor is zero. The provisions of this Attachment Z2 are

applicable to Transmission Owners subject to the provisions of Section 39.1 of this Tariff.

A. New Point-To-Point Transmission Service:

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Revenues from new Point-to-Point Transmission Service that could not be provided but

for the Creditable Upgrade(s) will be used, in whole or in part, for crediting purposes.

For each new point-to-point reservation that could not be provided but for one or more

Creditable Upgrades, made after (i) the commitment for such Creditable Upgrade by an

Upgrade Sponsor or (ii) the request causing the need for such Creditable Upgrade, with

service commencing after or extending beyond the date the Creditable Upgrade is

completed, the Upgrade Sponsor for each affected Creditable Upgrade shall receive a

portion of the transmission service charge equal to the positive response factor of such

new reservation on the Creditable Upgrade times the portion of the new reservation

capacity that could not be provided but for the Creditable Upgrade times the rate

applicable to such new reservation. For crediting purposes, the Transmission Provider

shall perform a one-time calculation of the response factor of such new reservation on the

Creditable Upgrade. This allocation from new service shall continue until the Upgrade

Sponsor has been fully compensated. Revenue credits will be paid to Upgrade Sponsors

in accordance with Section II.D of this Attachment Z2.

B. New Network Integration Transmission Service and Service to Transmission

Owners Taking Service Under Non-Rate Terms and Conditions:

Revenue for credits will be provided from (i) new Long-Term Network Integration

Transmission Service, and (ii) new transmission service taken under the non-rate terms

and conditions of this Tariff by Transmission Owners subject to Section 39.1 of this

Tariff, that could not be provided but for one or more Creditable Upgrades to

accommodate designation of new Network Loads or Transmission Owner’s(s’) loads,

new Designated Resources or increases in the designation of existing Designated

Resources above previously designated levels. Revenue credits shall be determined

based upon the subsequent incremental use of each affected Creditable Upgrade for such

new or increased Network Load or Transmission Owner load or Network Resource.

The annual revenue credit amount to be paid monthly by a Network Customer, or

included in rates, for each such new or increased use of a Creditable Upgrade shall be the

product of the total annual revenue requirement associated with the Creditable Upgrade

and the ratio of the incremental impact placed on the Creditable Upgrade by each such

new or increased use to the total of the incremental impacts placed on the Creditable

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Upgrade by all currently and previously identified incremental Network Integration

Transmission Service and Long-Term Firm Point-To-Point Transmission Service uses of

the Creditable Upgrade.

For the calculation of such revenue credits to be given to an Upgrade Sponsor for

subsequent use of a Creditable Upgrade, the incremental use assigned to such Upgrade

Sponsor shall be the capacity of the Creditable Upgrade minus all currently and

previously identified incremental Network Integration Transmission Service and Long-

Term Firm Point-To-Point Transmission Service uses. The cost of such revenue credit

amount shall be paid by the Network Customer making such new or increased use of the

Creditable Upgrade, or included in rates pursuant to the Base Plan and Balanced Portfolio

funding formulas in Attachment J, in addition to all other applicable charges under this

Tariff. Revenue credits will be paid to Upgrade Sponsors in accordance with Section

II.D of this Attachment Z2.

C. Power Controlling Devices:

1. New Network Integration Transmission Service:

Revenue credits will be provided for new Long-Term Network Integration Transmission

Service using the device in either direction to accommodate designation of new Network

Loads, new Designated Resources or increases in the designation of existing Designated

Resources above previously designated levels. Revenue credits shall be determined

based upon the subsequent additional incremental use of the device by any such new or

increased use.

The annual revenue credit amount to be paid monthly by a Network Customer, or

included in rates, for each such new or increased use of a Creditable Upgrade

shall be the product of the annual revenue requirement associated with the device

and the ratio of the incremental impact placed on the device by each such new or

increased use to the total of the incremental impacts placed on the device by all

currently and previously identified incremental Network Integration

Transmission Service and Long-Term Firm Point-To-Point Transmission Service

uses

of the device in both directions.

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For the calculation of such revenue credits to be given to an Upgrade Sponsor for

subsequent use of the device, the incremental use assigned to such Upgrade

Sponsor shall be the capacity of the device in both directions minus all currently

and previously identified incremental Network Integration Transmission Service

and Long-Term Firm Point-To-Point Transmission Service uses of the device in

both directions. The cost of such revenue credit amount shall be paid by the

Network Customer making such new or increased use of the device, or included

in rates pursuant to the Base Plan and Balanced Portfolio funding formulas in

Attachment J, in addition to all other applicable charges under this Tariff.

Revenue credits will be paid to Upgrade Sponsors in accordance with Section

II.D of this Attachment Z2.

2. New Point-To-Point Transmission Service:

Crediting for Long-Term Firm Point-To-Point Transmission Service using the

power controlling device in either direction shall be a portion of the transmission

service charge equal to the positive response factor of such new reservation on the

device times the new reservation capacity times the rate applicable to such new

reservation less any revenue credits applicable to other Network Upgrades on the

transmission path. Crediting for Short-Term Firm Point-To-Point Transmission

Service and Non-Firm Point-To-Point Transmission Service using the device in

either direction shall be the percent usage of the total revenue received by the

Transmission Provider that is not required for other transmission funding

obligations. Revenue credits will be paid to Upgrade Sponsors in accordance

with Section II.D of this Attachment Z2.

D. Distribution of Revenue Credits

1. For use of Creditable Upgrades which are also Service Upgrades, such revenue

credits shall be given to the original Upgrade Sponsor and to all previously

identified Upgrade Sponsors from incremental Network Integration Transmission

Service and Long-Term Firm Point-To-Point Transmission Service uses,

including prior incremental Network Integration Transmission Service uses that

resulted in the obligation to pay revenue credits. The grant of such revenue

credits shall be in proportion to the fraction of the annual revenue requirement

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associated with the Creditable Upgrade for which each Upgrade Sponsor is

responsible, net of any revenue credits previously applied.

2. For use of Sponsored Upgrades that qualify as Creditable Upgrades, such revenue

credits shall be given first to the Project Sponsor from new transmission service

using the Creditable Upgrade until the revenue credit due to the Project Sponsor

for that Creditable Upgrade is zero. Then such revenue credits shall be given to

all Upgrade Sponsor(s) of the Creditable Upgrade. The grant of such revenue

credits shall be in proportion to the fraction of the annual revenue requirement

associated with the Creditable Upgrade for which each Upgrade Sponsor is

responsible, net of any revenue credits previously applied.

3. For use of Creditable Upgrades associated with a Generator Interconnection

Agreement, revenue credits from new transmission service using the Creditable

Upgrade shall be given first to the Generation Interconnection Customer(s)

associated with the Creditable Upgrade until the revenue credit due is zero. Then

such revenue credits shall be given to all other Upgrade Sponsors of the

Creditable Upgrade. The grant of such revenue credits shall be in proportion to

the fraction of the annual revenue requirement associated with the Creditable

Upgrade for which each Upgrade Sponsor is responsible, net of any revenue

credits previously applied.

III. Future Roll-In

When a facility upgrade being paid for pursuant to the provisions of Attachment Z1 to this Tariff

is rolled into the revenue requirements used for the development of generally applicable transmission

service rates, the Transmission Owner that constructed the facility upgrade shall pay the remaining

balance of each customer’s unrecovered payments described in Sections VI.A and VI.B of Attachment

Z1 that are applicable to that facility upgrade. All customers who have upgraded facilities and have

remaining balances subject to cost recovery pursuant to Section VI of Attachment Z1, shall be paid in

full. The customer shall continue to pay the charges specified in the customer’s transmission service

agreement for the transmission service initially reserved.

IV Incremental LTCRs Formatted: Font: Bold

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For upgrades with Directly Assigned Upgrade Costs greater than or equal to $5,000,000,

the Upgrade Sponsor may elect to be paid for the upgrade through receipt of candidate

ILTCRs. In order to be eligible to receive candidate ILTCRs, the Upgrade Sponsor must

request the Transmission Provider to perform an analysis for the purposes of determining

available candidate ILTCRs. If so requested, the Transmission Provider shall perform the

following analysis:

a) If the upgrade is a Sponsored Upgrade, the Transmission Provider shall validate

that the upgrade has been evaluated and has not previously been approved via the

ITP, as defined in … If not, the sponsor will first submit the upgrade to be

evaluated as a potential solution in the next scheduled ITP.

b) The Upgrade Sponsor may request that up to three source-to-sink paths be

evaluated by the Transmission Provider to determine the amount of incremental

ATC created on these paths as a result of the portion of the upgrade associated

with the Directly Assigned Upgrade Cost.

cb) The Transmission Provider shall determine the minimum increase in ATC on

each of the requested paths over a ten-year period and communicate the MW

results to the Upgrade Sponsor. The Upgrade Sponsor may then decide to select

one of the requested paths on which candidate ILTCRs are desired and the

increase in ATC on that selected path shall be equal to the candidate ILTCRs on

that path. Such selection shall be documented in the applicable executed

agreements as specified under Attachment J to this Tariff. If the Upgrade Sponsor

does confirm selection of ILTCRs in the applicable executed agreement, then the

Upgrade Sponsor will continue to be eligible for revenue credits in accordance

with Section II of this Attachment Z2.

dc) The Transmission Provider will consider all awarded ILTCRs in all planning

studies on a going forward basis once the Upgrade Sponsor executes the

applicable agreements as specified under Attachment J of this Tariff.

ed) The Transmission Provider’s costs associated with studies for potential ILTCRs shall

be the responsibility of the Upgrade Sponsor’s requesting such studies.

Formatted: Indent: Left: 1", First line: 0",Line spacing: 1.5 lines

Comment [MWG161]: Reference

Formatted: Line spacing: 1.5 lines

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 46 of 59

Attachment AE

7.0 Transmission Congestion Rights Markets

The TCR Markets process includes an annual LTCR allocation, an annual ARR

allocation, annual and monthly TCR auctions and a monthly ARR allocation in accordance with

the timelines specified in the Market Protocols. The TCR Markets process is subject to review

by the Market Monitor consistent with Attachment AG of this Tariff. LTCRs are obtained by

Eligible Entities during the annual LTCR allocation. ARRs are obtained by Eligible Entities

during the annual ARR allocation or the monthly ARR allocation. TCRs are obtained by Market

Participants through the annual LTCR allocation and the annual and monthly TCR auctions.

There are eight (8) key processes associated with LTCRs, ARRs and TCRs:

(1) Annual LTCR/ARR verification and annual ILTCR verification;

(2) Annual LTCR allocation;

(3) Annual ARR allocation;

(4) Annual TCR auction;

(5) Monthly ARR allocation;

(6) Monthly TCR auction;

(7) ARR allocation and TCR auction settlements; and

(8) TCR secondary markets.

Table 7-1 in Section 7.4.2 of this Attachment AE provides additional details related to

auction timing and Transmission System capability available for the TCR auctions.

(b) Except as otherwise provided in this Section 7.0.b (ii), an entity taking firm transmission service

under a GFA Carve Out will not be eligible to participate in the TCR Markets for the MW capacity

associated with the GFA Carve Out.

(i) The MW capacity associated with each GFA Carve Out shall be included in the

Transmission Provider’s ARR allocation and TCR auction processes in a manner that

reflects the transmission service pursuant to the GFA Carve Out, provided, however, that

(A) candidate ARRs associated with the GFA Carve Out service shall not be nominated

for a product period if, based upon the twelve preceding months for which congestion

data is available, such ARR, had it been converted to a TCR, would have resulted in a net

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charge to the holder of the TCR over that product period, and (B) until twelve months of

Integrated Marketplace data are available, the Transmission Provider shall use relevant

data from both the EIS Market and the Integrated Marketplace to estimate whether the

result would have been a net charge to the TCR holder.

(ii) On an annual basis, the GFA Responsible Entity may elect, in writing, to cancel the GFA

Carve Out treatment and will be eligible to participate in the TCR Markets pursuant to

Section 7.0 of Attachment AE. The conversion of GFA Carve Out to the TCR Market is

irrevocable.

(c) Firm transmission capacity associated with a FSE shall not be eligible to participate in the TCR

Markets.

(i) The MW capacity associated with each FSE shall be included in the Transmission

Provider’s ARR allocation and TCR auction processes in a manner that reflects the

transmission service pursuant to the FSE, provided, however, that Candidate ARRs

associated with the FSE service shall not be nominated for a product period if, based

upon the twelve preceding months for which congestion data is available, such ARR, had

it been converted to a TCR, would have resulted in a net charge to the holder of the TCR

over that product period.

For the MW capacity associated with each FSE, the sink for the ARR/TCR shall be the

(1) load Settlement Location within the UMZ, (2) interface with an external Balancing Authority,

or (3) FSE Transfer Point, as appropriate. For ARR/TCR activity from FSE Transfer Points to

load external to the UMZ but internal to the Transmission Provider, the normal ARR/TCR

process is available to the applicable Market Participants from the FSE Transfer Point to the

load consistent with the transmission service reservation.

7.1 Annual Long-Term Congestion Right/Auction Revenue Right Verification and Incremental LTCR Verification

Only Eligible Entities are permitted to nominate candidate LTCRs and/or ARRs. Only

Upgrade Sponsors that are Market Participants that have received candidate ILTCRs through the

process described under Section IV of Attachment Z2 to this Tariff are eligible to nominate

candidate ILTCRs. The following rules apply to verification of firm transmission service for

conversion to LTCRs and/or ARRs and verification of ILTCRs.

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7.1.1 Transmission Service and Incremental Long-Term Congestion Rights Verification

In order for Eligible Entities to obtain candidate LTCRs and/or ARRs, the Transmission

Provider must first verify existing transmission service entitlements, including transmission

service entitlements that have been renewed in accordance with rollover rights since their initial

term. An Eligible Entity’s Transmission Service must span the entire monthly or seasonal period

for which ARRs are allocated to qualify for candidate ARRs in a particular month or season. An

Eligible Entity’s transmission service must span the entire annual period for which LTCRs are

allocated and must have rollover rights to qualify for candidate LTCRs. In order qualify for

candidate ILTCRs in the current allocation year, upgrades associated with the candidate ILTCRs

must be in-service prior to the start of the annual ILTCR verification. For Transmission Service

with rollover rights whose deadline for providing notice of rollover occurs after the annual

LTCR/ARR verification but before June 1, the Transmission Provider shall assume that the

rollover will occur and shall consider the Transmission Service entitlement to span the entire

allocation year, provided, however, that, if rollover rights for such Transmission Service are not

exercised by the applicable deadline, any ARRs, TCRs, or LTCRs associated with such

Transmission Service shall revert to the Transmission Provider effective on the date such

Transmission Service terminates. The Transmission Provider will verify Eligible Entity existing

Transmission Service entitlements as follows:

(1) The following will be performed prior to each annual LTCR and ARR allocation for

Eligible Entities taking Network Integration Transmission Service or Firm Point-To-

Point Transmission Service under the Tariff:

(a) The Transmission Provider will obtain source, sink and Reservation Capacity

information from the OASIS for each monthly and seasonal period for which

ARRs are allocated in which the transmission service spans the entire period, or

would if or when rolled over, for the current annual allocation and for the annual

period for which LTCRs are allocated in which the transmission service spans the

entire year;

(i) For a transmission service reservation with a source inside the SPP

Balancing Authority Area that is not a specific Resource or Resource

Market Hub, the Transmission Provider will determine the load Settlement

Location that most electrically corresponds to the source on the

transmission service reservation that will be utilized as the source for

candidate LTCRs and/or ARRs. Eligible Entities may create Resource

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specific Transmission Service reservations that represent their current

Transmission Service reservations using the process described in the

Market Protocols.

(ii) For a transmission service reservation with a source outside of the SPP

Balancing Authority Area, the interface between the Transmission

Provider and the first tier Balancing Authority Area associated with the

transmission reservation will be utilized as the source for candidate LTCRs

and/or ARRs.

(iii) For a transmission service reservation with a sink outside of the SPP

Balancing Authority Area, the interface between the Transmission

Provider and the first tier Balancing Authority Area associated with the

transmission reservation will be utilized as the sink for candidate LTCRs

and/or ARRs.

(iv) Eligible Entities taking Network Integration Transmission Service with

rollover rights under this Tariff shall be considered to have met the

definition of Load Serving Entity for purposes of LTCR allocation;

(v) Eligible Entities taking Firm Point-To-Point Transmission Service with

rollover rights under this Tariff shall not be considered a Load Serving

Entity for LTCR allocation purposes unless the Eligible Entity provides an

attestation to the Transmission Provider confirming that the Eligible

Entity is a Load Serving Entity as defined in this Attachment AE;

(b) The Transmission Provider will provide this information to each Eligible Entity

for verification; and

(c) Eligible Entities will notify the Transmission Provider within 2 weeks following

receipt of this information, identifying and correcting inaccurate data on the

OASIS. Otherwise, the Transmission Provider provided data will be considered

verified.

(2) The following will be performed prior to each annual LTCR and ARR allocation for the

Eligible Entity taking GFA service:

(a) Each Transmission Owner shall register any GFA for which candidate LTCRs

and/or ARRs are to be provided to the Transmission Owner or the transmission

customer under the GFA on the Transmission Provider’s OASIS. The

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Transmission Owner must provide the Transmission Provider with source, sink

and Reservation Capacity information for each GFA on the Transmission

Provider’s OASIS by registering each GFA with the Transmission Provider. The

Transmission Provider will use source, sink, and Reservation Capacity

information from the GFA registration for each monthly and seasonal period for

which ARRs are allocated and the annual period for which the LTCRs are

allocated. If both parties to the GFA are Market Participants with respect to the

GFA load, then the parties may jointly inform the Transmission Provider which

Market Participant will be allocated the candidate LTCRS and/or ARRs. If the

parties to the GFA do not so inform the Transmission Provider, or if only the

Transmission Owner that sold the GFA service is a Market Participant, then the

Transmission Owner that sold the GFA service will be allocated the candidate

LTCRs and/or ARRs associated with the GFA.

(i) For a GFA with a source inside the SPP Balancing Authority Area that is

not a specific Resource or Resource Market Hub, the Transmission

Provider will determine the load Settlement Location that most electrically

corresponds to the source on the Transmission Service reservation that

will be utilized as the source for candidate LTCRs and/or ARRs.

(ii) For a GFA with a source outside of the SPP Balancing Authority Area, the

interface between the Transmission Provider and the first tier Balancing

Authority Area associated with the transmission reservation will be

utilized as the source for the candidate LTCRs and/or ARRs.

(iii) For a GFA with a sink outside of the SPP Balancing Authority Area, the

interface between the Transmission Provider and the first tier Balancing

Authority Area associated with the transmission reservation will be

utilized as the sink for the candidate LTCRs and/or ARRs.

(iv) An Eligible Entity under a GFA taking the equivalent of Network

Integration Transmission Service with rollover rights shall be considered

to have met the definition of Load Serving Entity for purposes of LTCR

allocation;

(v) An Eligible Entity under a GFA taking the equivalent of Firm Point-To-

Point Transmission Service with rollover rights shall not be considered a

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Load Serving Entity for the purposes of LTCR allocation unless the

Eligible Entity provides an attestation to the Transmission Provider

confirming that the Eligible Entity is an Load Serving Entity as defined in

this Attachment AE;

(b) If the transmission customer under the GFA is receiving the candidate ARRs, to

the extent that the transmission service specified in the GFA is identified as the

equivalent of SPP Network Integration Transmission Service, the transmission

customer under the GFA must provide the historical peak loads being served

under the GFA for the previous three years.

7.1.2 Candidate Long-Term Congestion Rights/Auction Revenue Rights

Following verification of an Eligible Entity transmission service and candidate ILTCRs,

candidate LTCRs and/or ARRs associated with such transmission service and candidate ILTCRs

are assigned as follows:

(1) For each Eligible Entity with Network Integration Transmission Service, the Eligible

Entity’s Network Integration Transmission Service Candidate LTCRs and/or candidate

ARRs from a specific source is equal to the source Reservation Capacity.

(a) An Eligible Entity may select nominate Network Integration Transmission

Service Candidate LTCRs, as described in Section 7.2.4 of this Attachment AE

from a specific source to one or more sinks up to the amount of its available

Network Integration Transmission Service Candidate LTCRs associated with the

source such that the total of such selections nominations does not exceed the

lesser of the sum of Network Integration Transmission Service Candidate LTCRs

or the limit described under Section 7.1.3(1)(b) for that Eligible Entity.

(b) An Eligible Entity may nominate Network Integration Transmission Service

Candidate ARRs, as described in Section 7.3.1 of this Attachment AE from a

specific source to one or more sinks up to the amount of its Network Integration

Transmission Service Candidate ARRs associated with the source subject to the

total nomination cap described in Section 7.1.3 of this Attachment AE.

(2) For each Eligible Entity with Firm Point-To-Point Transmission Service, the Eligible

Entity’s Firm Point-To-Point Candidate LTCRs and/or ARRs for a specific source and

sink is equal to the Reservation Capacity associated with that source and sink.

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 52 of 59

(a) An Eligible Entity may select nominate Firm Point-To-Point Candidate LTCRs, as

described in Section 7.2 of this Attachment AE, for this specific source and sink

up to the amount of its available Firm Point-To-Point Candidate LTCRs such that

the total of such selections nominations does not exceed the total Firm Point-To-

Point Candidate LTCRs available for that Eligible Entity.

(b) Firm Point-To-Point Candidate ARRs may be nominated by an Eligible Entity, as

described in Section 7.3.1 of this Attachment AE, for this specific source and sink

up to the amount of its Firm Point-To-Point Candidate ARRs subject to the total

nomination cap described in Section 7.1.3 of this Attachment AE.

(3) A holder of candidate ILTCRs may nominate the candidate ILTCRs up to the MW

amount for the specific source and sink path documented through the process described

under Section IV of Attachment Z2 to this Tariff less previously awarded ILTCRs.

(43) For each Eligible Entity with equivalent Network Integration Transmission Service GFA

service, the Eligible Entity’s Grandfathered Agreement Network Integration

Transmission Service Candidate LTCRs and/or ARRs from a specific source is equal to

the source Reservation Capacity.

(a) An Eligible Entity may select nominate Grandfathered Agreement Network

Integration Transmission Service Candidate LTCRs, as described in Section 7.2 of

this Attachment AE, from a specific source to one or more sinks up to the amount

of its available Grandfathered Agreement Network Integration Transmission

Service Candidate LTCRs such that the total of such selections nominations does

not exceed the lesser of the sum of Grandfathered Agreement Network Integration

Transmission Service Candidate LTCRs or the limit described under Section

7.3.1(3)(b) for that Eligible Entity.

(b) An Eligible Entity may nominate Grandfathered Agreement Network Integration

Transmission Service Candidate ARRs, as described in Section 7.3.1 of this

Attachment AE, from a specific source to one or more sinks up to the amount of

its Grandfathered Agreement Network Integration Transmission Service

Candidate ARRs subject to the total nomination cap described in Section 7.1.3 of

this Attachment AE.

(54) For each Eligible Entity with equivalent Firm Point-To-Point GFA service, the Eligible

Entity’s Grandfathered Agreement Firm Point-To-Point Candidate LTCRs and/or ARRs

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 53 of 59

for a specific source and sink is equal to the Reservation Capacity associated with that

source and sink.

(a) An Eligible Entity may select nominate Grandfathered Agreement Firm Point-To-

Point Candidate LTCRs, as described in Section 7.2 of this Attachment AE, for

this specific source and sink up to the amount of its available Grandfathered

Agreement Firm Point-To-Point Candidate LTCRs such that the total of such

selections nominations does not exceed the total Grandfathered Agreement Firm

Point-To-Point Candidate LTCRs available for that Eligible Entity.

(b) An Eligible Entity may nominate Grandfathered Agreement Firm Point-To-Point

Candidate ARRs, as described in Section 7.3.1 of this Attachment AE, for this

specific source and sink up to the amount of its Grandfathered Agreement Firm

Point-To-Point Candidate ARRs subject to the total nomination cap described in

Section 7.1.3 of this Attachment AE.

7.2 Annual Long-Term Congestion Right Allocation Eligible Entities may select nominate the candidate LTCRs and candidate ILTCRs that

they wish to receive up to their available candidate LTCRs and candidate ILTCRs. The feasible

portion of the selected nominated candidate ARRs LTCRs and nominated candidate ILTCRs are

awarded to each Eligible Entity and candidate ILTCR holder during the LTCR annual

allocation. Available Nominated candidate LTCRs and candidate ILTCRs are evaluated on an

annual basis in a two-step, single round process; (i) nominated candidate LTCRs associated with

Eligible Entities that are Load Serving Entities are evaluated in accordance with Section 7.2.2

and (ii) remaining nominated candidate LTCRs associated with Eligible Entities that are not

Load Serving Entities and candidate ILTCRS are then evaluated in accordance with Section

7.2.3.

The Transmission Provider shall make available fifty percent (50%) of the projected

maximum Transmission System capability for the purpose of LTCR and ILTCR allocation in the

annual LTCR allocation process. No later than five (5) days prior to the start of the annual

LTCR allocation process, the Transmission Provider shall post the Transmission System network

topology, including the corresponding impacts from Parallel Flow, used to determine the

projected maximum Transmission System capability that will be used in the upcoming allocation.

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 54 of 59

7.2.1 LTCR and ILTCR Surrender

Eligible Entities may surrender previously awarded LTCRs and ILTCRs in 0.1 MW

increments. Prior to annual LTCR allocation, Eligible Entities shall submit the following

information:

(1) Source (valid candidate LTCR source Settlement Location);

(2) Sink (valid candidate LTCR sink Settlement Location);

(3) Surrendered LTCR MW (cannot exceed previously awarded LTCR);

(4) Surrendered ILTCR MW (cannot exceed previously awarded ILTCR).

7.2.2 LTCR and ILTCR Nomination

Eligible Entities and holders of candidate ILTCRs shall submit the following information in

order to nominate LTCRs and ILTCRs that were not previously awarded:

(a) Source (valid candidate LTCR and/or ILTCR source Settlement Location);

(b) Sink (valid candidate LTCR and/or ILTCR sink Settlement Location);

(c) LTCR MW (total LTCR MW nominated from a source Settlement Location cannot

exceed the source candidate LTCR MW as previously determined under Section 7.1.2 of

this Attachment AE less previously awarded LTCRs plus surrendered LTCRs);

(d) ILTCR MW (total ILTCR MW nominated from a source Settlement Location cannot

exceed the source candidate ILTCR MW as previously determined under Section 7.1.2 of

this Attachment AE less previously awarded ILTCRs plus surrendered ILTCRs);

7.2.32 Available Long-Term Congestion Rights for Load Serving Entities A Simultaneous Feasibility Test is performed to determine the amount of available

LTCRs that may be selected and awarded LTCRs for Eligible Entities that are LSEs. The

Simultaneous Feasibility Test is performed using the most current Network Model for the

corresponding LTCR allocation period. For the Simultaneous Feasibility Test, all nominated

candidate Load Serving Entity LTCRs are modeled as a generation injection at the source and a

corresponding load withdrawal at the sink. In addition, all previously awarded LTCRs and

ILTCRs, that have not been surrendered, which are associated with Eligible Entities that are not

LSEs, are modeled as fixed injections and withdrawals provided that such LTCRs must meet the

criteria as specified in Section 7.1.1 of this Attachment AE, or such LTCRs and ILTCRs have

not been surrendered as described under Section 7.2.1 of this Attachment AE. To the extent that

these previously awarded LTCRs and ILTCRs are no longer feasible, the Transmission Provider

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 55 of 59

will make the minimum adjustments necessary to the ratings of the applicable transmission

facilities in the model in order to allow the model to produce a feasible solution.

If all nominated candidate Load Service Entity LTCRs are feasible, then all nominated

Load Service Entity LTCRs are awarded. If the nominated candidate Load Serving Entity

LTCRs are not feasible, the amount of candidate LTCRs available for selection and award

awarded LTCRs will be reduced using a weighted least squares method. The weighted least

squares method minimizes the sum of the squared deviations between the actual LTCR amounts

and the candidate LTCR amounts, weighted by the reciprocal of the candidate LTCR amounts,

which results in a higher percentage LTCR reduction for those nominations having the greatest

impact on the constraints. LTCR reductions associated with candidates that have an equal

impact on the constraints are reduced by the same percentage. Previously awarded Load

Serving Entity LTCRs are guaranteed to be available using the iterative methodology described

in the Market Protocols; provided that such Load Serving Entity LTCRs must meet the criteria as

specified in Section 7.1.1 of this Attachment AE, or have not been surrendered as described

under Section 7.2.1 of this Attachment AE. To the extent that these previously awarded Load

Serving Entity LTCRs are no longer feasible, the Transmission Provider will make the minimum

adjustments necessary to the ratings of the applicable transmission facilities in the model in

order to allow the model to produce a feasible

7.2.43 Available Long-Term Congestion Rights for Non-Load Serving Entities

A Simultaneous Feasibility Test is performed to determine the amount of available

LTCRs that may be selected and awarded LTCRs for Eligible Entities that are not Load Serving

Entities and holders of candidate ILTCRs. The Simultaneous Feasibility Test is performed using

the most current Network Model for the corresponding LTCR allocation period. For the

Simultaneous Feasibility Test, all nominated candidate non-Load Serving Entity LTCRs and

candidate ILTCRs are modeled as a generation injection at the source and a corresponding load

withdrawal at the sink. In addition all available awarded LTCRs associated with Eligible Entities

that are Load Serving Entities as calculated under Section 7.2.32 of this Attachment AE are

modeled as fixed injections and withdrawals and all previously awarded LTCRs and ILTCRs are

modeled as fixed injections and withdrawals provided that such previously awarded LTCRs must

meet the criteria as specified in Section 7.1.1 of this Attachment AE, or such LTCRs and

ILCTRs have not been surrendered as described under Section 7.2.1 of this Attachment AE. To

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 56 of 59

the extent that these previously awarded LTCRs and ILTCRs are no longer feasible, the

Transmission Provider will make the minimum adjustments necessary to the ratings of the

applicable transmission facilities in the model in order to allow the model to produce a feasible

solution.

If all nominated candidate non-Load Serving Entity LTCRs and all nominated candidate

ILTCRs are feasible, then all nominated non-Load Serving Entity LTCRs and all nominated

candidate ILTCRs are awarded. If the nominated candidate non-Load Serving Entity LTCRs and

nominated candidate ILTCRs are not feasible, the amount of candidate LTCRs available for

selection and award awarded LTCRs and ILTCRs will be reduced using a weighted least

squares method. The weighted least squares method minimizes the sum of the squared

deviations between the actual LTCR and ILTCR amounts and the candidate LTCR and candidate

ILTCR amounts, weighted by the reciprocal of the candidate LTCR amounts and candidate

ILTCR amounts, which results in a higher percentage LTCR reduction for those nominations

having the greatest impact on the constraints. LTCR reductions associated with candidates that

have an equal impact on the constraints are reduced by the same percentage.

Previously awarded non-Load Serving Entity LTCRs are guaranteed to be available

using the iterative methodology described in the Market Protocols; provided that such non-Load

Serving Entity LTCRs must meet the criteria as specified in Section 7.1.1 of this Attachment AE,

or which have not been surrendered as described under Section 7.2.1 of this Attachment AE. To

the extent that these previously awarded non-Load Serving Entity LTCRs are no longer feasible,

the Transmission Provider will make the minimum adjustments necessary to the ratings of the

applicable transmission facilities in the model in order to allow the model to produce a feasible

solution.

7.2.45 LTCR Selection andand ILTCR Awards

(1) All previously awarded LTCRs and previously awarded ILTCRs are automatically awarded as

LTCRs and LTCRs for the current allocation year; provided that such LTCRs and ILTCRs meet

the criteria specified in Section 7.1.1 of this Attachment AE; or were not surrendered as

described under Section 7.2.1 of this Attachment AE.

(2) Additional Load Serving Entity LTCRs are selected and awarded as described under Section

7.2.3 of this Attachment AE in a single-round process. Eligible Entities may select:

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 57 of 59

(3) Additional non-Load Serving Entity LTCRs and additional ILTCRs are awarded as described

under Section 7.2.4 of this Attachment AE

(a) Available LTCRs from its Network Integration Transmission Service Candidate LTCRs, less

any previously awarded LTCRs plus any surrendered LTCRs associated with Network

Integration Transmission Service Candidate LTCRs;

(b) Available LTCRs from its Firm Point-To-Point Candidate LTCRs, less any previously

awarded LTCRs plus any surrendered LTCRs associated with Firm Point-To-Point

Candidate LTCRs;

(c) Available LTCRs from its Grandfathered Agreement Network Integration Transmission

Service Candidate LTCRs as described under Section 7.1.2 of this Attachment AE, less any

previously awarded LTCRs plus any surrendered LTCRs associated with Grandfathered

Agreement Network Integration Transmission Service Candidate LTCRs; and/or

(d) Available LTCRs from its Grandfathered Agreement Firm Point-To-Point Candidate LTCRs

as described under Section 7.1.2 of this Attachment AE, less any previously awarded LTCRs

plus any surrendered LTCRs associated with Grandfathered Agreement Firm Point-To-Point

Candidate LTCRs;

(3) Eligible Entities shall submit the following information in order to select LTCRs that were

not previously awarded:

(a) Source (valid candidate LTCR source Settlement Location);

(b) Sink (valid candidate LTCR sink Settlement Location);

(c) LTCR MW (total LTCR MW selected from a source Settlement Location cannot exceed the

source candidate available LTCR MW as previously determined under Section 7.2.2 or

Section 7.2.3 of this Attachment AE less previously awarded LTCRs plus surrendered

LTCRs);

(4) All selected awarded LTCRs and ILTCRs as described in subsections (1) through (3) above are

automatically awarded, and these awarded LTCRs and those awarded as described under (1) above are

directly converted to TCRs prior to the annual ARR allocation for the current allocation year.

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 58 of 59

7.3 Annual Auction Revenue Right Allocation

The annual ARR allocation addresses how candidate ARRs verified in the annual

LTCR/ARR verification may be nominated and awarded. Eligible Entities may nominate the

candidate ARRs that they wish to receive up to their ARR nomination caps less any LTCRs

awarded. No candidate ARRs are available from un-awarded ILTCRs. The portion of the

nominated candidate ARRs that are simultaneously feasible are allocated to each Eligible Entity

during the annual allocation. Candidate ARRs are nominated on a monthly and seasonal basis in

a three round process.

The Transmission Provider shall make available one hundred percent (100%) of the

projected maximum Transmission System capability for the purpose of ARR allocation in the

annual ARR allocation process. No later than five (5) days prior to the start of the annual ARR

allocation process, the Transmission Provider will post the Transmission System network

topology data for each of the monthly and seasonal On-Peak and Off-Peak models, including the

corresponding Parallel Flow and transmission line outage assumptions, used to determine the

projected maximum Transmission System capability that will be used in the upcoming

allocations.

7.3.3 Annual Auction Revenue Right Awards

A Simultaneous Feasibility Test is performed in each round of the ARR allocation to

determine the amount of nominated ARRs to be awarded. The Simultaneous Feasibility Test is

performed using the most current Network Model including planned transmission outages for

the corresponding ARR allocation period. For the Simultaneous Feasibility Test, a nominated

candidate ARR is modeled as a generation injection at the source and a corresponding load

withdrawal at the sink. All directly converted TCRs from awarded LTCRs and awarded ILTCRs

are modeled as fixed injections and withdrawals.

If the nominated candidate ARRs are not feasible, the amount of nominated candidate

ARRs to be awarded will be reduced using a weighted least squares method. The weighted least

squares method minimizes the sum of the squared deviations between the actual ARR amounts

and the nominated ARR amounts, weighted by the reciprocal of the nominated ARR amounts,

which results in a higher percentage ARR reduction for those nominations having the greatest

impact on the constraints. ARR reductions associated with nominations that have an equal

impact on the constraints are reduced by the same percentage.

Attachment 6 - MPRR 227 Recommendation Report.docx 12/16/2014 Page 59 of 59

Every six (6) months for the first two (2) years after implementation of the Integrated

Marketplace, the Transmission Provider will analyze the net funding of TCRs through the Day-

Ahead Market. In the event the cumulative funding is at or below 90% or above 100%, the

Transmission Provider 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.

Proposed Criteria Language Revision N/A

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Indent: Left: 0.12", 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"

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DVER Logic Analysis

Raleigh Mohr

Number of Directives per Month For WGRs

0

10

20

30

40

50

60

70

80

# of

Dire

ctiv

es

2012 (EIS)2013 (EIS)2014 (EIS)2014 (IM)

2

Month 2012 (EIS) 2013 (EIS) 2014 (IM)

January 35 30 *44

February 34 26 *27

March 47 57 29

April 61 36 2

May 18 22 20

June 13 31 12

July 10 19 9

August 3 6 9

September 57 42 10

October 55 36 27

November 33 68 27

December 52 39

Grand Total 418 412 145

*Denotes Directives issued in EIS

2014 Integrated Marketplace Directives

Monthly Average

Projected 12 months in IM

Improvement (Yearly)

16 192 53.7%

Directives

3

• VER Capacity 2012: 7186 (NDVER, 7186)

• VER Capacity 2013: 7599 (NDVER, 5309)

• VER Capacity 2014: 8605 (NDVER, 5635)

RTBM Analysis of DVER vs. NDVER

• 3 random intervals were selected containing breached flowgates on otherwise normal operating days.

• Analysis was done by changing the 5 NDVERs with the greatest shift factors on commonly constrained flowgates to DVERs and re-running the SCED algorithm.

• The goal of this analysis was to quantify the impacts of dispatchability in the SCED solution.

• The results are on the following slides.

4

Case 1

Dispatch MW LMP Savings as DVER

As NDVER As DVER As NDVER As DVER

Resource A 90 90 -$213 -$36 $15,925

Resource B 54.1 49.1 -$120 -$11 $5,888

Resource C 60.5 49.2 -$242 -$44 $12,271

Resource D 66.1 66.1 -$213 -$36 $11,692

Resource E 24.8 0 -$120 -$11 $2,840

5

Violation Degree (MW) Shadow Price

As NDVERs As DVERs As NDVERs As DVERs

Constraint A 3 0 -$838 -$218

Case 2

Dispatch MW LMP Savings as DVER

As NDVER As DVER As NDVER As DVER

Resource A 31.6 26.6 -$157 -$133 $1,088

Resource B 5.2 .2 -$139 -$115 $414

Resource C 34.3 29.3 -$162 -$139 $1,167

Resource D 4.6 0 -$139 -$115 $378

Resource E 10.4 5.4 -$144 -$120 $554

6

Violation Degree (MW) Shadow Price

As NDVERs As DVERs As NDVERs As DVERs

Constraint A 5.2 2.3 -$517 -$474

Constraint B 10.3 5.0 -$486 -$405

Constraint C 1.12 1.08 -$696 -$744

Case 3

Dispatch MW LMP Savings as DVER

As NDVER As DVER As NDVER As DVER

Resource A 23.5 18.5 -$880 -$37 $19,872

Resource B 34.8 10.3 -$880 -$37 $29,775

Resource C 23.2 0 -$880 -$37 $19,984

Resource D 23.2 0 -$880 -$37 $19,984

Resource E 46.9 46.8 -$880 -$37 $39,555

7

Violation Degree (MW) Shadow Price

As NDVERs As DVERs As NDVERs As DVERs

Constraint A 2.3 0.9 -$888 -$624

Constraint B 21.8 0 -$1369 -$47

Constraint C 6.8 6.8 -$1178 -$1178

Variable Energy Resources Capacity

250 (1) 122 (1) 351 (4)

1679 (24)

301 (2)

1149 (13)

895 (10) 684 (14)

388 (5)

611 (7)

1396 (15)

135 (2)

0

500

1000

1500

2000

2500

3000

2007-04 2008 2009 2010 2011 2012 2013

Capa

city

in M

W (#

of R

esou

rces

)

Commercial Operational Date

NDVERDVER

8

VER Logic Next steps

• SPP is interested in MWG feedback – Does SPP need to provide more data to incent VERs to

register as DVERs?

– Should SPP propose a change in the DVER registration requirement?

– Do MPs have other ideas on how to incent more VERs to register as DVERs?

9

Re-pricing: Seeking MWG Approval for a Request to FERC December 9, 2014 Joe Ghormley, Senior Attorney (501) 614-3368 jghormley@spp.org

OVERVIEW • Before asking FERC for permission to re-price a particular hour (as

required by the Tariff), SPP seeks the MWG’s approval for such an action (as required by the Protocols).

• On May 21, 2014, several market intervals were identified for re-pricing. Re-pricing for most hours occurred in accordance with the Tariff, but two hours did not re-price in accordance with Tariff requirements.

• For one hour, re-pricing did not occur.

– The Tariff requires FERC permission for any re-pricing made later. – The Protocols require MWG, MOPC, and SPP BOD approval before

SPP makes a re-pricing request to FERC.

• For the other hour, the re-pricing occurred, but Market Participants did not receive notice within the time-frame set forth in the Tariff. Notification was sent at later date for this interval.

2

Brief Summary of Re-pricing Process • Upon identifying intervals in a given hour that need re-pricing,

Operations creates a “session” for those intervals in the POPS Repricing Management Tool (“PRMT”).

• Thereafter, Settlements uses the PRMT to “publish” each session,

which starts a process that updates the prices for each interval in the session at issue.

• Once the PRMT process completes, the updated prices are exported to

three different places: – the SPP portal, – the POPS Post-Production table for data backup, and – a reporting database used for the settlement statements

• An automated email advises MPs that updated prices were successfully

moved to the three areas above. This email serves to notify MPs of re-priced intervals pursuant to the Tariff and Protocols.

3

Re-pricing for May 21, 2014 • For Operating Date May 21, 2014, Operations identified 264 out of 288

intervals for re-pricing. • Operations divided these 264 intervals among 21 sessions in the PRMT.

• Operations completed its reviews on May 23, and Settlements began

processing the 21 sessions in order to post to the market portal by May 25.

• Processing time for each session increased to 3+ hours instead of the typical 5-30 minutes.

• Due to issues with the PRMT, Settlements had to rely on automated emails to determine whether each session processed successfully.

• In processing all 21 sessions, Settlements did not detect that PRMT had not sent confirmation emails for two of the sessions.

• Those sessions corresponded to the hours at issue in this matter.

4

Situation #1 - Hour ending 14

• For this hour, Operations identified all 12 five-minute intervals for re-pricing and created a session in the PRMT.

• Settlements initiated processing, but did not detect the absence of a confirmation email from PRMT for this session.

• The session had failed, and the new prices for the Hour ending 14:

– Did not move to POPs,

– Did not move to the Reporting database,

– Did not move to the market portal, and

– Were not reported to MPs via automated email.

5

Situation #1 - Hour ending 14, continued.

• For a re-pricing after the issuance of a final Settlement Statement, Attachment AE § 8.4(2) requires SPP to request FERC approval.

• SPP Protocols § 7.2.2.2 further requires SPP to obtain approval from the MWG, MOPC, and the BOD for the re-pricing and the request to FERC.

• SPP seeks MWG’s approval before it proceeds with the process of requesting permission from FERC as required by the Tariff.

6

Situation #2 – Hour ending 11

• For this particular hour, the re-pricing was performed, and the initial settlement statements reflected the updated price.

– The updated prices for this session moved to POPs and the Reporting database.

– The settlement statements reflected the updated prices because settlement calculations use database information.

• The portal did not reflect the new prices, however, and no notice of re-pricing was sent to MPs.

• Section 7.2.2.1 of the Protocols requires SPP to notify Market Participants no later than 5:00 p.m. four (4) Calendar Days after the Operating Day at issue.

• The Tariff does not appear to speak to this particular scenario.

7

Situation #2 – Hour ending 11, continued.

• After research and analysis, SPP concluded the most appropriate course of action was to notify MPs and correct the prices appearing on the portal.

• SPP has taken these steps.

• SPP proposes to notify FERC of the circumstances regarding this Hour ending 11 in any re-pricing request that may be filed regarding the Hour ending 14.

8

Resource Hub Inconsistency and Approval December 16-17, 2014

Nick Parker nparker@spp.org

Market Hubs

• Marketplace Hubs Task Force (MHTF) created the hubs process through MPRR90

• Tariff had some general ‘placeholder’ language prior to MPRR90

– Only made reference to Market Hubs

• Protocols had no language about hubs prior to MPRR90

– Market Hubs were split into 2 types Trading Hubs

Resource Hubs

– Separate approval processes were defined

2

MPRR90 Language

• Filed Tariff Language

– Market Hubs (Trading Hubs and Resource Hubs) shall obtain approval in accordance with the procedures in the Market Protocols

– Post approved Market Hubs 45 days prior to effective date

• Protocol Language

– Proposals for Resource Hubs submitted to SPP, and MMU will review

– Proposals for Trading Hubs submitted to MWG, further sent to MOPC for final approval

– Post approved Market Hubs 45 days prior to effective date

3

FERC Order on 9/20/2013 (ER13-1173-000) • Commission Determination from p406

– SPP has not supported its proposal to remove oversight authority from the SPP Board of Directors for the establishment, modification, or deletion of a Market Hub

– …nor has it demonstrated the ability to reduce the notification time by nearly 75 percent is just and reasonable

– We reject without prejudice SPP’s proposed revisions to section 3.1.1 of Attachment AE

4

Language Update for FERC Order • Tariff language

– MPRR 90 language was not incorporated into the Tariff – Original language stayed the same

• Protocol Language – Protocols are updated prior to FERC Order – Once FERC rejected the changes the Protocols should

have been updated to reflect the results of the Order – This update didn’t happen

Conflicting language between the Tariff and Protocols

Tariff has priority

5

Current Language • Original Tariff Language

– SPP will review any establishment, modification, or deletion of a Market Hub with stakeholders. The MOPC will review and make a recommendation to the Board of Directors for approval.

– Post approved Market Hubs 6 months prior to effective date

• Protocol Language – Proposals for Resource Hubs submitted to SPP, and MMU will

review

– Proposals for Trading Hubs submitted to MWG, further sent to MOPC for final approval

– Post approved Market Hubs 45 days prior to effective date

6

Steps going forward • Get in compliance with the Tariff

– Trading Hubs were approved by the MOPC and BOD so there is no issue

– There are currently 6 Resource Hubs in the commercial model that were submitted to SPP prior to the FERC Order, and have not been approved by the process in the current Tariff

– Seek Tariff required approval for these current Resource Hubs GRDA_HUB

GRDA_HUBSA

UCUHUB

GSPR2014HUB

OMPA_GENHUB

KCPLHUB

7

Steps going forward

• New Resource Hub requests will follow the process defined in the Tariff

• New MPRR will be developed to correct the discrepancy – Planned to take to January MWG

8

New Resource Hub Proposal

• GSPR2015HUB submitted by SPS on 12/3/2014 – Resources and weighting factors included in the

meeting materials

9

Settlement Location Aggregate Pnode Bus Level PnodeGRDA_HUB GRDA_H OKGEREDBUDUNU4GRDA_HUB GRDA_H OKGEREDBUDUNU3GRDA_HUB GRDA_H OKGEREDBUDUNU2GRDA_HUB GRDA_H OKGEREDBUDUNU1GRDA_HUB GRDA_H GRDASALINA1UN6GRDA_HUB GRDA_H GRDASALINA1UN5GRDA_HUB GRDA_H GRDASALINA1UN4GRDA_HUB GRDA_H GRDASALINA1UN3GRDA_HUB GRDA_H GRDASALINA1UN2GRDA_HUB GRDA_H GRDASALINA1UN1GRDA_HUB GRDA_H GRDAPENSA1UN6GRDA_HUB GRDA_H GRDAPENSA1UN5GRDA_HUB GRDA_H GRDAPENSA1UN4GRDA_HUB GRDA_H GRDAPENSA1UN3GRDA_HUB GRDA_H GRDAPENSA1UN2GRDA_HUB GRDA_H GRDAPENSA1UN1GRDA_HUB GRDA_H GRDAKERR_HYDUN4GRDA_HUB GRDA_H GRDAKERR_HYDUN3GRDA_HUB GRDA_H GRDAKERR_HYDUN2GRDA_HUB GRDA_H GRDAKERR_HYDUN1GRDA_HUB GRDA_H GRDAGRDA17UN2GRDA_HUB GRDA_H GRDAGRDA17UN1GRDA_HUBSA GRDASA_H OKGEREDBUDUNU4GRDA_HUBSA GRDASA_H OKGEREDBUDUNU3GRDA_HUBSA GRDASA_H OKGEREDBUDUNU2GRDA_HUBSA GRDASA_H OKGEREDBUDUNU1GRDA_HUBSA GRDASA_H GRDASALINA1UN6GRDA_HUBSA GRDASA_H GRDASALINA1UN5GRDA_HUBSA GRDASA_H GRDASALINA1UN4GRDA_HUBSA GRDASA_H GRDASALINA1UN3GRDA_HUBSA GRDASA_H GRDASALINA1UN2GRDA_HUBSA GRDASA_H GRDASALINA1UN1GRDA_HUBSA GRDASA_H GRDAPENSA1UN6GRDA_HUBSA GRDASA_H GRDAPENSA1UN5GRDA_HUBSA GRDASA_H GRDAPENSA1UN4GRDA_HUBSA GRDASA_H GRDAPENSA1UN3GRDA_HUBSA GRDASA_H GRDAPENSA1UN2GRDA_HUBSA GRDASA_H GRDAPENSA1UN1GRDA_HUBSA GRDASA_H GRDAKERR_HYDUN4GRDA_HUBSA GRDASA_H GRDAKERR_HYDUN3GRDA_HUBSA GRDASA_H GRDAKERR_HYDUN2GRDA_HUBSA GRDASA_H GRDAKERR_HYDUN1GRDA_HUBSA GRDASA_H GRDAGRDA17UN2GRDA_HUBSA GRDASA_H GRDAGRDA17UN1GSPR2014HUB GSPR2014HUB_H SPSWILDORADUNWINDFARMGSPR2014HUB GSPR2014HUB_H SPSTOLKSUBUN2

GSPR2014HUB GSPR2014HUB_H SPSTOLKSUBUN1GSPR2014HUB GSPR2014HUB_H SPSSPINSPURUNSPINSPUR_WINDGSPR2014HUB GSPR2014HUB_H SPSSAN_JUANUNWINDFARMGSPR2014HUB GSPR2014HUB_H SPSS_JALUNSUNE_SPS2GSPR2014HUB GSPR2014HUB_H SPSQUAYCNTYUNQUAYCOUNTY1GSPR2014HUB GSPR2014HUB_H SPSPLXSUBUN4GSPR2014HUB GSPR2014HUB_H SPSPLXSUBUN3GSPR2014HUB GSPR2014HUB_H SPSPLXSUBUN2GSPR2014HUB GSPR2014HUB_H SPSPLXSUBUN1GSPR2014HUB GSPR2014HUB_H SPSNICHSUBUN3GSPR2014HUB GSPR2014HUB_H SPSNICHSUBUN2GSPR2014HUB GSPR2014HUB_H SPSNICHSUBUN1GSPR2014HUB GSPR2014HUB_H SPSMONUMENTUNSUNE_SPS4GSPR2014HUB GSPR2014HUB_H SPSMADDOXSUUN2GSPR2014HUB GSPR2014HUB_H SPSMADDOXSUUN1GSPR2014HUB GSPR2014HUB_H SPSLP-HOLL2UNCOOKE_ST2GSPR2014HUB GSPR2014HUB_H SPSLP-HOLL2UNCOOKE_ST1GSPR2014HUB GSPR2014HUB_H SPSLP-HOLL2UNCOOKE_GT3GSPR2014HUB GSPR2014HUB_H SPSLP-HOLL2UNCOOKE_GT2GSPR2014HUB GSPR2014HUB_H SPSLLANOUNWNDFRMGSPR2014HUB GSPR2014HUB_H SPSLEA_ROADUNSUNE_SPS3GSPR2014HUB GSPR2014HUB_H SPSJONESSUBUN4GSPR2014HUB GSPR2014HUB_H SPSJONESSUBUN3GSPR2014HUB GSPR2014HUB_H SPSJONESSUBUN2GSPR2014HUB GSPR2014HUB_H SPSJONESSUBUN1GSPR2014HUB GSPR2014HUB_H SPSINDUSTR2UNRICHARDSON1GSPR2014HUB GSPR2014HUB_H SPSINDUSTR2UNENGCARBON1GSPR2014HUB GSPR2014HUB_H SPSHOPI_SUBUNSUNE_SPS5GSPR2014HUB GSPR2014HUB_H SPSHOBBSUN3BGSPR2014HUB GSPR2014HUB_H SPSHOBBSUN3GSPR2014HUB GSPR2014HUB_H SPSHOBBSUN2GSPR2014HUB GSPR2014HUB_H SPSHOBBSUN1GSPR2014HUB GSPR2014HUB_H SPSHARRSUBUN3GSPR2014HUB GSPR2014HUB_H SPSHARRSUBUN2GSPR2014HUB GSPR2014HUB_H SPSHARRSUBUN1GSPR2014HUB GSPR2014HUB_H SPSDOLLARHIUNSUNE_SPS1GSPR2014HUB GSPR2014HUB_H SPSCUNNSUBUN4GSPR2014HUB GSPR2014HUB_H SPSCUNNSUBUN3GSPR2014HUB GSPR2014HUB_H SPSCUNNSUBUN2GSPR2014HUB GSPR2014HUB_H SPSCUNNSUBUN1GSPR2014HUB GSPR2014HUB_H SPSCARLSBADUN5GSPR2014HUB GSPR2014HUB_H SPSCAPROCKUNWINDFARMGSPR2014HUB GSPR2014HUB_H SPSBLACKHAWUN2GSPR2014HUB GSPR2014HUB_H SPSBLACKHAWUN1GSPR2014HUB GSPR2014HUB_H LAM345LAMAR_DCUNDGSPR2014HUB GSPR2014HUB_H CSWSCALPINEUNONETA_4GSPR2014HUB GSPR2014HUB_H CSWSCALPINEUNONETA_3

GSPR2014HUB GSPR2014HUB_H CSWSCALPINEUNONETA_2GSPR2014HUB GSPR2014HUB_H CSWSCALPINEUNONETA_1KCPLHUB KCPLHUB_H NPPDJOHNSON2UN1KCPLHUB KCPLHUB_H NPPDJOHNSON1UN2KCPLHUB KCPLHUB_H NPPDJOHNSON1UN1KCPLHUB KCPLHUB_H NPPDJEFFREYUN2KCPLHUB KCPLHUB_H NPPDJEFFREYUN1KCPLHUB KCPLHUB_H KCPLWOLF_KCPUN17KCPLHUB KCPLHUB_H KCPLSPEARVILUNWINDFARMKCPLHUB KCPLHUB_H KCPLPAOLAUNUN1_OSAWACT1KCPLHUB KCPLHUB_H KCPLNRTHEASTUNNE18KCPLHUB KCPLHUB_H KCPLNRTHEASTUNNE17KCPLHUB KCPLHUB_H KCPLNRTHEASTUNNE16KCPLHUB KCPLHUB_H KCPLNRTHEASTUNNE15KCPLHUB KCPLHUB_H KCPLNRTHEASTUNNE14KCPLHUB KCPLHUB_H KCPLNRTHEASTUNNE13KCPLHUB KCPLHUB_H KCPLNRTHEASTUNNE12KCPLHUB KCPLHUB_H KCPLNRTHEASTUNNE11KCPLHUB KCPLHUB_H KCPLMONTROSEUNMON3KCPLHUB KCPLHUB_H KCPLMONTROSEUNMON2KCPLHUB KCPLHUB_H KCPLMONTROSEUNMON1KCPLHUB KCPLHUB_H KCPLLEVEEUNHAW8KCPLHUB KCPLHUB_H KCPLLEVEEUNHAW7KCPLHUB KCPLHUB_H KCPLLACYGNEUNLAC2KCPLHUB KCPLHUB_H KCPLLACYGNEUNLAC1KCPLHUB KCPLHUB_H KCPLIATANUNIAT2KCPLHUB KCPLHUB_H KCPLIATANUNIAT1KCPLHUB KCPLHUB_H KCPLHAWTHORNUNHAW6KCPLHUB KCPLHUB_H KCPLHAWTHORNUNHAW5KCPLHUB KCPLHUB_H KCPLCIMRONUNCIMRON_WINDKCPLHUB KCPLHUB_H KCPLC_HIGGNSUNHIG4KCPLHUB KCPLHUB_H KCPLBULLCRK5UNUNIT4KCPLHUB KCPLHUB_H KCPLBULLCRK5UNUNIT3KCPLHUB KCPLHUB_H KCPLBULLCRK5UNUNIT2KCPLHUB KCPLHUB_H KCPLBULLCRK5UNUNIT1OMPA_GENHUB OMPA_GENHUB_H WFECOMMANGMUNOMPA_MANGUMOMPA_GENHUB OMPA_GENHUB_H WFECOMLVRNEUNOMPA_LAVERNEOMPA_GENHUB OMPA_GENHUB_H OKGEREDBUDUNU4OMPA_GENHUB OMPA_GENHUB_H OKGEREDBUDUNU3OMPA_GENHUB OMPA_GENHUB_H OKGEREDBUDUNU2OMPA_GENHUB OMPA_GENHUB_H OKGEREDBUDUNU1OMPA_GENHUB OMPA_GENHUB_H OKGEOMPONCAUNOMPONCA4OMPA_GENHUB OMPA_GENHUB_H OKGEOMPONCAUNOMPONCA2OMPA_GENHUB OMPA_GENHUB_H OKGEOMPONCAUNOMPONCA1_3OMPA_GENHUB OMPA_GENHUB_H OKGEOMKINGFUNOMPA_KNGFISHEROMPA_GENHUB OMPA_GENHUB_H OKGEOMKAWUN2OMPA_GENHUB OMPA_GENHUB_H OKGEMCCLAIUNST1

OMPA_GENHUB OMPA_GENHUB_H OKGEMCCLAIUNGT2OMPA_GENHUB OMPA_GENHUB_H OKGEMCCLAIUNGT1OMPA_GENHUB OMPA_GENHUB_H OKGEFPL_WINDUNUN1_FPL_OMPAOMPA_GENHUB OMPA_GENHUB_H GRDASALINA1UN6OMPA_GENHUB OMPA_GENHUB_H GRDASALINA1UN5OMPA_GENHUB OMPA_GENHUB_H GRDASALINA1UN4OMPA_GENHUB OMPA_GENHUB_H GRDASALINA1UN3OMPA_GENHUB OMPA_GENHUB_H GRDASALINA1UN2OMPA_GENHUB OMPA_GENHUB_H GRDASALINA1UN1OMPA_GENHUB OMPA_GENHUB_H GRDAPENSA1UN6OMPA_GENHUB OMPA_GENHUB_H GRDAPENSA1UN5OMPA_GENHUB OMPA_GENHUB_H GRDAPENSA1UN4OMPA_GENHUB OMPA_GENHUB_H GRDAPENSA1UN3OMPA_GENHUB OMPA_GENHUB_H GRDAPENSA1UN2OMPA_GENHUB OMPA_GENHUB_H GRDAPENSA1UN1OMPA_GENHUB OMPA_GENHUB_H GRDAKERR_HYDUN4OMPA_GENHUB OMPA_GENHUB_H GRDAKERR_HYDUN3OMPA_GENHUB OMPA_GENHUB_H GRDAKERR_HYDUN2OMPA_GENHUB OMPA_GENHUB_H GRDAKERR_HYDUN1OMPA_GENHUB OMPA_GENHUB_H GRDAGRDA17UN2OMPA_GENHUB OMPA_GENHUB_H GRDAGRDA17UN1OMPA_GENHUB OMPA_GENHUB_H CSWSTURK_PPUNTURK_OMPAOMPA_GENHUB OMPA_GENHUB_H CSWSPIRKEYUNOMPA_PIRKEYOMPA_GENHUB OMPA_GENHUB_H CSWSOMPWHSK4UNOMPA_PAWHUSKAOMPA_GENHUB OMPA_GENHUB_H CSWSDOLET_PPUNOMPA_DOLETUCUHUB UCUHUB_H MPSTWA1UN2UCUHUB UCUHUB_H MPSTWA1UN1UCUHUB UCUHUB_H MPSSIBLEYUN3UCUHUB UCUHUB_H MPSSIBLEYUN2UCUHUB UCUHUB_H MPSSIBLEYUN1UCUHUB UCUHUB_H MPSSHARPER5UN3UCUHUB UCUHUB_H MPSSHARPER5UN2UCUHUB UCUHUB_H MPSSHARPER5UN1UCUHUB UCUHUB_H MPSRGREEN1UN3UCUHUB UCUHUB_H MPSPAR_JECMUN3UCUHUB UCUHUB_H MPSPAR_JECMUN2UCUHUB UCUHUB_H MPSPAR_JECMUN1UCUHUB UCUHUB_H MPSNEVADAUN1UCUHUB UCUHUB_H MPSLAKE_RDUN7UCUHUB UCUHUB_H MPSLAKE_RDUN6UCUHUB UCUHUB_H MPSLAKE_RDUN5UCUHUB UCUHUB_H MPSLAKE_RDUN4UCUHUB UCUHUB_H MPSLAKE_RDUN3UCUHUB UCUHUB_H MPSLAKE_RDUN2UCUHUB UCUHUB_H MPSLAKE_RDUN1UCUHUB UCUHUB_H MPSIATAN_SJUNIAT2_GMOCUCUHUB UCUHUB_H MPSIATAN_SJUN1

UCUHUB UCUHUB_H MPSGRNWD1UN4UCUHUB UCUHUB_H MPSGRNWD1UN3UCUHUB UCUHUB_H MPSGRNWD1UN2UCUHUB UCUHUB_H MPSGRNWD1UN1UCUHUB UCUHUB_H MPSGRAYWINDUNWINDFARMUCUHUB UCUHUB_H MPSCRSRD_EXUNCROSSROADS4UCUHUB UCUHUB_H MPSCRSRD_EXUNCROSSROADS3UCUHUB UCUHUB_H MPSCRSRD_EXUNCROSSROADS2UCUHUB UCUHUB_H MPSCRSRD_EXUNCROSSROADS1

Weighting Factor0.060.060.060.060.020.020.020.020.020.020.010.010.010.010.010.010.010.010.010.010.190.28

1111111111111111111111

0.0240.08

0.080.0240.0180.0020.0040.0280.0160.0160.0080.0360.0160.0160.002

0.010.0180.0060.0060.0020.0020.0120.002

0.030.03

0.0360.0360.0020.0020.0020.0220.0220.0220.0220.0520.052

0.050.0020.0160.0160.028

0.010.0020.0120.0160.016

0.030.0070.007

0.0080.008

0.003680.001760.001760.001760.001760.16525

0.02520.0003

00000000

0.036680.033660.033850.000180.000120.093990.099350.144210.146940.009730.177490.01974

5.00E-050.0004

0.000660.000730.00075

0.010.00640.07010.07010.07010.07010.06690.05730.10670.01270.04590.0614

0.06830.06140.00320.00150.00150.00150.00150.00150.00150.00060.00060.00060.00060.00060.00060.0011

0.0010.001

0.00110.04350.01760.06530.02550.01070.0398

00

0.31640.02730.02640.00470.00560.00460.00010.05940.06150.0569

00.00010.00010.00040.0672

000

0.17240.1361

0.00040.00060.00070.00050.00150.00260.00310.00260.0028

Settlement Location Aggregate Pnode Bus Level PnodeGSPR2015HUB CSWS.ONETAGSPR2015HUB SPSBLACKHAWUN1_RAGSPR2015HUB SPSBLACKHAWUN2_RAGSPR2015HUB SPSCAPROCKUNWINDFARM_RAGSPR2015HUB SPSCARLSBADUN5_RAGSPR2015HUB SPSLP-HOLL2UNCOOKE_ST1_RAGSPR2015HUB SPSLP-HOLL2UNCOOKE_ST2_RAGSPR2015HUB SPSLP-HOLL2UNCOOKE_GT2_RAGSPR2015HUB SPSLP-HOLL2UNCOOKE_GT3_RAGSPR2015HUB SPSCUNNSUBUN1_RAGSPR2015HUB SPSCUNNSUBUN2_RAGSPR2015HUB SPSCUNNSUBUN3_RAGSPR2015HUB SPSCUNNSUBUN4_RAGSPR2015HUB SPSINDUSTR2UNENGCARBON1_RAGSPR2015HUB SPSHARRSUBUN1_RAGSPR2015HUB SPSHARRSUBUN2_RAGSPR2015HUB SPSHARRSUBUN3_RAGSPR2015HUB SPSHOBBSPLT1GSPR2015HUB SPSHOBBSPLT2GSPR2015HUB SPSJONESSUBUN1_RAGSPR2015HUB SPSJONESSUBUN2_RAGSPR2015HUB SPSJONESSUBUN3_RAGSPR2015HUB SPSJONESSUBUN4_RAGSPR2015HUB SPSLLANOUNWNDFRM_RAGSPR2015HUB SPSMADDOXSUUN1_RAGSPR2015HUB SPSMADDOXSUUN2_RAGSPR2015HUB SPSNICHSUBUN1_RAGSPR2015HUB SPSNICHSUBUN2_RAGSPR2015HUB SPSNICHSUBUN3_RAGSPR2015HUB SPSPLXSUBUN1_RAGSPR2015HUB SPSPLXSUBUN2_RAGSPR2015HUB SPSPLXSUBUN3_RAGSPR2015HUB SPSPLXSUBUN4_RAGSPR2015HUB SPS.PSCOGENGSPR2015HUB SPSQUAYCNTYUNQUAYCOUNTY1_RAGSPR2015HUB SPSSAN_JUANUNWINDFARM_RAGSPR2015HUB SPSSPINSPURUNSPINSPUR_WIND_RAGSPR2015HUB SPSTOLKSUBUN1_RAGSPR2015HUB SPSTOLKSUBUN2_RAGSPR2015HUB SPSWILDORADUNWINDFARM_RA

Weighting Factor17

5531221139551

15161613131111

9935355

1124489157

2424

7

PRR Recommendation Report

MPRR No. 221 PRR

Title Transitional ARR Allocation Process

Timeline Normal Expedited Urgent Action

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

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Ranking TBD

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

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: 5; 5.3; 5.3.2.1(new); 5.3.3 Title: Transmission Congestion Rights Markets Process; Annual ARR Allocation Process; Transitional ARR Allocation (new); Simultaneous Feasibility. Protocol Version: 21a

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description

The Transitional ARR Allocation is designed to allocate ARRs to Transmission Owners that are new to the Integrated Marketplace. The Transitional ARR Allocation can only be requested by these Transmission Owners that are bringing their transmission facilities under the Tariff. Other non-transmission owning entities that have existing firm transmission service across the same new transmission facilities will not be excluded from participating, provided that these new entities plan to join in conjunction with the transmission owning entity. There is currently no mechanism to allow a new Transmission Owner an opportunity to participate in an ARR Allocation prior to the Monthly ARR Allocation if they are unable to participate in the Annual ARR Allocation. This new Protocol and Tariff section outlines a new transitional ARR Allocation that will give Transmission Owners in this situation an opportunity to receive ARRs prior to the Monthly ARR Allocation.

Tariff Implications or Changes

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

Attachment AE: 7.11 Transitional ARR Allocation (new)

No

Criteria Impact or Changes

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

No

Working Group Voting Record

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 1 of 11

MWG

Date of Vote: 11/19/2014 Vote: Unanimously Approved

Opposed: N/A

Abstained: N/A

Date of Vote: 12/16/2014 Vote: Unanimously Approved SPP Comments

Opposed: N/A

Abstained: N/A

RTWG Date of Vote: Vote:

ORWG Date of Vote: Vote:

MOPC Date of Vote: Vote:

Board/Members Committee Date of Vote: Vote:

Date 10/31/2014

Sponsor Name Charles Cates E-mail Address ccates@spp.org Company Southwest Power Pool Phone Number 501.614.3351

Comments Received Comment Author Micha Bailey on behalf of MWG Date 11/19/2014

Comment Description MWG took out the word “normal” in front of annual allocation. MWG believe by adding the word “normal’ in front of annual allocation might confuse one when reading these sections. MWG added the definition of Transitional ARR Allocation Process to the Tariff. MWG made other clarifying language changes.

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

Comments Received

Comment Author Nick Parker Date 12/3/2014

Comment Description SPP added language to clarify what base flow inputs to the Transitional ARR Allocation Process is used.

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

Proposed Protocol Language Revision

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 2 of 11

1. Glossary

Transitional ARR Allocation Process

As defined in Attachment AE of the Tariff.

5. Transmission Congestion Rights Markets Process

The annual TCR Markets Process includes an annual LTCR allocation process, an annual and

monthly ARR allocation process and annual and monthly TCR Auctions.

LTCRs are multi-year instruments, ARRs are annual, monthly or seasonal instruments, and

TCRs are monthly and seasonal financial instruments whose values are determined as part of the

DA Market settlement based on the MW amount of the TCR (including LTCRs converted to

TCRs) and the DA Market differential of the Marginal Congestion Component of LMP between

specified sinks and sources. TCRs are of the obligation type which means they can result in a

credit or a charge. They provide a financial hedge against congestion costs in the DA Market as

long as the MCC of the TCR sink Settlement Location is greater than the MCC of the TCR

source Settlement Location. If the MCC at the TCR sink Settlement Location is less than the

MCC of the TCR source Settlement Location, the TCR holder is charged (this type of TCR is

commonly referred to as a “Counter-Flow TCR”). Awarded LTCRs are directly converted into

TCRs prior to the annual ARR allocation for the current allocation year.

Auction Revenue Rights (ARRs) are obtained by Eligible Entities during the annual ARR

allocation process, Transitional ARR Allocation Process and/or monthly ARR allocation process.

Holders of ARRs are entitled to receive the Annual and Monthly TCR Auction revenues

associated with awarded TCR Bids. However, ARRs are of the obligation type which means

they can result in the holder receiving a portion of the TCR auction revenues or contributing to

the TCR auction revenues.

TCRs are obtained by Market Participants through the annual LTCR allocation and the Annual

and Monthly TCR Auctions. Optionally, ARR holders may convert their ARRs into TCRs in the

Annual and Monthly TCR Auctions and either hold the TCRs or offer these TCRs for sale in the

auctions.

The TCR Markets Process is subject to review by the Market Monitor, consistent with

Attachment AG of the SPP OATT.

There are 8 key steps associated with obtaining an LTCR or TCR and/or offering an awarded

LTCR or TCR for sale.

(1) Annual LTCR/ARR Verification Process;

Comment [MPRR138.1]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.2]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.3]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.4]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR171.5]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [MPRR171.6]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.7]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR171.8]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.9]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR171.10]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.11]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.12]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.13]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.14]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 3 of 11

(2) Annual LTCR Allocation Process;

(3) Annual ARR Allocation Process;

(4) Annual TCR Auction Process;

(5) Monthly ARR Allocation Process;

(6) Monthly TCR Auction Process;

(7) ARR Allocation and TCR Auction Settlements; and

(8) TCR Secondary Markets.

Exhibit 5-1 provides an overall representative timeline related to the LTCR Allocation, ARR

Allocation and TCR Auction processes and Exhibit 5-2 provides additional details related to

auction timing and available transmission system capability of the TCR Auction processes.

Exhibit 5-1: LTCR/ARR Allocation and TCR Auction Processes Timeline

Comment [MPRR138.15]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.16]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.17]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.18]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 4 of 11

Exhibit 5-2: TCR Auction Processes Summary

1 October and November 2 December, January, February, March 3 April and May

Auction

Month

Auction

Type

TCR Award Periods TCR

Products

Auction

Rounds

Total

Auctions

May Annual

(System Capability %)

Jun

(100)

Jul

(90)

Aug

(90)

Sep

(90)

Fall1

(60)

Winter2

(60)

Spring3

(60)

On-Peak/

Off-Peak

1

14

Jun Monthly

(System Capability %)

Jul

(100)

On-Peak/

Off-Peak

1 2

Jul Monthly

(System Capability %)

Aug

(100)

On-Peak/

Off-Peak

1 2

Aug Monthly

(System Capability %)

Sep

(100)

On-Peak/

Off-Peak

1 2

Sep Monthly

(System Capability %)

Oct

(100)

On-Peak/

Off-Peak

2 4

Oct Monthly

(System Capability %)

Nov

(100)

On-Peak/

Off-Peak

2 4

Nov Monthly

(System Capability %)

Dec

(100)

On-Peak/

Off-Peak

2 4

Dec Monthly

(System Capability %)

Jan

(100)

On-Peak/

Off-Peak

2 4

Jan Monthly Feb On-Peak/ 2 4

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 5 of 11

(System Capability %) (100) Off-Peak

Feb Monthly

(System Capability %)

Mar

(100)

On-Peak/

Off-Peak

2 4

Mar Monthly

(System Capability %)

Apr

(100)

On-Peak/

Off-Peak

2 4

Apr Monthly

(System Capability %)

May

(100)

On-Peak/

Off-Peak

2 4

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 6 of 11

Key process and design assumptions of each of these eight (8) key steps are described in the following

sub-sections.

5.3 Annual ARR Allocation Process

The Annual ARR Allocation Process addresses how candidate ARRs verified in the Annual LTCR/ARR

Verification Process may be nominated and converted to ARRs. Eligible Entities may nominate the

candidate ARRs that they wish to receive up to their Nomination Caps less any LTCRs awarded plus

any LTCRs surrendered. Any candidate LTCRs not awarded in the Annual LTCR Allocation Process

and surrendered LTCRs become candidate ARRs.

(1) The annual allocation process determines the portion of the nominated candidate ARRs that are

simultaneously feasible to allocate to each Eligible Entity. 100% of the SPP Residual

Transmission System Capability, as defined under Section 5.2.2(2), is made available during the

Annual ARR Allocation Process. Candidate ARRs are nominated on a monthly (June, July,

August and September) and seasonal basis (Fall, Winter and Spring) in a three-round process.

No later than five (5) Business Days prior to the start of the Annual ARR Allocation Process,

SPP will post the transmission system network topology data for each of the monthly and

seasonal on-peak and off-peak models, along with corresponding Parallel Flow, prohibited

collocated and electrically equivalent Settlement Location pairs, and transmission line outage

assumptions, that SPP will use in the upcoming allocation process for use by Eligible Entities in

developing their candidate ARR nomination strategies. Exhibit 5-3 provides a representative

timeline of the three-round annual ARR allocation process.

(2) In addition to the Annual ARR Allocation Process, a Transmission Owner may request that a

Transitional ARR Allocation Process be conducted to the extent that the Transmission Owner is

incorporating existing transmission facilities into the SPP Transmission System under the Tariff

and the timing of such incorporation does not allow participation in the Annual ARR Allocation

Process.

(a) Only Eligible Entities with firm transmission service associated with such transmission

facilities as verified by SPP using the process described under Section 5.1.1 will be

eligible for candidate ARRs.

(b) SPP will only conduct a Transitional ARR Allocation Process if the requested ARR

allocations include at least the Winter and Spring periods. Additional periods requested

must align with the existing Annual ARR periods. Otherwise, impacted Eligible Entities

must obtain ARRs in the Monthly ARR Allocation Process.

Comment [MPRR138.19]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.20]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.21]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 7 of 11

Exhibit 5-3: Annual ARR Allocation Process Timeline

12/15 5/31

1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5

6/1 - 9/30Annual ARR Awards

by MonthOn-Peak and Off-Peak

12/15 - 5/31ARR Allocation

10/1 - 5/31Annual ARR Awards

by SeasonOn-Peak and Off-Peak

4/5 4/23

4/5 - 4/23Annual ARR

Allocation

4/5 - 4/23Three Round ARR Allocation Process

4/5 - 4/6Eligible Entities Submit Round 1

Nominations

4/7 - 4/10

SPP Performs Round 1 ARR

Allocation

4/11 - 4/12Eligible Entities Submit Round 2

Nominations

4/13 - 4/16

SPP Performs Round 2 ARR

Allocation

4/17 - 4/18Eligible Entities Submit Round 3

Nominations

4/19 - 4/22

SPP Performs Round 3 ARR

Allocation

4/10

SPP PostsRound 1Results

4/16

SPP PostsRound 2Results

4/22

SPP PostsRound 3Results

The following rules apply to the annual allocation of ARRs.

5.3.2 ARR Allocation

ARRs are allocated in a three-round process as follows:

…

5.3.2.1 Transitional ARR Allocation

ARRs associated with Eligible Entities with verified firm transmission service as described under

Section 5.3(2) are allocated in a single round process. Eligible Entities may nominate:

(a) ARRs from their NITS Candidate ARRs that total to no more than 100% of their NITS ARR

Nomination Cap;

(b) ARRs from their GFA NITS Candidate ARRs that total to no more than 100% of their GFA

NITS ARR Nomination Cap;

(c) ARRs from their FPTP Candidate ARRs that total to no more than 100% of their FPTP ARR

Nomination Cap; and

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 8 of 11

(d) ARRs from their GFA FPTP Candidate ARRs that total to no more than 100% of their GFA

FPTP ARR Nomination Cap.

5.3.3 Simultaneous Feasibility

A simultaneous feasibility test (SFT) is performed in each round to ensure that the nominated candidate

ARRs, with nominated candidate ARR MW modeled as generation injection at the source and a

corresponding load withdrawal at the sink, do not violate any normal transmission line thermal ratings

under normal system conditions and do not violate short-term Emergency transmission line thermal

ratings following a single contingency (N-1 contingency analysis). The SFT is performed consistent

with the transmission system loading analysis that is performed as part the Security Constrained

Economic Dispatch process in the DA Market and includes consideration of the impact of Parallel Flow.

100% of the SPP Residual Transmission System Capability, as defined under Section 5.2.2(2), is made

available during the analysis.

(1) The SPP Transmission System topology used in the SFT is the most up-to-date Network Model

for all allocation periods, updated for planned maintenance outages.

(a) For withdrawals at Settlement Locations containing more than one PNode, SPP will

distribute the Settlement Location withdrawal down to the PNode level using load

distribution percentages from the peak hour of the corresponding most recent historical

period (i.e. June, July, August, September, Fall, Winter and Spring). These load

distribution percentages are calculated using the methodology described under Section

4.1.2.1.6.

(b) For injections at Market Hubs, SPP will distribute the hub injection down to the PNode

level on a pro-rata basis using the weighting factors defined when the hub is created.

(c) For GFA Carve Outs that will be nominated, an injection at the source and a

corresponding withdrawal at the sink will be included in the Annual ARR Allocation

Process and will be subject to SFT. The capacity used in the allocation will be the

maximum allowable nomination as defined in section 5.3.2.

(2) All previously awarded TCRs associated with LTCRs that have not been surrendered are

modeled as fixed injections/withdrawals. To the extent that these fixed injections and

withdrawals are not feasible, SPP will increase the ratings of the applicable transmission lines to

ensure feasibility. SPP will report back to the MWG when and which transmission line ratings

had to be adjusted, and the magnitude of each adjustment, to ensure feasibility.

(3) Additionally, if the SFT is associated with a transitional ARR allocation as described under

Section 5.3.2.1, all TCRs previously awarded in the Annual TCR Auction Process and all

remaining ARRs not accounted for in the Annual TCR Auction Process for the applicable study

period are modeled as fixed injections at the specified sources and fixed withdrawals at the

specified sinks. To the extent that these fixed injections and withdrawals are not feasible, SPP

Comment [MPRR138.22]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.23]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.24]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR171.25]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [MPRR171.26]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.27]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 9 of 11

will increase the ratings of the applicable transmission lines to ensure feasibility prior to

assessing transitional ARR feasibility.

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.

Proposed Tariff Language Revision

ATTACHMENT AE

INTEGRATED MARKETPLACE

Transitional ARR Allocation Process

An interim, multi-period, single-round process, outside of the normal Annual process schedule, used by an Eligible Entity when a Transmission Owner brings existing transmission facilities and transmission service under the SPP Tariff.

7.11 Transitional ARR Allocation

A Transmission Owner joining the Integrated Marketplace as a new Market Participant

may request the Transmission Provider perform a transitional ARR allocation to the extent that

the Transmission Owner is incorporating existing transmission facilities into the SPP

Transmission System under the Tariff and the timing of such incorporation does not allow

participation in the Annual ARR Allocation Process described under Section 7.2 of this

Attachment AE. Eligible Entities with firm transmission service on that Transmission Owner’s

facilities may participate in the allocation. The Transmission Provider shall conduct the

transitional ARR allocation consistent with the processes described under Section 7.1 and

Section 7.2 of this Attachment AE, provided that:

(1) The transitional ARR allocation shall be performed in a single round;

(2) At a minimum, the transitional ARR allocation must include the Winter and Spring

season and align with the other Annual ARR periods; and

(3) All TCRs previously awarded in the annual TCR auction and all remaining ARRs not

accounted for in the annual TCR auction (as defined in Section 7.6 of this Attachment

AE) for the applicable study period are modeled as fixed injections at the specified

sources and fixed withdrawals at the specified sinks. To the extent that these fixed

injections and withdrawals are no longer feasible, the Transmission Provider will make

the minimum adjustments necessary to the ratings of the applicable transmission facilities

in the model in order to allow the model to produce a feasible solution solely for the

purpose of assessing transitional ARR feasibility.

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 10 of 11

Proposed Criteria Language Revision N/A

Attachment 11 - MPRR 221 Recommendation Report.docx 12/18/2014 Page 11 of 11

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 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 1 of 55

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

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

No

Working Group Voting Record

MWG

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

Opposed: N/A

Abstained: WR

Date of Vote: 12/16/2014 Vote: Unanimously Approved

RTWG Date of Vote: 10/29/2014 Vote: Approved with no Tariff Impact

ORWG Date of Vote: 11/6/2014 Vote: Approved with no Reliability Impact

MOPC Date of Vote: Vote:

Board/Members Committee Date of Vote: Vote:

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 2 of 55

Date 10/14/2014

Sponsor Name Micha Bailey E-mail Address mcbailey@spp.org 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.

Comments Received

Comment Author Matt Harward Date 12/3/2014

Comment Description Upon further review of the Tariff, Regulatory and Legal propose the following Tariff changes to coincide with the approved protocol changes. These changes (which start on page 42) specify which offer will be used to calculate the MWP costs.

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

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

Comment [MPRR102.2]: MPRR102 Awaiting implementation. #ER13-1748

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 3 of 55

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.

(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:

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(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;

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"

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 5 of 55

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

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

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"

Comment [MPRR102.3]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.4]: MPRR102 Awaiting implementation. #ER13-1748

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 6 of 55

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:

(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"

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 7 of 55

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 8 of 55

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.

Comment [MPRR102.5]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.6]: MPRR102 Awaiting implementation. #ER13-1748

Formatted: Font: Italic

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4.5.8.6 Day-Ahead Spinning Reserve Amount

The above variables are defined as follows:

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.

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 10 of 55

4.5.8.7 Day-Ahead Supplemental Reserve Amount

The above variables are defined as follows:

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.

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4.5.8.8 Day-Ahead Regulation-Up Service Distribution Amount

The above variables are defined as follows:

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

The above variables are defined as follows:

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.

Comment [MPRR102.7]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.8]: MPRR102 Awaiting implementation. #ER13-1748

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4.5.8.11 Day-Ahead Supplemental Reserve Distribution Amount

The above variables are defined as follows:

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.

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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.

Formatted: Numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0" + Tab after: 0.25" + Indent at: 0.25", Tab stops: Not at 0.5"

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"

Formatted: Indent: Left: 0", Numbered +Level: 1 + Numbering Style: 1, 2, 3, … + Startat: 3 + Alignment: Left + Aligned at: 0.75" +Tab after: 1" + Indent at: 1", Tab stops: 0.25", List tab + Not at 0.5"

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"

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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

Formatted: Outline numbered + Level: 3 +Numbering Style: i, ii, iii, … + Start at: 1 +Alignment: Right + Aligned at: 1.13" + Indentat: 1.5", Tab stops: Not at 1.5"

Formatted: Outline numbered + Level: 4 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 1.63" + Indentat: 2", Tab stops: Not at 2"

Formatted: Outline numbered + Level: 3 +Numbering Style: i, ii, iii, … + Start at: 1 +Alignment: Right + Aligned at: 1.13" + Indentat: 1.5", Tab stops: Not at 1.5"

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"

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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

Formatted: Indent: Left: 0", Numbered +Level: 1 + Numbering Style: 1, 2, 3, … + Startat: 3 + Alignment: Left + Aligned at: 0.75" +Tab after: 1" + Indent at: 1", Tab stops: 0.25", List tab + Not at 0.5"

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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:

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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

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The above variables are defined as follows:

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.

Comment [MPRR102.9]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.10]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.11]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.12]: MPRR102 Awaiting implementation. #ER13-1748

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Variable Unit Settlement Interval

Definition

DaRegUpCapOffer a, h, s

$/MW Dispatch Interval

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) .

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Variable Unit Settlement Interval

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.

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Variable Unit Settlement Interval

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.

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4.5.9.4 Real-Time Regulation-Up Service Amount

The above variables are defined as follows:

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

Comment [MPRR102.13]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.14]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.15]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.16]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.17]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.18]: MPRR102 Awaiting implementation. #ER13-1748

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4.5.9.6 Real-Time Spinning Reserve Amount

The above variables are defined as follows:

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

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4.5.9.7 Real-Time Supplemental Reserve Amount

The above variables are defined as follows:

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

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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.

2 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.

Formatted: Numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0" + Tab after: 0.25" + Indent at: 0.25", Tab stops: Not at 0.5"

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"

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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

Real-Time Make-Whole Payment Eligibility Period

Formatted: Numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0" + Tab after: 0.25" + Indent at: 0.25", Tab stops: Not at 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"

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 27 of 55

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"

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 28 of 55

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

Formatted: Numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0" + Tab after: 0.25" + Indent at: 0.25", Tab stops: Not at 0.5"

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 29 of 55

+ 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

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 30 of 55

RtEffMin5minQty a, s, i = Min (

RtComMinEconCapOL5minQtya, s, i ,

RtDispMinEconCapOL5minQtya, s, i ,

Max (0, (-1) * RtBillMtr5minQtya, 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

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 31 of 55

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] )

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 32 of 55

* 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

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 33 of 55

- 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

DaRegUpHrlyQty a, z, s, h] )

* RtRegUpMcp5minPrc z, i ) / 12

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

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

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

DaRegDnHrlyQty a, z, s, h] )

* RtRegDnMcp5minPrc z, i ) / 12

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

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

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 34 of 55

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

DaSpinHrlyQty a, z, s, h ] )

* RtSpinMcp5minPrc z, i ) / 12

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

(-1) * RtRucComStat5minFlg 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

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 35 of 55

#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

CurveOffer Energy Dispatched As RTBM

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:

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 36 of 55

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

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

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

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 37 of 55

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

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

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

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

Formatted: Numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0" + Tab after: 0.25" + Indent at: 0.25", Tab stops: Not at 0.5"

Formatted: Numbered + Level: 1 +Numbering Style: 1, 2, 3, … + Start at: 1 +Alignment: Left + Aligned at: 0" + Tab after: 0.25" + Indent at: 0.25", Tab stops: Not at 0.5"

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 38 of 55

(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

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 39 of 55

The above variables are defined as follows:

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)

$/MW Dispatch Interval

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)

$/MW Dispatch Interval

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.

Comment [MPRR102.19]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.20]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.21]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.22]: MPRR102 Awaiting implementation. #ER13-1748

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 40 of 55

Variable

Unit

Settlement Interval

Definition

RtSpinOffer a, s, i, c

(Not Available on Settlement Statement)

$/MW Dispatch Interval

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)

$/MW Dispatch Interval

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).

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 41 of 55

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.

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 42 of 55

4.5.9.9 Real-Time Out-Of-Merit Amount

The above variables are defined as follows:

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.

RtRegUp5minQty a, z, s, i MW Dispatch Interval

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

4.5.9.10 RUC Make-Whole-Payment Distribution Amount

The above variables are defined as follows:

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.

Comment [MPRR102.23]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.24]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.25]: MPRR102 Awaiting implementation. #ER13-1748

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 43 of 55

4.5.9.15 Real-Time Regulation Non-Performance Amount

The above variables are defined as follows:

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 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.

Comment [MPRR102.26]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.27]: MPRR102 Awaiting implementation. #ER13-1748

Attachment 12 - MPRR 215 Recommendation Report.docx 12/18/2014 Page 44 of 55

Proposed Tariff Language Revision

Attachment AE

5.1.3 Day-Ahead Market Results

No later than 1600 hours Day-Ahead, the Transmission Provider will notify each Market

Participant of the Day-Ahead Market results for each hour of the Operating Day.

The following results are communicated to each Market Participant for only its specific

Resources:

(1) Cleared Resource Offers for Energy, Regulation-Up Service , Regulation-Down Service ,

Spinning Reserve or Supplemental Reserve;

(a) Cleared Offers for Energy associated with Resource Offers represent a physical

Resource commitment.

(b) Resources committed by the Transmission Provider in the Day-Ahead Market that

incur one or more start-up costs within the Operating Day as a result of the

Transmission Provider Day-Ahead Market commitment are guaranteed to receive

revenues that are at least equal to the Resource Offer costs for the cleared amount

of Energy, Regulation-Up Service, Regulation-Down Service, Spinning Reserve

or Supplemental Reserve for that Resource.

(c) Cleared Regulation-Up Service MWs represent only those MWs cleared to meet

the Regulation-Up Service requirement.

(d) Cleared Regulation-Down Service MWs represent only those MWs cleared to

meet the Regulation-Down Service requirement.

(e) Cleared Spinning Reserve MWs represent the Spinning Reserve MWs cleared to

meet the Spinning Reserve requirement and Regulation-Up Service MWs cleared

to meet the Spinning Reserve requirement through product substitution as

described under Section 5.1.2(2)(c) of this Attachment AE.

(f) Cleared Supplemental Reserve MWs represent the sum of Supplemental Reserve

MWs cleared to meet the Supplemental Reserve requirement and Regulation-Up

Service MWs and Spinning Reserve MWs cleared to meet the Supplemental

Reserve requirement through product substitution as described under Section

5.1.2(2)(c) of this Attachment AE.

(2) Cleared Virtual Energy Offers;

(3) Cleared Import Interchange Transaction Offers;

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(4) Cleared Demand Bids;

(5) Cleared Virtual Energy Bids;

(6) Cleared Export Interchange Transaction Bids; and

(7) Cleared Through Interchange Transactions.

The following results are communicated to all Market Participants:

(1) LMPs for each Settlement Location, the marginal Energy component (“MEC”) of the

LMP, the Marginal Congestion Component (“MCC”) of the LMP and the Marginal Loss

Component (“MLC”) of the LMP for each Settlement Location; and

(2) MCPs for Regulation-Up Service, Regulation-Down Service, Spinning Reserve and

Supplemental Reserve for each Reserve Zone.

6.2.3 Real-Time Balancing Market Results

Following execution of the RTBM SCED, the Transmission Provider shall communicate

the results to Market Participants prior to the start of the applicable Dispatch Interval.

(1) The following results are communicated to each Market Participant for only its specific

Resources:

(a) Resource Dispatch Instructions. The Dispatch Instruction is a MW output target

for the end of the applicable Dispatch Interval.

(b) Cleared Regulation-Up Service , Regulation-Down Service, Spinning Reserve and

Supplemental Reserve MW by Resource.

(i) Cleared Regulation-Up Service MWs represent only those MWs cleared to

meet the Regulation-Up Service requirement.

(ii) Cleared Regulation-Down Service MWs represent only those MWs

cleared to meet the Regulation-Down Service requirement.

(iii) Cleared Spinning Reserve MWs represent the Spinning Reserve MWs

cleared to meet the Spinning Reserve requirement and Regulation-Up

Service MWs cleared to meet the Spinning Reserve requirement through

product substitution as described under Section 5.1.2(2)(c) of this

Attachment AE.

(iv) Cleared Supplemental Reserve MWs represent the sum of Supplemental

Reserve MWs cleared to meet the Supplemental Reserve requirement and

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Regulation-Up Service MWs and Spinning Reserve MWs cleared to meet

the Supplemental Reserve requirement through product substitution as

described under Section 5.1.2(2)(c) of this Attachment AE.

(2) The following results are communicated to all Market Participants and are used for

settlement purposes;

(a) LMPs for each Settlement Location, the MCC of LMP for each Settlement

Location and the MLC of LMP for each Settlement Location.

(b) MCPs for Regulation-Up Service, Expected Regulation-Up Mileage Regulation-

Down Service, Expected Regulation-Down Mileage, Spinning Reserve and

Supplemental Reserve for each Reserve Zone.

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

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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.

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(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 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 and Regulation-Up Offers to the extent

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that Regulation-Up Service was cleared to meet the Spinning Reserve

requirement,

(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, Regulation-Up Offers to the

extent that Regulation-Up Service was cleared to meet the Supplemental

Reserve requirement and Spinning Reserve Offers to the extent that

Spinning Reserve was cleared to meet the Supplemental Reserve

requirement,

(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

eligible Resource is equal to the sum for all hours in the Day-Ahead Market Make

Whole Payment Eligibility Period of:

(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,

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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. 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.

(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

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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

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 Day-Ahead Market in

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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 the sum for all Dispatch Intervals in the RUC Make Whole

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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, including the impact from product

substitution as described under Section 5.1.2(2)(c) of this Attachment AE, 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.

(b) An Asset Owner’s RUC Make Whole Payment Revenue Amount for each eligible

Resource is equal 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).

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(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.

Proposed Criteria Language Revision

N/A

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PRR Recommendation Report

MPRR No. 219 PRR

Title TCR Shortpay Calculation Correction

Timeline Normal Expedited Urgent Action

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

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Rating-Ranking Rating – Ranking Rating: 1 – FERC Compliance 2 – Defect

– 3 – Member Request 4 – Other

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

SPP Staff will complete this section. Member Software Impact Yes No

Protocol Section(s) Requiring Revision

Section No.: 4.5.8.15 Title: Transmission Congestion Rights Daily Uplift Amount Protocol Version: 21.a

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description

This change is necessary to correct the calculation of a short pay for TCR holders. The current calculation charges a position in both directions rather than netting counter-flows. The flaw in this calculation is most easily seen in an example of system impact of a portfolio:

Suppose Entity Big Rock owns a 10 MW position AB with a shift factor of 0.3 on constraint Z, and another 10 MW path CD with a shift factor of 0.1 on constraint Z, the net impact of the portfolio on constraint Z is 4 MW (which is calculated by taking the shift factor multiplied by the MW and summing over the positions 0.3*10 + 0.1*10).

Suppose Entity Small Town owns 20 MW path EF with a shift factor of 0.3 on constraint Z. This positions creates a 6 MW impact on constraint Z. Suppose further that Small Town also owns a 20 MW position GH with a -0.1 shift factor on constraint Z (with impact of -2MW) their net impact on constraint Z is also 4 MW.

Both portfolios have the same 4 MW impact on constraint Z. However, because of the ABS value format of the existing short pay allocation Entity Big Rock would be assessed a short pay on the basis of 4 MW of flow on constraint Z and entity Small Town (with the same net impact of 4 MW on the constrained element as Big Rock) would be assessed a short pay on 8 MW of flow (6 + ABS(-2)).

Thus both portfolios have the same impact on the constraint, yet Entity Small Town would pay twice the short pay costs as Entity Big Rock.

This example illustrates the problem for one constraint and small number of TCR paths but it can be generalized to many constraints and many paths where on

Attachment 13 - MPRR 219 Recommendation Report.docx 12/19/2014 Page 1 of 7

each path it is the sum of the net flows on the line that should determine the TCR underfunding allocation. Net flows across many paths is completely analogous to determining the allocation based on net revenue. The proposed changes to the equations in this MPRR would net portfolios (properly accounting for counter flows) and assess short pay on a net revenue position. This will ensure that counter flows to not also get assessed short pay. Similarly, in the refund of overages counter flows will not receive pay backs for overages. Charging on the absolute value (as the current equations do) will degrade liquidity in the market significantly. If the market believes there is a 10% underfunding risk, then all bids to buy congestion will factor in that 10% risk relative to their perception of fair value (thus reducing (discounting) their offer by 10%). If the absolute values are used then offers to provide additional transfer capability (via counter flow) will also have to factor in a 10% surcharge to their offers. That means that on every path there would be a 90% fair value bid vs. a 110% fair value offer. Without the absolute value portion of the formula, bids will still be 90% and offers at 100% but that is still much better for liquidity than the alternative (existing spread of twice that) caused by the existing incentive structure. Such reduced bids and offers will degrade auctions revenues (and thus auction pay out values) over time. Removes absolute value from equations to properly account for offsetting portfolio positions in short pay calculations.

Tariff Implications or Changes

Yes – Section No.: (Include a summary of impact and/or specific changes) Attachment AE; Section 8.5.12 Transmission Congestion Rights Daily Uplift Amount

No

Criteria Impact or Changes

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

No

MWG Review PRR Recommendation

Date of Vote: 12/16/2014 Vote: Unanimously Rejected

Opposed:

Abstained:

RTWG Review Date of Vote: Vote:

ORWG Review Date of Vote: Vote:

MOPC Recommendation Date of Vote: Vote:

Board Review Date of Vote: Vote:

Date 10/31/2014

Sponsor Name Marguerite Wagner E-mail Address marguerite.wagner@betm.com Company Boston Energy Trading & Marketing Phone Number 617.529.3127

Attachment 13 - MPRR 219 Recommendation Report.docx 12/19/2014 Page 2 of 7

Proposed Protocol Language Revision

4.5.8.15 Transmission Congestion Rights Daily Uplift Amount

(1) A DA Market charge or credit1 will be calculated for each Asset Owner holding TCRs for

each Operating Day to the extent that congestion revenues collected over the Operating Day

are not sufficient to fund the net of the total charges and credits calculated under Section

4.5.8.14 over the Operating Day. The amount is calculated as follows:

#TcrUpliftDlyAmt a, d =

ShortFallDlyAmt d * [TcrUpliftRatioAoDlyAmt a, d / TcrUpliftRatioSppDlyAmt d]

Where,

(a) #TcrUpliftRatioAoDlyAmt a, d =

(-1) * (Min ( 0, ∑h∑

t ABS (TcrHrlyQty a, h, t * (DaMccHrlyPrc source, h -

DaMccHrlyPrc sink, h ) ) ) )

(b) #TcrUpliftRatioSppDlyAmt d =

(-1) * (Min ( 0, ∑a

∑h∑

tABS (TcrHrlyQty a, h, t * (DaMccHrlyPrc source, h -

DaMccHrlyPrc sink, h ) ) ) )

If TcrUpliftRatioSppDlyAmt d = 0

THEN

TcrUpliftRatioSppDlyAmt d = 1

(c) #ShortFallDlyAmt d =

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

Attachment 13 - MPRR 219 Recommendation Report.docx 12/19/2014 Page 3 of 7

(-1) * MIN { 0, ∑a∑

s∑

h[ DaMccHrlyPrc s, h * (DaClrdHrlyQty a, s, h

+ ∑i∑

t( DaImpExp5minQty a, s, i, t / 12 ) + ∑

tDaClrdVHrlyQty a, s, h, t ) ]

+ ∑a

∑h

TcrFundHrlyAmt a, h }

(2) 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:

TcrUpliftDlyMpAmt m, d = ∑a

TcrUpliftDlyAmt a, d

Attachment 13 - MPRR 219 Recommendation Report.docx 12/19/2014 Page 4 of 7

The above variables are defined as follows:

Variable

Unit

Settlement Interval

Definition

TcrUpliftDlyAmt a, d $ Operating Day

Transmission Congestion Rights Daily Uplift Amount per AO - AO a’s share of the ShortFallDlyAmt d in Operating Day d.

TcrUpliftRatioAoDlyAmt a, d $ Operating Day

Transmission Congestion Rights Uplift Ratio per Asset Owner per Operating Day – The total of the absolute value of Asset Owner a’s hourly TCR

instrument economic value for Operating Day d.

TcrUpliftRatioSppDlyAmt d $ Operating Day

SPP Transmission Congestion Rights Uplift Ratio per Operating Day – The total of TcrUpliftRatioAoDlyAmt a, d for Operating Day d.

ShortFallDlyAmt d $ Operating Day

Transmission Congestion Rights Daily Shortfall Amount – The shortfall in congestion revenues that would be required to fully fund TCRs in Operating Day d.

DaMccHrlyPrc s, h $/MWh Hour Day-Ahead Marginal Congestion Component of Day-Ahead LMP – The Marginal Congestion Component of the Day-Ahead LMP at Settlement Location s 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.

DaClrdVHrlyQty a, s, h, t MWh Hour Day-Ahead Cleared Virtual Energy Quantity per AO per Settlement Location per Hour in the DA Market – The value described under Section 4.5.8.3.

DaImpExp5minQty a, s, i, t MW Dispatch Interval

Day-Ahead Interchange Transaction Quantity per AO per Settlement Location per Dispatch Interval – The value described under Section 4.5.9.2.

TcrHrlyQty a, h, t MWh Hour Transmission Congestion Right Quantity - The value described under Section 4.5.8.14.

TcrFundHrlyAmt a, h $ Hour Transmission Congestion Rights Hourly Funding Amount per AO per Hour - The value calculated under Section 4.5.8.14.

TcrUpliftDlyMpAmt m, d $ Operating Day

Transmission Congestion Rights Daily Uplift Amount per MP per Operating Day - MP m’s share of the ShortFallDlyAmt d in Operating Day d.

A none none An Asset Owner.

Attachment 13 - MPRR 219 Recommendation Report.docx 12/19/2014 Page 5 of 7

Variable

Unit

Settlement Interval

Definition

H none none An Hour.

S none none A Settlement Location.

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.

Attachment 13 - MPRR 219 Recommendation Report.docx 12/19/2014 Page 6 of 7

Proposed Tariff Language Revision

8.5.12 Transmission Congestion Rights Daily Uplift Amount

A Day-Ahead Market daily charge will be calculated as follows for each Asset Owner

holding TCRs for each Operating Day to the extent that congestion revenues collected over the

Operating Day are not sufficient to fund the net of the total charges and payments calculated

under Section 8.5.11 over the Operating Day:

TCR Daily Uplift Amount =

(TCR Daily Shortfall Amount) * (TCR Uplift Ratio Amount)

(1) The TCR Daily Shortfall Amount is equal to the positive difference between (i) the net of

the total charges and payments calculated under Section 8.5.11 over the Operating Day

multiplied by (-1) and (ii) Total Congestion Revenues collected over the Operating Day.

(2) The Total Congestion Revenues collected over the Operating Day is equal to the sum for

all hours and Settlement Locations in the Operating Day of (total Day-Ahead cleared

Energy MW * Day-Ahead MCC) at each Settlement Location.

(3) An Asset Owner’s TCR Uplift Ratio Amount shall be equal to the lesser of (i) zero or (ii)

the sum of the absolute value of each of the hourly charges and payments calculated

under Section 8.5.11 for that Asset Owner over the Operating Day divided by the lesser

of (i) zero or (ii) the sum of the absolute value of each of the charges and payments

calculated under Section 8.5.11 for all Asset Owners over the Operating Day.

Proposed Criteria Language Revision N/A

Attachment 13 - MPRR 219 Recommendation Report.docx 12/19/2014 Page 7 of 7

Portfolio Netting in PJM

Howard J HaasSeth Hayik

SPPDecember 16, 2014

PJM IMM Recommendation: Elimination of Portfolio Netting

• In PJM, hourly and End of Planning Period (EOPP) uplift is calculated on the basis of net portfolio target allocations

• The result is that, under current PJM rules, positive target allocation FTRs are treated differently based on a participant’s portfolio• Participants with less negative target allocations

subsidize those with more negative target allocations.

©2014 www.monitoringanalytics.com 2

PJM IMM Recommendation: Elimination of Portfolio Netting

• FTRs with negative target allocations are a source of revenue, along with congestion

• FTRs with positive target allocations are recipients of revenue

• Payout to FTRs with positive target allocations is prorated when sum of positive target allocations is greater than revenue

• Payout ratio to FTRs with positive target allocations is determined by the ratio of total available revenue to total positive target allocations

©2014 www.monitoringanalytics.com 3

PJM IMM Recommendation: Elimination of Portfolio Netting

• Portfolio subsidization is eliminated by applying payout ratio only to positive target allocation FTRs, not to net portfolio value.

©2014 www.monitoringanalytics.com 4

• Congestion: $45• Net negative target allocations: $5• Total revenue available to pay net

positive portfolios: $50 ($45 + $5)

Owner Positive TA Negative TA Net TA

Portfolio

Payment

1 $60.00 ($40.00) $20.00 $8.33

2 $30.00 $0.00 $30.00 $12.50

3 $90.00 ($20.00) $70.00 $29.17

4 $0.00 ($5.00) ($5.00) ($5.00)

Total $180.00 ($65.00) $115.00 $45.00

Portfolio Composition

Portfolio Netting Payout Ratio (Current Approach)

©2014 www.monitoringanalytics.com 5

• Four FTR holders• Total of net positive target allocations is $120 ($ 20+$30+$70)

• Net total revenue available (after portfolio nettin g) = $45 + $5 = $50

• Payout ratio = total revenue / total net positive t arget allocations = $50 / $120 = 41.7%

• Total portfolio payments equals total congestion = $45

No Portfolio Netting Payout Ratio (Proposed Approac h)

©2014 www.monitoringanalytics.com 6

• Four FTR holders• Total positive target allocations are $180 ($60 + $ 30 + $90)• Total negative target allocations are $65 (-$40 + - $20 + -$5)

• No netting revenue available = $45 + $65 = $110• Payout ratio to positive target allocations = no netting revenue / positive

target allocations = $110 / $180 = 61.1%

• Total portfolio payments equals total congestion = $45

• Congestion: $45• Negative target allocations: $65• Total revenue to pay positive target

allocations: $110 ($45 + $65)

Owner Positive TA Negative TA Net TA

Portfolio

Payment

1 $60.00 ($40.00) $20.00 ($3.33)

2 $30.00 $0.00 $30.00 $18.33

3 $90.00 ($20.00) $70.00 $35.00

4 $0.00 ($5.00) ($5.00) ($5.00)

Total $180.00 ($65.00) $115.00 $45.00

Portfolio Composition

Payout Ratio Summary

©2014 www.monitoringanalytics.com 7

15%

23%

53%

-9%

Portfolio Netting Portfolio Payout

1

2

3

4

-5%

30%

57%

-8%

No Portfolio Netting Portfolio Payout

1

2

3

4

• Total of portfolio payouts to participants does not change ($45)

• Removal of portfolio netting results in uniform payout ratio to FTRs with positive target allocations (instead of uniform payout ratio to net positive portfolio value)

• Eliminates cross subsidy from portfolios without FTRs with negative target allocations to portfolios with FTRs with a negative target allocation

Elimination of Portfolio Netting: Hourly Impact

©2014 www.monitoringanalytics.com 8

Net Positive

Target

Allocations

Net Negative Target

Allocations

Reported Payout

Ratio (Current)

No Net Positive

Target

Allocations

No Net Negative

Target Allocations

No Net Payout

Ratio

(Proposed)

Total Congestion

Revenue

2013/2014 Total $2,625,369,880 ($126,385,125) 72.8% $5,442,171,151 ($2,942,754,444) 87.5% $1,819,508,754

2014/2015 Total $353,422,616 ($58,637,567) 100.0% $818,194,829 ($543,954,471) 100.0% $351,160,295

Current Proposed

• Elimination of portfolio netting improves payout ra tio to FTRs with positive target allocations

42.4%

30.3%

11.4%

11.4%

4.6%

Portfolio Netting

A

B

C

D

E

End of Planning Period (EOPP) Portfolio Netting (Current) vs No Netting (Proposed) Uplift Share

©2014 www.monitoringanalytics.com 9

30.4%

21.7%8.2%

9.2%

30.4%

No Portfolio Netting

A

B

C

D

E

Participant Positive TA Negative TA Net TA

Uplift Percent

Netting

Uplift Charge

Net Payout Netting

Percent No

Netting

Uplift Charge

No Net Payout No Net

A 280,000,000$ (1,000,000)$ 279,000,000$ 42.4% 42,420,556$ 236,579,444$ 30.4% 30,434,783$ 248,565,217$

B 200,000,000$ (1,000,000)$ 199,000,000$ 30.3% 30,256,956$ 168,743,044$ 21.7% 21,739,130$ 177,260,870$

C 75,000,000$ (300,000)$ 74,700,000$ 11.4% 11,357,762$ 63,342,238$ 8.2% 8,152,174$ 66,547,826$

D 85,000,000$ (10,000,000)$ 75,000,000$ 11.4% 11,403,375$ 63,596,625$ 9.2% 9,239,130$ 65,760,870$

E 280,000,000$ (250,000,000)$ 30,000,000$ 4.6% 4,561,350$ 25,438,650$ 30.4% 30,434,783$ (434,783)$

Portoflio Netting (Current) No Portfolio Netting (Proposed)Participant Portfolios

EOPP FTR Uplift Summary• Under current portfolio netting rules, participants with

the same positive FTR target allocations do not fac e the same End of Planning Period (EOPP) uplift charg e• Negative target allocations offset positive target

allocation positions in the portfolio• Portfolios with more negative target allocations ar e

subsidized by those with less

• Under the proposed portfolio rules, participants wi th the same positive target allocations will face the same EOPP uplift charge• Negative target allocations would not offset positi ve

target allocation positions in the portfolio• Elimination of portfolio netting eliminates cross

subsidies

• The proposed rules would treat all FTRs equally, regardless of portfolio construction

©2014 www.monitoringanalytics.com 10

Monitoring Analytics, LLC2621 Van Buren Avenue

Suite 160Eagleville, PA

19403

(610) 271-8050

MA@monitoringanalytics.com

www.MonitoringAnalytics.com

©2014 www.monitoringanalytics.com 11

PRR Comments

PRR No. 181 PRR

Title Mirrored JOU Share Option

Date 12/4/2014

Submitter Name Jared Greenwalt E-mail Address jgreenwalt@spp.org Company Southwest Power Pool Phone Number 501.688.8314

Comments

These comments provide the additional language and modifications that are necessary to implement MPRR 181 as initially proposed by Westar with the exception of allowing the new JOU option to also be registered as a Combined Cycle Unit.

Revised Proposed Protocol Language Revision

4.2.1.1 Day-Ahead Market

(A) Each Market Participant with registered load must satisfy the must offer obligation for each

Asset Owner associated with that registered load as set forth in Section 4.2.1.1 based on the

following criteria:

…

(4) A load-serving Market Participant’s net resource capacity, for an Asset Owner for purposes

of this section shall include:

(a) Offered capacity by Resources identified in (3) above less the Operating Reserve

obligation identified in (2) above; and

(b) Firm Power purchases less the Firm Power sales, except that, if the seller has

registered the buyer’s load associated with a firm power sale, such firm power sale

shall not act to increase the buyer’s net resource capacity or act to reduce the seller’s

net resource capacity.

(i) For purposes of this Section 4.2.1.1, firm power purchases and firm power

sales shall mean sales and purchases that are deliverable with service

comparable to Firm Point-To-Point Transmission Service or Firm Network

Integration Transmission Service with the supplier assuming the obligation

to provide both capacity and energy. Additionally, firm power purchases

shall include an Asset Owner’s share of a Jointly Owned Unit to the extent

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 1 of 18

that such shares have not been registered as separate Resources either under

the JOU Individual Resource Option, or the JOU Combined Resource

Option, or the Mirrored JOU Share OptionSingle Resource Option as

described under Section 4.2.2.5.4. In order to verify firm power purchases

and firm power sales, supporting documentation must be provided to the

Market Monitor upon request. Market Participants have the option to input

information regarding firm power purchases and firm power sales into the

Market Monitor website. If no information is input into this website, the

Market Monitor will contact the Market Participant for that information.

The Market Monitor may confirm the firm purchase or sale with the

counterparty and will include the transacted MWs to calculate net resource

capacity for both purchaser and seller. If one of the parties dispute the firm

purchase or sale to the Market Monitor, then the firm purchase or sale will

not be used in the calculation of either the purchaser’s or seller’s net

resource capacity.

…

4.2.2.5.4 Jointly Owned Unit

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

Resources using eithereither the Individual Resource Option, or the Combined Resource Option, or the

Mirrored JOU Owner ShareSingle Resource Option as specified during market registration as described

under Section 6.1.6. Otherwise, the Resource is modeled like any other single Resource with an

associated single Asset Owner. Resource offers may be submitted for each Asset Owner’s JOU

ownership (“JOU Share Resource”) the same as any other Resource subject to the following Resource

Offer validation rules and exceptions.

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

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

by or on behalf of the Asset Owner identified at registration (“designated Asset Owner”):

(a) JOU maximum physical capacity operating limit;

(b) JOU minimum physical capacity operating limit;

(c) maximum physical 10-minute response from an off-line state (if a Quick-Start Resource);

and

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 2 of 18

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

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

Option).

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

Share Resource must meet the following criteria in order to be accepted as valid offers,

otherwise, all Offers related to the Physical JOU Resource will revert to the last valid offer;

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

Resource associated with the Physical JOU Resource must be less than or equal to the

Physical JOU Resource maximum physical capacity operating limit; and

(b) The sum of the Minimum Emergency Capacity Operating Limits of each JOU Share

Resource associated with the Physical JOU Resource must be greater than or equal to the

Physical JOU Resource minimum physical capacity operating limit;

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

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

JOU Share Resource;

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

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

for each JOU Share Resource and the Offer parameters submitted by or on behalf of the

designated Asset Owner that apply to the entire Physical JOU Resource (see Section 4.2.2.1 for

footnoted parameters to be submitted by or on behalf of the designated Asset Owner and Section

4.2.2.2 regarding Commitment Status) given the additional constraint that if one of the JOU

Resources is committed, all JOU Share Resources associated with the Physical JOU Resource

must be committed or the Mirrored JOU Owner Share Option will be evaluated by SCUC based

on Designated Asset Owner share energy offers mirrored by SPP to all other joint ownership

shares and the unit commitment Offer parameters submitted by or on behalf of the designated

Asset Owner that apply to the entire Physical JOU Resource (see Section 4.2.2.1 for footnoted

parameters to be submitted by or on behalf of the designated Asset Owner and Section 4.2.2.2

regarding Commitment Status) given the additional constraint that if one of the JOU Resources is

committed, all JOU Share Resources associated with the Physical JOU Resource must be

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

Resources. Prior to evaluation by SCUC, each JOU Share Resource associated with the Physical

JOU Resource is assigned the following unit commitment parameters as submitted by or on

behalf of the designated Asset Owner:

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

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

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

value will be used for make-whole-payment calculation purposes;

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 3 of 18

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

with the Physical JOU Resource is calculated by multiplying the Mitigated Start-Up

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

Percent Share and this value will be used for make-whole-payment calculation purposes;

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

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

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

value will be used for make-whole-payment calculation purposes;

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

with the Physical JOU Resource is calculated by multiplying the Mitigated No-Load

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

Percent Share and this value will be used for make-whole-payment calculation purposes;

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

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

JOU Resource;

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

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

JOU Resource;

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

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

Resource;

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

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

for the Physical JOU Resource;

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

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

JOU Resource;

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

the Physical JOU Resource is set equal to the Maximum Daily Starts submitted for the

Physical JOU Resource;

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

with the Physical JOU Resource is set equal to the Maximum Weekly Starts submitted

for the Physical JOU Resource;

(l) Under the Combined Resource option, The tThe Maximum Daily Energy of each Asset

Owner’s JOU Share Resource associated with the Physical JOU Resource is calculated

by multiplying the Maximum Daily Energy submitted for the Physical JOU Resource by

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 4 of 18

that Asset Owner’s JOU Ownership Percent Share; or under the Mirrored JOU Owner

Option, SPP will calculate mirrored offers from the designated asset owner energy offer

as shown (see following example). The Energy Offer of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is calculated by mirror imaging and

scaling Designated Asset Owner energy offer into single aggregate 3-part offer, as

calculated from the designated owner offer. Thus, the SPP dispatch clearing will

reasonably attempt to clear and settle Mirrored JOU owners according to their share

ownership. See Example below;

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

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

JOU Resource;

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

the Physical JOU Resource is set equal to the Minimum Down Time submitted for the

Physical JOU Resource;

SPP Market Portal Offer Submission

(Designate Owner)

SPP Market Portal Offer Submission

(Designate Owner)

SPP Pre-processor

Mirrored Offer for 2nd JOU owner

SPP Pre-processor

Mirrored Offer for 2nd JOU owner

SPP Pre-processor

Mirrored Offer for 3rd JOU owner

SPP Pre-processor

Mirrored Offer for 3rd JOU owner

250 5,700 26.80 125 26.80 75 26.80 50 26.80300 6,600 30.40 150 30.40 90 30.40 60 30.40350 7,000 32.00 175 32.00 105 32.00 70 32.00400 7,180 32.72 200 32.72 120 32.72 80 32.72450 7,200 32.80 225 32.80 135 32.80 90 32.80500 9,500 42.00 250 42.00 150 42.00 100 42.00550 10,500 46.00 275 46.00 165 46.00 110 46.00

SPP Market Portal Offer Submission

(Designate Owner)

SPP Pre-processor

Mirrored Offer for 2nd JOU owner

SPP Pre-processor

Mirrored Offer for 3rd JOU owner

2,000$ 1,000$ 600$ 400 40,000$ 20,000$ 12,000$ 8,000

4 $/mmbtu natural gas4 $/mwh VOM

SPP generated Mirrored Offer Point for 2nd

Owner $/mwh

SPP generated Capacity share

(20%) for 3rd JOU owner

MW

SPP generated Mirrored Offer Point for 3rdd

Owner $/mwh

Total JOU Unit

Capacity Point MW

Total JOU unit Incr HR

btu/kwh

Total JOU unit Incr Energy

$/mwh

Designated 1st Owner Capacity

share offer (50%) Point

MW

Designated 1st Owner share Offer Point

$/mwh

SPP generated Capacity share (30%) for 2nd

JOU owner MW

10000 500

Table 4.2.2.5.4 SPP MIRRORED JOU 3-Part SHARE OFFERS

Total JOU Unit

"Cold" Startup

Fuel mmbtu

Total JOU No-Load

Fuel mmbtu/Hr

Total JOU unit Startup $

===== No-load $/Hr

1st Owner share Offers

(50%) Startup $

===== No-load $/Hr

2nd Owner share Offers

(30%) Startup $ /

No-load $/Hr

3rd Owner share Offers (20%)

Startup $ /

No-load $/Hr

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 5 of 18

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

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

Physical JOU Resource;

(p) The Maximum Quick-Start Response Limit of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is calculated by multiplying the Maximum

Quick-Start Response Limit submitted for the Physical JOU Resource by that Asset

Owner’s JOU Ownership Percent Share; and

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

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

JOU Resource.

(5) Commitment of JOU Share Resources that have registered under the Single Resource option will

be evaluated by SCUC based on the Offer parameters submitted by or on behalf of the

designated Asset Owner that apply to the entire Physical JOU Resource (see Section 4.2.2.1 for

footnoted parameters to be submitted by or on behalf of the designated Asset Owner and Section

4.2.2.2 regarding Commitment Status) and individual JOU Share Resources given the additional

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

associated with the Physical JOU Resource must be committed. This rule also applies to clearing

of Supplemental Reserve from off-line Quick-Start Resources. Prior to evaluation by SCUC,

each JOU Share Resource associated with the Physical JOU Resource is assigned the following

unit commitment and dispatch parameters as submitted by or on behalf of the designated Asset

Owner:

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

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

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

value will be used for make-whole-payment calculation purposes;

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

with the Physical JOU Resource is calculated by multiplying the Mitigated Start-Up

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

Percent Share and this value will be used for make-whole-payment calculation purposes;

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

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

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

value will be used for make-whole-payment calculation purposes;

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

with the Physical JOU Resource is calculated by multiplying the Mitigated No-Load

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

Percent Share and this value will be used for make-whole-payment calculation purposes;

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 6 of 18

(e) The Minimum Emergency Capacity Operating Limit of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is calculated by multiplying the

Minimum Emergency Capacity Operating Limit submitted for the Physical JOU

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

(f) The Minimum Normal Capacity Operating Limit of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is calculated by multiplying the

Minimum Normal Capacity Operating Limit submitted for the Physical JOU Resource by

that Asset Owner’s JOU Ownership Percent Share;

(g) The Minimum Economic Capacity Operating Limit of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is calculated by multiplying the

Minimum Economic Capacity Operating Limit submitted for the Physical JOU Resource

by that Asset Owner’s JOU Ownership Percent Share;

(h) The Minimum Regulation Capacity Operating Limit of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is calculated by multiplying the

Minimum Regulation Capacity Operating Limit submitted for the Physical JOU Resource

by that Asset Owner’s JOU Ownership Percent Share;

(i) The Maximum Emergency Capacity Operating Limit of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is calculated by multiplying the

Maximum Emergency Capacity Operating Limit submitted for the Physical JOU

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

(j) The Maximum Normal Capacity Operating Limit of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is calculated by multiplying the

Maximum Normal Capacity Operating Limit submitted for the Physical JOU Resource

by that Asset Owner’s JOU Ownership Percent Share;

(k) The Maximum Economic Capacity Operating Limit of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is calculated by multiplying the

Maximum Economic Capacity Operating Limit submitted for the Physical JOU Resource

by that Asset Owner’s JOU Ownership Percent Share;

(l) The Maximum Regulation Capacity Operating Limit of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is calculated by multiplying the

Maximum Regulation Capacity Operating Limit submitted for the Physical JOU

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

(m) The Ramp-Rate-Up of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is calculated by multiplying the Ramp-Rate-Up submitted for the

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

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 7 of 18

(n) The Energy Offer Curve of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is set equal to the Energy Offer Curve submitted for the Physical

JOU Resource;

(o) The Ramp-Rate-Down of each Asset Owner’s JOU Share Resource associated with the

Physical JOU Resource is calculated by multiplying the Ramp-Rate-Down submitted for

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

(p) The Regulation Ramp Rate of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is calculated by multiplying the Regulation Ramp Rate

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

Share;

(q) The Contingency Reserve Ramp Rate of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is calculated by multiplying the Contingency

Reserve Ramp Rate submitted for the Physical JOU Resource by that Asset Owner’s JOU

Ownership Percent Share;

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

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

JOU Resource;

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

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

JOU Resource;

(t) The Start-Up Time of each Asset Owner’s JOU Share Resource associated with the

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

Resource;

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

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

for the Physical JOU Resource;

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

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

JOU Resource;

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

the Physical JOU Resource is set equal to the Maximum Daily Starts submitted for the

Physical JOU Resource;

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

with the Physical JOU Resource is set equal to the Maximum Weekly Starts submitted

for the Physical JOU Resource;

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 8 of 18

(y) The Maximum Daily Energy of each Asset Owner’s JOU Share Resource associated with

the Physical JOU Resource is calculated by multiplying the Maximum Daily Energy

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

Share;

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

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

JOU Resource;

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

the Physical JOU Resource is set equal to the Minimum Down Time submitted for the

Physical JOU Resource;

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

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

Physical JOU Resource;

(cc) The Maximum Quick-Start Response Limit of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is calculated by multiplying the Maximum

Quick-Start Response Limit submitted for the Physical JOU Resource by that Asset

Owner’s JOU Ownership Percent Share;

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

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

JOU Resource;

(ee) The Dispatch Status for Energy of each Asset Owner’s JOU Share Resource associated

with the Physical JOU Resource is set equal to the Dispatch Status for Energy submitted

for the Physical JOU Resource;

(ff) The Dispatch Status for Regulation-Up of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is set equal to the Dispatch Status for

Regulation-Up submitted for the Physical JOU Resource. If the submitted Regulation-Up

Dispatch Status associated with the Physical JOU Resource is Fixed, the Regulation-Up

Fixed MW for each Asset Owner’s JOU Share Resource is calculated by multiplying the

Regulation-Up Fixed MW submitted for the Physical JOU Resource by that Asset

Owner’s JOU Ownership Percent Share;

(gg) The Dispatch Status for Regulation-Down of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is set equal to the Dispatch Status for

Regulation-Down submitted for the Physical JOU Resource. If the submitted Regulation-

Down Dispatch Status associated with the Physical JOU Resource is Fixed, the

Regulation-Down Fixed MW for each Asset Owner’s JOU Share Resource is calculated

by multiplying the Regulation-Down Fixed MW submitted for the Physical JOU

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

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 9 of 18

(hh) The Dispatch Status for Spinning Reserve of each Asset Owner’s JOU Share Resource

associated with the Physical JOU Resource is set equal to the Dispatch Status for

Spinning Reserve submitted for the Physical JOU Resource. If the submitted Spinning

Reserve Dispatch Status associated with the Physical JOU Resource is Fixed, the

Spinning Reserve Fixed MW for each Asset Owner’s JOU Share Resource is calculated

by multiplying the Spinning Reserve Fixed MW submitted for the Physical JOU

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

(ii) The Dispatch Status for Supplemental Reserve of each Asset Owner’s JOU Share

Resource associated with the Physical JOU Resource is set equal to the Dispatch Status

for Supplemental Reserve submitted for the Physical JOU Resource. If the submitted

Supplemental Reserve Dispatch Status associated with the Physical JOU Resource is

Fixed, the Supplemental Reserve Fixed MW for each Asset Owner’s JOU Share

Resource is calculated by multiplying the Supplemental Reserve Fixed MW submitted

for the Physical JOU Resource by that Asset Owner’s JOU Ownership Percent Share.

(5)(6) If committed, each JOU Share Resource will be considered separately for the purposes of

dispatch, Operating Reserve clearing and settlement; andadditionally the Physical JOU Resource

will receive an aggregate Setpoint Instruction for the purposes of Energy and Operating Reserve

deployment;

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

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

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

Offers and Ramp Rate;

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

DA Market make-whole payment under the same eligibility rules as any other Resource

as described under Section 4.5.8.12;

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

Energy Offer Curve, Ramp-Rate-Up and Ramp-Rate-Down and is cleared for Operating

Reserve based on the submitted Operating Reserve Offers, Ramp-Rate-Up and Ramp-

Rate-Down. SPP sends to each Asset Owner it’s independent Dispatch Instruction,

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

Share Resource.

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

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

Dispatch Instructions, and (ii) each Asset Owner’s independent Setpoint Instructions

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

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 10 of 18

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

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

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

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

individual JOU Share Resource is eligible to receive a RUC make-whole payment

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

4.5.9.8.

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

Resource Deviation that exceeds the JOU Share Resource Operating Tolerance as

described under Sections 4.5.9.8 and 4.5.9.10, Regulation deployment failure

charges as described under Section 4.5.9.15 and Contingency Reserve deployment

failure charges as described under Section 4.5.9.17, under the same eligibility

rules as any other Resource.

(6)(7) The Meter Agent(s) assigned to the Physical JOU Resource must account for all physical

Energy produced and properly reflect this Energy in each individual JOU Share Resource meter

data submittal.

6.1.6 Jointly Owned Resource

In addition to the responsibilities described under Section 6.1.1, Market Participants wishing to model

each ownership share as a separate Resource must choose one of the two three options described below

and provide the specified additional information. Only the Jointly Owned Unit “Mirrored JOU Owner

Share Option” may be registered A Resource registeredA Resource registered as a Combined Cycle

Resource. All other Jointly Owned Unit options may not be registered as a combined cycle Resource.

may not register as a JOU.may not register as a JOU.

6.1.6.1 Individual Resource Option

Under the Individual Resource Option, each ownership share is modeled as a separate Resource for the

purposes of commitment and dispatch and each Resource may be committed independent of the other

Resource shares. In order to qualify for this option, all Asset Owners must certify that if their ownership

share Resource is the only Resource committed, that their ownership share is greater than or equal to the

minimum physical capacity operating limit of the Physical JOU Resource. The following additional

information must also be provided and/or specified:

(1) Specification of a single Asset Owner that will be responsible for submittal of the following

operating data representing the physical operating characteristics of entire JOU Resource for use

in data validation as described under Section 4.2.2.5.4;

(a) JOU maximum physical capacity operating limit;

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 11 of 18

(b) JOU minimum physical capacity operating limit; and

(c) Maximum physical 10-minute response from an off-line state.

(2) Specification of each Asset Owner and Settlement Location associated with each individual

ownership share.

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

Resource unless each individual JOU Resource owner registers a different Meter Agent for its share of

the Resource.

6.1.6.2 Combined Resource Option

Under the Combined Resource Option, each ownership share is modeled as a separate Resource for the

dispatch purposes but commitment related parameters are submitted representing the entire physical

Resource. Under this option, the commitment decision is made assuming that all Resource shares must

be committed or none at all. This option must may be selected if the eligibility criteria stated under the

Individual Resource Option cannot be met. The following additional information must also be provided

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

submittal by or on its behalf of all unit commitment related data and the following operating data

representing the physical operating characteristics of entire JOU Resource for use in data

validation as described under Section 4.2.2.5.4;

(a) JOU maximum physical capacity operating limit;

(b) JOU minimum physical capacity operating limit; and

(c) Maximum physical 10-minute response from an off-line state.

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

associated with each individual ownership share JOU Resource.

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

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

Resource unless each individual JOU Resource owner registers a different Meter Agent for its share of

the Resource.

6.1.6.3 Mirrored JOU Owner ShareSingle Resource Option

Under the Mirrored JOU Owner ShareSingle Resource Option, each ownership share is modeled as a

separate Resource for the dispatch purposes and both commitment and dispatch related parameters are

submitted representing the entire physical Resourcethe operating owner three part offer will be mirrored

for all other owner shares as separate resources. Thus, the energy offer curve submitted by the

designated asset owner operator will be mirrored by SPP for all other owner energy offers. This is done

if the joint owner’s desire share proportioned clearing of the JOU. Similar to the Combined Option, the

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 12 of 18

commitment related parameters are submitted by the designated asset owner representing the entire

physical Resource. Under this option, the commitment decision is made assuming that all Resource

shares must be committed or none at all. This option willmay be selected if the eligibility criteria stated

under the Individual Resource Option cannot be met and the Combined Option is not selected. The

following additional information must also be provided:

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

submittal by or on its behalf of all energy and unit commitment offerrelated data and the

following operating data representing the physical operating characteristics of entire JOU

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

(a) JOU maximum physical capacity operating limit;

(b) JOU minimum physical capacity operating limit; and

(c) Maximum physical 10-minute response from an off-line state.

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

associated with each individual ownership share JOU Resource. All market payments, charges,

uplifts, and penalties associated with cleared Day-Ahead and Real-Time market offers will be

settled by SPP according to registered ownership share percentages under the Mirrored JOU

Owner Share Option.

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

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

Resource unless each individual JOU Resource owner registers a different Meter Agent for its share of

the Resource.

Revised Proposed Tariff Language Revision

Attachment AE

2.2 Application and Asset Registration

…

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

under the Market Protocols, Market Participants wishing to model each participant’s

share of a Jointly Owned Unit as a separate Resource must choose one of the two three

options described below and provide the specified additional information. Only the

Jointly Owned Unit “Mirrored JOU Owner Share Option” may be registered A Resource

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

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 13 of 18

Jointly Owned Unit.may not register as a Jointly Owned Unit. All other Jointly Owned

Unit options may not be registered as a combined cycle Resource.

(a) Individual Resource Option

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

as a separate Resource for the purposes of commitment and dispatch and each

Resource may be committed independent of the other Resource shares. In order

to qualify for this option, each Market Participant must register its share and

certify that it is greater than or equal to the minimum physical capacity operating

limit of the physical Jointly Owned Unit.

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

Jointly Owned Unit unless each individual Jointly Owned Unit participant

registers a Meter Agent for its share of the Resource.

Unless otherwise agreed to by the Jointly Owned Unit participants, the

operating owner will be responsible for submitting the following data:

• Jointly Owned Unit maximum physical capacity operating limit;

• Jointly Owned Unit minimum physical capacity operating limit; and

• Maximum physical ten (10) minute response from an off-line state. (b) Combined Resource Option

Under the combined Resource option each participant’s share is modeled

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

commitment decision is made assuming that all Resource shares must be

committed or none at all. Once committed, each share is dispatched

independently. This option must may be selected if the eligibility criteria stated

under the individual Resource option cannot be met.

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

Jointly Owned Unit unless each individual Jointly Owned Unit participant

registers a Meter Agent for its share of the Resource.

Unless otherwise agreed to by the Jointly Owned Unit participants, the

operating owner will be responsible for submitting the following data:

• Jointly Owned Unit maximum physical capacity operating limit;

• Jointly Owned Unit minimum physical capacity operating limit;

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

and

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 14 of 18

• Participant share percentage by Market Participant.

(bc) Mirrored JOU ShareSingle Resource Option

Under the Mirrored JOU Sharesingle Resource Option, each participant’s

share can beis modeled and can be registered as a separate or single Resource for

the purpose of dispatch.or a single resource have separate SPP JOU share

settlement. Under this option, the commitment decision is made assuming that all

Resource shares must be committed or none at all. Once committed, the

operating owner (Designated Asset Owner) energy curve is mirrored onto either

JOU share units or into a single JOU aggregate unit. This option or the Combined

Resource Option mustmay be selected if the eligibility criteria stated under the

individual Resource option cannot be met.

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

Jointly Owned Unit unless each individual Jointly Owned Unit participant

registers a Meter Agent for its share of the Resource.

Unless otherwise agreed to by the Jointly Owned Unit participants, the

operating owner will be responsible for submitting the following dataBy

agreement of the Jointly Owned Unit participants, the operating owner will be

responsible for submitting all energy, operating reserve, and unit commitment

offer data, including:

• Jointly Owned Unit maximum physical capacity operating limit;

• Jointly Owned Unit minimum physical capacity operating limit;

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

and

• Participant share percentage by Market Participant.

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

registration procedures specified in the Market Protocols.

…

2.9 Combined Cycle Resource

Market Participants registering Resources with combined cycle capability as described in

Section 4.1.2.2 of this Attachment AE shall select only one configuration during market

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 15 of 18

registration. Market Participants that jointly participate in a combined cycle Resource that desire

to use the Jointly Owned Unit modeling options described under Section 2.2(4) of this

Attachment AE must register as a Jointly Owned Unit and cannot must cannot register the

Resource as a Mirrored JOU Owner Share Option”. . All other Jointly Owned Unit options

may not be registered as a combined cycle Resource.combined cycle Resourcecombined cycle

Resource. Modifications to Resource configurations may be made in accordance with timing

requirements defined in the Market Protocols.

2.11.1 Day-Ahead Market

A. Each Market Participant must satisfy the must offer obligation for an Asset Owner as set forth in

Section 2.11.1(B) of this Attachment AE based on the following criteria:

… (4) A Market Participant’s net resource capacity for an Asset Owner, for purposes of this

section shall include:

i. Offered capacity by Resources identified in Section 2.11.1(A)(3) of Attachment

AE less the Operating Reserve obligation identified in Section 2.11.1(A)(2) of

Attachment AE; and

ii. Firm power purchases less firm power sales, except that, if the seller has

registered the buyer’s load associated with a firm power sale as described in

Section 2.2(11) of this Attachment AE, such firm power sale shall not act to

increase the buyer’s net resource capacity or act to reduce the seller’s net resource

capacity. For purposes of this Section 2.11.1 of this Attachment AE firm power

purchases and firm power sales shall mean sales and purchases that are

deliverable with transmission service comparable to Firm Point-To-Point

Transmission Service or Firm Network Integration Transmission Service with the

supplier assuming the obligation to provide both capacity and energy.

Additionally, firm power purchases shall include an Asset owner’s share of a

Jointly Owned Unit to the extent that such shares have not been registered as

separate Resources either under Jointly Owned Unit individual Resource option,

or the Jointly Owned Unit combined Resource option or the Jointly Owned Unit

single Resource option as described under Section 2.2(4) of this Attachment AE.

In order to verify firm power purchases and firm power sales, supporting

documentation must be provided to the Market Monitor upon request. Market

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 16 of 18

Participants have the option to input information regarding firm power purchases

and firm power sales into the Market Monitor website. If no information is input

into this website, the Market Monitor will contact the Market Participant for that

information. The Market Monitor may communicate with the counterparty to

confirm the firm purchase or sale and will include the transacted MWs to

calculate net resource capacity for both purchaser and seller. If one of the parties

disputes the firm purchase or sale to the Market Monitor, then the firm purchase

or sale will not be used in the calculation of either the purchaser’s or seller’s net

resource capacity subject to any dispute resolution.

4.1.2.3 Jointly Owned Unit

Each Market Participant may submit Resource Offers for its share of the Jointly

Owned Unit. Offer parameters must meet the following criteria in order to be accepted as

valid Offers:

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

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

maximum physical capacity operating limit;

(2) The sum of the Minimum Emergency Capacity Operating Limits of all shares of

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

minimum physical capacity operating limit.

Commitment of individual Jointly Owned Unit shares that have registered under

the individual Resource option will be evaluated by security constrained unit

commitment (“SCUC”) based on the individually submitted Offers for each Jointly

Owned Unit share.

Commitment of Jointly Owned Unit shares that have registered under the

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

individually submitted Offers for each Jointly Owned Unit share and the commitment

related Offer parameters submitted by the designated Market Participant that apply to the

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

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

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

Quick-Start Resources.

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 17 of 18

Commitment of Jointly Owned Unit shares that have registered under the

Mirrored JOU Sharesingle Resource Ooption will be evaluated by SCUC based on the

dispatch related Offer parameters submitted by the designated Market Participant that

apply to each Jointly Owned Unit share and a combination of the mirrored operating

owner submission and mirrored Jointly Owned Unit share and the commitment related

Offer parameters submitted by the designated Market Participant, effectively modeled as

a single operator owner 3 part offer for a JOU shares, to that apply to the entire Jointly

Owned Unit given the additional constraint that if one of the Jointly Owned Units shares

is committed, all Resource shares for each Jointly Owned Unit must be committed. This

rule also applies to clearing of Supplemental Reserve from off-line Quick-Start

Resources.

Revised Proposed Criteria Language Revision

N/A

Attachment 15 - MPRR 181 SPP Comments 12-4-2014.docx Page 18 of 18

PRR Comments

MPRR

No. 217 MPRR Title Regulation Certification Testing Procedure

Date 11/14/2014

Submitter Name Raleigh Mohr E-mail Address rmohr@spp.org Company Southwest Power Pool Phone Number 501.482.2206

Comments

After the initial posting, SPP discussed the changes internally and decided that the test was too strenuous. SPP decided to relax the test some by changing the ramping periods from 30 seconds to 1 minute each and changing the steady state periods after the ramping periods from 30 seconds to one minute each as well.

All changes are highlighted in yellow.

Reason for Revision

This purpose of this revision is to change the regulation certification testing procedure requirements for resources. The current test’s rate of response interval is 5 minutes. This would be appropriate to test for energy deployment, not regulation deployment. A shorter rate of response interval will better test a resource’s AGC response for regulation deployment.

Revision Description

This MPRR changes the regulation testing procedures and regulation testing scoring from 5 minutes intervals to 1 minute intervals. This will have the Market Participant follow a 1 minute rate of response instead of the 5 minutes. The 5 minutes rate of response is a good test for energy deployment. The one minute rate of response will be a better test for regulation deployment.

Revised Proposed Protocol Language Revision

6.1.11.3 Regulation Qualified Resources

There are specific testing requirements for a Resource to become a Regulation Qualified Resource,

Regulation-Up Qualified Resource or Regulation-Down Qualified Resource:

(1) A resource may be certified as a Regulation Qualified Resource, Regulation-Up Qualified

Resource or Regulation-Down Qualified Resource only after it achieves three consecutive

Regulation Test Scores of 75% or above through the testing procedures described under Section

(7);

Attachment 16 - MPRR 217 SPP Comments 11-14-2014.docx Page 1 of 5

(2) The first of these tests may be performed internally by the Asset Owner. Notification to perform

a regulation test must be made to SPP at least 20 minutes before the test ;

(3) SPP makes the final determination about whether a regulation test can be performed ;

(4) Only one test may be performed on a Resource each Operating Day; ;

(5)

(6) SPP may perform a regulation test on any Regulation Qualified Resource, Regulation-Up

Qualified Resource or Regulation-Down Qualified Resource to verify continued certification;

(7) A Market Participant may request a re-test if it’s Resource was disqualified as a Regulation

Qualified Resource, Regulation-Up Qualified Resource or Regulation-Down Qualified Resource

by SPP as described under Section 4.4.3.1. The Resource must attain a test score of 75 % or

greater in order to be re-qualified;

(8) After initial certification, a Compliance Rating of 75% or above must be maintained as described

under Section 6.1.11.3.3.

6.1.11.3.1 Regulation Testing Procedures

The Regulation test to verify both Regulation-Up Service and Regulation-Down Service capability is

run during a continuous 40-minute period. The Regulation test to verify either Regulation-Up Service

capability or Regulation-Down Service capability is run during a continuous 20-minute period. Such

tests are run when, in the judgment of the SPP test administrator, economic or other conditions do not

otherwise change the Dispatch Instruction of the Resources that are being tested. Changes in Dispatch

Instructions for a Resource during the test period invalidate the test for that Resource. During the

Regulation test, the Setpoint Instruction is fixed in each of two three or four five consecutive 102-minute

periods. The following steps describe the implementation of the test. It is assumed that the Regulation-

Up Service deployment is positive and Regulation-Down Service deployment is negative. A test may

start with either a Regulation-Up Service deployment (if certifying as Regulation Qualified Resource or

Regulation-Up Qualified Resource) or a Regulation-Down Service deployment (if certifying as

Regulation Qualified Resource or Regulation-Down Qualified Resource) but the steps below assume

that the test starts with a Regulation-Up deployment.

(1) Step One: T0-T10T21 — During this time period, the stepped Setpoint Instruction is equal to

the Dispatch Instruction (i.e. Regulation-Up Service or Regulation-Down Service deployment is

equal to zero). This is the initiation of the Regulation test. This tentwo-minute period is provided

so that the Resource settles at its Dispatch Instruction. At T10T1, the actual loading is sampled

and the resulting value defines the Base Loading for that Resource which is shown as the zero

axis in Exhibit 6-1.

(2) Step Two: T10T21-T20T42 — At the start of this 210 minute period, the stepped Setpoint

Instruction is increased by 5 times the Resource’s Regulation Ramp Rate to simulate the

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

Comment [MPRR102.2]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.3]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.4]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.5]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.6]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.7]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.8]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.9]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.10]: MPRR102 Awaiting implementation. #ER13-1748

Attachment 16 - MPRR 217 SPP Comments 11-14-2014.docx Page 2 of 5

maximum amount of Regulation-Up Service deployment available on the Resource in one

minute (Note that this step is skipped for Regulation-Down Qualified Resource certification).

(3) Step Three: T20T42-T30T63 —At the start of this 210 minute period, the stepped Setpoint

Instruction is returned back to the Resource’s Base Loading level (i.e., the Regulation-Up

Service deployment is set to zero). Note that for a Resource that is only certifying to provide

Regulation-Up Service only, this step constitutes the end of the test.

(4) Step Four: T30T63-T40T84 — At the start of this 210 minute period, the stepped Setpoint

Instruction is reduced by 5 times the Resource’s Regulation Ramp Rate to simulate the

maximum amount of Regulation-Down Service deployment available on the Resource in one

minute. Note that for a Resource that is only certifying to provide Regulation-Down Service

only, this step constitutes the beginning of the test.

(5) Step Five: T40T48 — At this time, the stepped Setpoint Instruction is returned back to the

Resource’s Base Loading level to terminate the test at T50T105.

Exhibit 6-2 illustrates these five steps.

Exhibit 6-2: Regulation Testing Procedure

Stepped Setpoint Instruction Ramped Setpoint Instruction

6.1.11.3.2 Regulation Testing Scoring

Scoring the Regulation Test Score is based on the average of two independent test scores: Rate of

Response Compliance test score and Regulation Mismatch Compliance test score.

(1) Rate of Response Compliance — The rate of response compliance is a measure of a Resource‘s

ability to achieve its Regulation deployment within five one (51) minutes. The Rate of Response

Compliance is an average of four1 compliance calculations corresponding to the end of each of

1 For Resources only certifying to supply Regulation-Up or Regulation-Down, this value is equal to two.

0

210 420

630 8400 10

Regulation-Up Deployment

Regulation-Down Deployment

Ideal Response

T

1.53

2.55

3.57 4.59

Comment [MPRR102.11]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.12]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.13]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.14]: MPRR102 Awaiting implementation. #ER13-1748

Comment [MPRR102.15]: MPRR102 Awaiting implementation. #ER13-1748

Attachment 16 - MPRR 217 SPP Comments 11-14-2014.docx Page 3 of 5

the four (4) 51-minute ramping periods (T31.5, T2.5, T73.5 and T94.5)2 during the test and is

determined as follows:

(2) At T31.5, a snapshot of Resource output is taken. This value is called AG31.5. The Rate of

Response Compliance at time T31.5 (RORC31.5) is:

RORC31.5 = 100 – [ [ ABS [ Ramped Setpoint Instruction – AG31.5 ]

/ Ramp-Rate-Up * 5 ] *100 ]

(3) The calculation is repeated at T52.5, T73.5 and T94.5, yielding RORC52.5, RORC73.5 and

RORC94.5.

(4) The Rate of Compliance is then equal to:

Rate of Compliance = [RORC1.53 + RORC2.5 + RORC73.5 + RORC94.5 ] / 4

(5) Regulation Mismatch Compliance — The Regulation mismatch compliance is a measure of a

Resource‘s ability to maintain its actual output at a constant desired level for five one minutes.

The Regulation Mismatch Compliance is an average of four3 mismatch calculations,

corresponding to samples taken during four, five one minute periods when the Resource response

yields an actual loading equal to the ramped Setpoint Instruction. These time periods are T15-

T20T2, T25T32.5-T30T43, T35T53.5-T40T6,4 and T45T74.5-T50T854. During these time

periods, the actual loading is sampled.

(a) During the time period T1.5-T20T2, a number of Resource output snapshots, n, of actual

loading, AG1, AG2, AGn, are taken. The Regulation Mismatch Compliance for the

T1.5-T20T2 period (RMRC20) is:

RMRC20 = {∑n

{ 100 – [ [ ABS [ Ramped Setpoint Instruction – AGn ]

/ Ramp-Rate-Up * 5 ] *100 ] } } / n

(b) The calculation is repeated for T32.5-T30T43, T35T53.5-T40T64, and T45T74.5-

T50T85 yielding RMRC430, RMRC640, and RMRC850.

(c) The Regulation Mismatch Compliance is then equal to:

Regulation Mismatch Compliance =

[RMRC20 + RMRC430 + RMRC640 + RMRC850 ] / 4

(6) Regulation Test Score — The Regulation Test Score is calculated as the average of the Rate of

Compliance test score and the Regulation Mismatch Compliance test score:

2 For Resources only certifying to supply Regulation –Up, only T31.5 and T2.5 are used. For Resources only certifying to supply Regulation-Down, only T3.5 7and T4.59 are used. 3 For Resources only certifying to supply Regulation-Up or Regulation-Down, this value is equal to two. 4 For Resources only certifying to supply Regulation–Up, only T1.5-T20T2 and T32.5-T30T43 are used. For Resources only certifying to supply Regulation-Down, only T53.5-T40T64 and T74.5-T50T85 are used.

Attachment 16 - MPRR 217 SPP Comments 11-14-2014.docx Page 4 of 5

Regulation Test Score = [Rate of Compliance + Regulation Mismatch Compliance]

/ 2

Revised Proposed Tariff Language Revision N/A

Revised Proposed Criteria Language Revision N/A

Attachment 16 - MPRR 217 SPP Comments 11-14-2014.docx Page 5 of 5

PRR Recommendation Report

MPRR No. 222 PRR

Title Allow Max of Zero for VERs

Timeline

Normal Expedited Urgent Action

Provide explanation if Expedited and/or Urgent Action is selected: This MPRR is Expedited to make it on the next CWG Quarterly Report.

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Ranking Medium

Impact Analysis Required Yes, Estimated Cost: $ 15,813 Duration: 5 months No

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: None Submitted Title: None Submitted Protocol Version: None Submitted

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description

This change will allow market participants to submit a resource into the market with an economic maximum of zero MW’s. The reason this is needed is described below in this example: -Solar Farm X has a set profile that gets submitted into the Day Ahead Market -Market Participant Gomer wants to submit the VER into the market with a self-schedule mirroring the profile of Solar Farm X -Market Participant Gomer can’t do this because they need to submit .1 MW’s during the overnight period when it is obvious that the solar farm will not be generating. Allow Market Participants to submit a Maximum Economic Operating Limit of zero MWs when submitting an Offer for a Variable Energy Resource in the Day-Ahead Market and Real-Time Balancing Market.

Tariff Implications or Changes

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

No

Criteria Impact or Changes

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

No

Working Group Voting Record

MWG

Date of Vote: 11/19/2014 Vote: Approved pending Impact Analysis

Opposed: N/A

Abstained: OMPA

Attachment 17 - MPRR 222 Recommendation Report.docx 12/19/2014 Page 1 of 2

Date of Vote: 12/17/2014 Vote: Unanimously Approved Impact Analysis

RTWG Date of Vote: Vote:

ORWG Date of Vote: Vote:

MOPC Date of Vote: Vote:

Board/Members Committee Date of Vote: Vote:

Date 11/6/2014

Sponsor Name Amber Metzker E-mail Address Amber.L.Metzker@xcelenergy.com Company Xcel Energy Phone Number 1-303-571-6202

Proposed Protocol Language Revision Note: This is an MWG Market software change request that does not require changes to the Protocols or the Tariff. No language change is proposed.

Proposed Tariff Language Revision None Submitted

Proposed Criteria Language Revision N/A

Attachment 17 - MPRR 222 Recommendation Report.docx 12/19/2014 Page 2 of 2

Protocols Revision Request

MPRR No. 218 PRR

Title Market Registration Naming Conventions

Protocol Section(s) Requiring Revision

Section No.: 6; 6.1; 6.2; 6.7 (new); 6.7.1 (new); 6.7.2 (new); 6.7.3 (new); 6.7.4 (new); 6.7.5 (new) 6.7.6 (new); (6.7.7) new Title: Market Registration; Registration of Resources; Registration of Load; Naming Conventions for Market Assets (new); General Requirements (new); Resource Settlement Location Name/Asset Name (new); Load Settlement Location Name/Asset Name (new); Market Hub Settlement Location (new); Tie interface Meter Data Settlement Location (MDSL) Name (new); Source/Sink Name (new); Market and/or Reliability Data Developed and Named by SPP (new) 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

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

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Reason for Revision Implement a consistent naming convention during registration for market assets.

Revision Description

Establish SPP naming conventions to insure that the names for all Market assets meet specific criteria so that 1) the naming structure of Settlement Locations, MDSLs, Source/Sinks, etc. is consistent and 2) the name of assets is easily identifiable in all SPP Reliability and Market models, systems, etc. The naming conventions will only apply to market assets going forward.

Tariff Implications or Changes

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

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 18 - MPRR 218 Market Registration Naming Conventions.docx Page 1 of 8

Date 10/31/2014

Sponsor Name Eddie Watson (Model Coordination) E-mail Address ewatson@spp.org Company Southwest Power Pool Phone Number 501.614.3269

Proposed Protocol Language Revision

6. Market Registration

All Market Participants must register their loads and Resources, excluding Behind the Meter Generation

less than 10 MW, prior to participation in the SPP Integrated Marketplace. Registration is accomplished

by entering the required information via the SPP Market Registration Portal. In addition, each Market

Participant is required to execute the service agreement specified in Tariff Attachment AH. Registration

identifies each load and/or Resource to Asset Owners, associated Market Participants and Settlement

Locations, Meter Agents, and settlement responsibilities.

A Market Participant may represent one or more Asset Owners and may appoint a Designated Agent to

perform its functions under these protocols.

Assets are the registered loads and Resources to an Asset Owner at specific Settlement Locations and

have a designated Meter Agent. Market Participants have the legal relationship with SPP. The Market

Participants may participate in the SPP Integrated Marketplace as any combination of Resource entities,

load serving entities, Meter Agents, and/or power marketers. The Market Participant is also responsible

for insuring that SPP receives Settlement Location data from the Meter Agent in a suitable electronic

format.

Registration data is used for operation and settlement of the SPP Integrated Marketplace, identifying

responsibilities and identifying discrete entities. The registration data is also used in the interaction of

SPP Customer Relations personnel with Market Participants.

Exhibit 6-1 provides an overview of how the registration data is used in developing settlement related

items in the Commercial Model. Please note the diagram does not show all of the Node to Meter

Settlement Location to Meter Data Submittal Location relationships, only a sample subset. Each Meter

Data Submittal Location will have a minimum of a single PNode (Meter Settlement Location) associated

with it and each PNode will have a single Node associated with it.

All Market Assets registered in the Integrated Marketplace must conform to the Naming Convention

requirements described and provided in Section 6.7.

…

Attachment 18 - MPRR 218 Market Registration Naming Conventions.docx Page 2 of 8

6.1 Registration of Resources

Any Market Participant operating Resources within SPP or representing Asset Owners that are not

Market Participants that are operating Resources within SPP must register with SPP via the SPP Market

Registration Portal and be capable of performing the functions of a Resource as described herein.

Resources are registered on a nodal basis to Settlement Locations. Resources at the same physical and

electrically equivalent injection point to the transmission grid may register at the unit or plant level.

Failure or refusal to register a Resource will result in SPP filing an unexecuted version of the service

agreement as specified in Tariff Attachment AH for that Resource with FERC under the name of the

generation interconnection customer under an interconnection agreement with SPP or the applicable TO.

In the case of a Qualifying Facility exercising its rights under PURPA to deliver its net output to its host

utility, such registration will not require the Qualifying Facility to participate in the Integrated

Marketplace or subject the Qualifying Facility to any charges or credits related to the Integrated

Marketplace. The Integrated Marketplace charges and payments associated with the Qualifying Facility

will be handled in accordance with Attachment AE to the SPP Tariff. See Section 6.7.2 for Naming

Convention requirements for Resource Assets registered in the Integrated Marketplace.

6.2 Registration of Load

Any Market Participant with load within SPP must register with SPP via the SPP Market Registration

Portal and be capable of performing the functions of load as described herein. Loads are registered at

Settlement Locations within Settlement Areas. Loads may choose to be registered at a Settlement

Location consisting of either a single Meter Settlement Location (PNode) or multiple Meter Settlement

Locations (APNode). For each load registered, the Asset Owner must specify whether Settlement Meter

Data will be submitted on an hourly basis or on a 5-minte basis. See Section 6.7.3 for Naming

Convention requirements for Load Assets registered in the Integrated Marketplace.

An APNode load Settlement Location is not limited by Settlement Area boundaries.

6.6 TCR/ARR Related Network and Commercial Model Updates

Exhibit 6-4 shows the TCR/ARR Related Model Update Timeline. TCR/ARR related model changes

for existing Market Participants take place as outlined in the table below. New Market Participant

related model changes take place three times per year as indicated in Exhibit 6-3. TCR/ARR related

model additions for new MPs will be implemented as part of the applicable New MP Registration

PRODUCTION Model Updates. Detailed model update timing information for the implementation of

TCR/ARR related model updates for new and existing MPs, new assets, and changes to existing assets is

included in Appendix E.

Modification or termination of a Settlement Location with an active TCR/ARR can only be completed

after the expiration of applicable TCR/ARR. Requests to modify or terminate a Settlement Location

with an active TCR/ARR must follow the timing requirements outlined in Exhibit 6-4.

Attachment 18 - MPRR 218 Market Registration Naming Conventions.docx Page 3 of 8

Exhibit 6-4: TCR Related Model Update Timeline TCR Annual Production Model Effective Date

Reliability only Changes Due

Commercial Changes Due

June 1 February 1st (120 days prior to June 1st)

December 15th (165 days prior to June 1st)*

TCR Monthly Production Model Effective Date

Reliability only Changes Received By

Commercial Changes Received By

July 1 May 15 April 15

August 1 June 15 April 15

September 1 July 15 June 15

October 1 August 15 June 15

November 1 September 15 August 15

December 1 October 15 August 15

January 1 November 15 October 15

February 1 December 15 October 15

March 1 January 15 December 15

April 1 February 15 December 15

May 1 March 15 February 15

*Commercial Model Changes to be included in the TCR Annual Production Model must be included in the February YYYY Model Update with and Effective Date of either February 1st or March 1st. Therefore, the applicable Commercial changes are due to SPP by December 15th of the previous year in order to be included in the February Model Update.

6.7 Naming Conventions for Market Assets

The SPP naming conventions are established to insure that the names for all Market assets meet specific

criteria so that 1) the naming structure of Settlement Locations (SLs), Meter Data Settlement Locations

(MDSLs), Sources and/or Sinks (Source/Sinks), etc. is consistent and 2) the names of assets are easily

identifiable in all SPP Reliability and Market models, systems, etc. The Naming Conventions primarily

address the naming requirements for SLs and MDSLs, Source/Sinks, and other Market/model data for

Market assets registered in the Integrated Marketplace and used in related models and databases.

However, SPP will work to insure that the applicable asset name is consistently used in all pertinent SPP

Model data, i.e. EMS data (equipment data), Commercial Model data (Settlement Location Name),

MOS data (PNODENAME), and other applicable model and system data.

The Settlement Location definition in the SPP Tariff addresses four (4) types of Settlement Locations,

which are: Resource (including pseudo-tied resources), Load (including pseudo-tied loads), Market Hub,

Attachment 18 - MPRR 218 Market Registration Naming Conventions.docx Page 4 of 8

and External Interface. (Note; Tie Interfaces, including the External Interfaces, are registered and

modeled only as Meter Data Settlement Locations instead of as Settlement Locations.) The information

below addresses Naming Conventions developed for naming the four types of Settlement Locations as

well as MDSLs, Source/Sinks, and other Market data.

6.7.1 General Requirements

(1) The names of Settlement Locations (SLs) and Meter Data Settlement Locations (MDSLs) shall

be in all UPPERCASE LETTERS and shall not be more than 25 characters in length.

(2) The names for Sources and/or Sinks should also be in all UPPERCASE LETTERS and shall not

be more than 14 characters in length. Also, each Source and/or Sink that is to be mapped to a

Marketplace Settlement Location must have a unique name.

(3) At least one Meter Data Settlement Location (MDSL) will be registered and related to a

registered asset Settlement Location. The applicable MDSL should have the same name and

format as the registered Asset Resource Settlement Location to which it is associated/related.

Also, a Market Participant may register multiple MDSLs and assign them to one Settlement

Location. For this situation, the name of each additional MDSL should be similar to and/or

reflect the naming aspects of the asset’s registered Settlement Location.

6.7.2 Resource Settlement Location Name/Asset Name

The Resource Asset Name/Settlement Location name shall be consistent with the name used for the

resource in the latest Planning Model data, EIA-411 data, EIA-860 data, and for Source/Sinks. SPP will

work to insure that the applicable Resource name is consistently used in SPP Model data, i.e. EMS

Resource data, Commercial Model data (Settlement Location Name) and MOS data (PNODENAME),

etc. The Resource Settlement Location name shall include appropriate information to uniquely

distinguish the resource from other resources registered in the Marketplace. (For each option below, the

Resource Name and Unit Name may be combined with no period (.) separating them.) See below for

additional information;

(1) Resource Settlement Location for MP of Legacy BAs/Settlement Area – The Settlement

Location name shall include the Settlement Area (SA), Resource Name, and Unit name/ID with

each separated by a Period (.), as applicable. (The Resource Name and Unit Name can be

combined with no period (.) separating them.)

(Example: With Settlement Area for resource being “AAAA”; resource name being “BBBB”;

unit name being “CCCC”; Settlement Location name = AAAA.BBBB.CCCC or

AAAA.BBBBCCCC.)

(2) Resource Settlement Location for a non-Legacy BA/non-Settlement Area MP – The Settlement

Location shall include the Settlement Area (SA), MP or Owner Name/Acronym, Resource

Name, and Unit Name with each separated by a Period (.), as applicable.

Attachment 18 - MPRR 218 Market Registration Naming Conventions.docx Page 5 of 8

(Example: With Settlement Area for resource being “AAAA”; MP/Owner Name being

“MMMM”, resource name being “BBBB”; unit name being “CCCC”; Settlement Location name

= AAAA.MMMM.BBBB.CCCC or AAAA.MMMM.BBBBCCCC.)

6.7.3 Load Settlement Location Name/Asset Name

The Load Asset Name/Settlement Location name shall be consistent with the name used for the load in

the latest Planning Model data and/or other applicable load data as well as for Source/Sinks. SPP will

work to insure that the applicable Load name is consistently used in SPP Model data, i.e. EMS Load

data, Commercial Model data (Settlement Location Name) and MOS data (PNODENAME), etc. The

Load Settlement Location name shall include the appropriate information, based on the type of load

being registered. See below for additional details;

(1) The name of a Legacy BA/Settlement Area MP’s Network Load Settlement Location for loads in

the Legacy BA’s Settlement Area shall include the MP’s Settlement Area (SA) listed twice

separated by an Underscore (_)

(Example: With Legacy BA MP’s Settlement Area for load being “AAAA”; Settlement

Location name = AAAA_AAAA.)

(2) The name of a Legacy BA/Settlement Area MP’s Load Settlement Location for loads in another

Legacy BA’s Settlement Area shall include the MP’s Settlement Area (SA) and the

interconnected adjacent Settlement Area separated by an Underscore (_).

(Example: With Legacy BA MP’s Settlement Area being “AAAA”; Adjacent Settlement Area

with MP’s load being “BBBB”; Settlement Location name = AAAA_BBBB.)

(3) The name of a non-Legacy BA/non-Settlement Area MP’s Load Settlement Location for loads in

a SPP Market Settlement Area shall include Settlement Area, MP or Owner, and “LOAD” or

Name of Load with each separated by an Underscore (_).

(Example: With Settlement Area with MP’s load being “AAAA”; MP name being ”MMMM”,

and load name being “LLLL”; Settlement Location name = AAAA_MMMM_LLLL).

6.7.4 Market Hub Settlement Location

A Market Hub is a Settlement Location representing an aggregation of PNodes as defined by SPP’s

Hubs Establishment process. SPP will determine the Settlement Location name of any approved Market

Hub developed for use in the Marketplace and post the identification of the Market Hub prior to the

proposed effective date. The name of a Market Hub Settlement Location and related Market data will

conform to the appropriate naming convention requirements.

6.7.5 Tie Interface Meter Data Settlement Location (MDSL) Name

SPP requires net measurements on the tie interfaces between each Settlement Area and between the

Settlement Areas and the external BAs with SPP. Each Market Participant responsible for a residual

Attachment 18 - MPRR 218 Market Registration Naming Conventions.docx Page 6 of 8

load of a Settlement Area is required to register an Internal Interface and/or External Interface MDSL(s),

as applicable, to assist in the effort to verify the Tie Interfaces and account for net tie-line flows for that

Settlement Area. The format for each Tie Interface is AREAX.AREAY. See additional details below:

(1) Internal Interface – The Internal Interface/interchange Meter Data Settlement Location name

shall include the registering MP’s responsible Settlement Area name/acronym and the applicable

adjacent interconnected SPP Internal Settlement Area name/acronym separated by a Period (.).

(Example: With the registering MP’s related Settlement Area acronym being “AREA1” and the

adjacent interconnected SPP Internal Settlement Area being “AREA2”; the Internal Interface

MDSL name = AREA1.AREA2). For each AREA1.AREA2 MDSL combination where both

areas are internal Market Settlement Areas, there will also be a corresponding Reciprocal

Internal Interface, AREA2.AREA1. This Reciprocal Internal Interface is registered by the MP

responsible for the adjacent Settlement Area and data for this MDSL must be submitted by the

designated meter agent of the residual load owner of AREA2.)

(2) External Interface - The External Interface Meter Data Settlement Location name shall include

the applicable External Balancing Authority Area name/acronym and the interconnected MP’s

responsible Settlement Location name/acronym, with each separated by a Period (.).

(Example: With External Balancing Authority area being “AREAE” and the interconnected SPP

Internal Settlement Area being “AREAI”; MDSL name = AREAE.AREAI). A reciprocal MDSL

is not required for External Interface MDSLs.)

6.7.6 Source/Sink Name

Each Settlement Location must have at least one Source and/or Sink related/mapped to it, which must be

registered and activated in the NAESB EIR Source/Sink registry. The Source/Sink must be consistent

with the related Settlement Location name as well as with the name used for the asset in the latest

Planning Model data and/or other applicable data. The Source/Sink may also be the same as the related

Settlement Location Name; however, the Source/Sink name must be less than or equal to 14 characters.

The Source/Sink name shall be consistent with or similar to the name used for the resource or load asset

in the latest Planning Model data and/or other applicable database. (Note - In some instances, multiple

PSEs may register different sources and/or sinks that represent or map to the same Settlement Location.)

6.7.7 Market and/or Reliability Data Developed and Named by SPP

SPP will determine and provide the naming of the PNode Name (including aggregate level PNode and

Elemental PNode names), EMS Station Name, and EMS Unit Name for all Market assets (resource,

aggregate load, and bus level loads) registered in the Marketplace by a Market Participant. SPP will

insure that names selected and used for each of these data fields are consistent with the names of the

related Settlement Location, MDSL, Source/Sink etc. registered and used for the assets in the

Marketplace.

Attachment 18 - MPRR 218 Market Registration Naming Conventions.docx Page 7 of 8

7.1 Market System Outage and Error Handling

… Proposed Tariff Language Revision

N/A

Proposed Criteria Language Revision N/A

Attachment 18 - MPRR 218 Market Registration Naming Conventions.docx Page 8 of 8

Protocols Revision Request

MPRR No. 224 PRR

Title Second Round to the SPP TCR Annual Auction

Protocol Section(s) Requiring Revision

Section No.: 5.3 and 5.3.2 Title: Annual TCR Auction Process Protocol Version: 22.a

Impact Analysis Required Yes – If yes, estimated cost: TBD No SPP Staff will complete this section.

Member Software Impact Yes No

Requested Resolution Normal Expedited Urgent Action

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

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Reason for Revision

Inertia Power is making the request to add another round to the annual TCR auction for several reasons:

1) A two round auction leads to better price discovery. 2) A two round auction is more productive for entities attempting to hedge.

Currently, if I am trying to hedge a unit, I only have one opportunity to clear, which means I have to bid high to ensure I can hedge. Therefore, the one round auction incents price insensitive bidding.

3) A two round auction is more in line with other ISO practices. SPP is the only ISO with a one round annual auction.

4) Currently, the software is set up for a two round process. In fact, Staff opens the second round just briefly in order to get the software to run appropriately. Some minor modifications will still have to be made and we will need to allow time for testing.

5) Monthly auctions held from October through May are two round auctions and this would create symmetry between the annual auction and these monthly auctions.

Revision Description Change the language in section 5.4 and 5.4.2 to state that the annual auction is a two round process as opposed to a single round process. Make other conforming changes were a single round annual auction is referenced.

Tariff Implications or Changes

Yes – Section No.: (Include a summary of impact and/or specific changes) Changes would need to be made to Section 7.3 of the tariff to indicate a two round annual TCR auction as opposed to a single round.

No

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 1 of 10

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

Date 11/26/2014

Sponsor

Name Noha Sidhom E-mail Address Noha.sidhom@gmail.com Company Inertia Power III, LLC Phone Number 571-242-0469

Proposed Protocol Language Revision

5.4 Annual TCR Auction

The Annual TCR Auction Process is the mechanism through which Market Participants may

obtain annual TCRs through submission of TCR Bids to purchase TCRs and/or through

conversion of ARRs into TCRs through self-conversion. Various percentages of the SPP

Residual Transmission System Capability, as calculated under Section 5.3.3is made available

during the Annual TCR Auction Process as shown in Exhibit 5-2. TCRs in the annual auction

are auctioned in a single two round process for all months and seasons. TCRs that originated as

LTCRs may be sold during this these single two round process. If there are any changes to the

transmission system topology, Parallel Flow data, or prohibited collocated and electrically

equivalent Settlement Location pairs after the conclusion of Annual ARR Allocation Process,

SPP will post such changes no later than three (3) Business Days prior to the start of the Annual

TCR Auction Process. Exhibit 5-5 provides a representative timeline of the two-round monthly

and single two round annual TCR auction process.

Exhibit 5-1: Annual TCR Auction Processes Timeline

Comment [MPRR138.1]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.2]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MCB3]: MCB: This graph will have to be updated. SPP can work on this graph and update it when the MPRR gets approved.

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 2 of 10

12/15 5/31

1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5

6/1 - 9/30Annual TCR

Auction Awardsby Month

On-Peak and Off-Peak

12/15 - 5/31TCR Auctions

10/1 - 5/31Annual TCR

Auction Awardsby Season

On-Peak and Off-Peak

5/3 - 5/23Annual

TCR Auction

5/3 5/23

5/3 - 5/23Single-Round Annual TCR Auction

5/3 - 5/6MPs submitTCR Bids

5/7 - 5/14

SPP PerformsTCR Auction

The following rules apply to the Annual TCR Auction:

5.4.1 TCR Bid and Offer Submittal

(1) Any Market Participant that has satisfied the applicable credit requirements may

participate in the Annual TCR Auction;

(2) Market Participants holding ARRs may elect to self-convert all or a portion of those

ARRs into TCRs with the same source and sink by specifying the Self-Convert option as

part of the TCR Bid submittal. Directly converted TCRs from LTCRs can be offered for

sale in the Annual TCR Auction.

(3) For each month and season included in the Annual TCR Auction period, Market

Participants may submit TCR Bids and TCR Offers in 0.1 MW increments separately, for

On-Peak and Off-Peak periods (8 separate transmission system models created

representing each month in an annual auction period and on-peak and off-peak periods

within each month and 6 separate transmission system models created representing each

season in an annual auction period and on-peak and off-peak periods within each season).

The following information is submitted for a TCR Bid or a TCR Offer:

(a) Source (any valid Settlement Location);

(b) Sink (any valid Settlement Location);

(c) Class (on-peak or off-peak);

Comment [MPRR138.4]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR171.5]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [MPRR171.6]: MPRR171 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.7]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.8]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.9]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 3 of 10

(d) Period (month or season);

(e) Type (Bid, Self-Convert, Offer);

(f) TCR MW;

(g) TCR Price ($/MW);

(i) TCR Bids and Offers cannot exceed $100,000/MW-Month;

(ii) TCR Bids and Offers cannot be less than ($100,000/MW-Month).

(4) For each TCR Round, a Market Participant is limited to a maximum combined submittal

of 2000 TCR Bids and/or TCR Offers for each Asset Owner it represents.

(5) Market Participants may not submit offers to buy TCRs between Settlement Locations

that are collocated and electrically equivalent.

5.4.2 Annual TCR Auction Process

TCRs are auctioned in a singletwo-round process for each month and season using the SPP

Residual Transmission System Capability as defined under Section 5.3.3 as follows:

(1) Round 1 - 100% of the SPP Residual Transmission System Capability is made available

for the month of June, 90% of the SPP Residual Transmission System Capability is made

available for the July-September period and 60% of the SPP Residual Transmission

System Capability is made available for the Fall, Winter and Spring seasons;

(a) TCR Bids of the Self-Convert Type may be submitted for each source to sink pair

that the Market Participant desires to convert the associated ARRs into TCRs.

The Self-Convert Type option will convert ARRs associated with the specified

source to sink pair into the TCR MW specified subject to simultaneous feasibility.

(b) Only Eligible Entities holding ARRs may submit a Self-Convert TCR Bid.

(c) All awarded ARRs from section 5.3.3(1)(c) that resulted from GFA Carve Outs

will be automatically submitted to the TCR auction as self-convert TCR Bids.

(d) The Self-Convert TCR Bid must specify the same source and sink as the

associated ARR and the TCR MW must be less than or equal to the associated

ARR MW.

(2) Round 2 - The same model and the same percentages of the SPP Residual Transmission

System Capability as described above in (1) will be used in Round 2;

(a) Any remaining ARRs may be submitted in this round. TCR Bids of the remaining

Self-Convert Type may be submitted for each source to sink pair that the Market

Participant desires to convert the associated ARRs into TCRs. The Self-Convert

Comment [MPRR138.10]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.11]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.12]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.13]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 4 of 10

Type option will convert ARRs associated with the specified source to sink pair

into the TCR MW specified subject to simultaneous feasibility.

(b) Only Eligible Entities holding ARRs may submit a Self-Convert TCR Bid.

(c) All awarded ARRs from section 5.3.3(1)(c) that resulted from GFA Carve Outs

will be automatically submitted to the TCR auction as self-convert TCR Bids.

(d) The Self-Convert TCR Bid must specify the same source and sink as the

associated ARR and the TCR MW must be less than or equal to the associated

ARR MW

(e) Any TCRs awarded in Round 1 of the Annual TCR Auction, including Self-

Converted TCRs, may be offered for sale.

5.4.3 Annual TCR Auction Clearing and Simultaneous Feasibility

The Auction is performed using a Linear Program algorithm with an objective function to

maximize the total TCR auction value while ensuring that the cleared TCRs are also

simultaneously feasible.

(1) The SFT is performed as described under Section 5.3.3 with TCR Bid MW modeled as

an injection at the source and a corresponding withdrawal at the sink and TCR Offer MW

modeled as an injection at the sink and a withdrawal at the source.

(2) The SPP Transmission System topology and Parallel Flow assumptions used in the SFT

are normally the same as used in the Annual ARR Allocation process. However,

unforeseen events that drastically impact transmission system topology that occur

following the ARR Allocation but prior to the Annual TCR Auction will be accounted for

in the models for the Annual TCR Auctions.

5.4.4 Annual TCR Awards

Simultaneously feasible TCRs are awarded based upon the TCR Bid prices such that the total

TCR auction value is maximized. Self-Converted TCRs are evaluated simultaneously with

submitted TCR Bids and Offers. In the event there is a tie during the SFT, the competing bids

and offers will be awarded pro rata based on their impact(s) to the constraint(s). Auction

Clearing Prices (ACP) are calculated for each Settlement Location using the formula for the

Marginal Congestion Component as described under Section 4.5.4.1.2 (MCCi = - ( ∑=

K

k 1

Sensik *

SPk )).

Comment [MPRR138.14]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.15]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.16]: MPRR138 Awaiting FERC Approval. #ER14-2553

Comment [MPRR138.17]: MPRR138 Awaiting FERC Approval. #ER14-2553

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 5 of 10

For example, if we assume a 3 bus system (Bus A, B and C) and Bus A is the Reference Bus, we

can calculate the ACP at Bus B as follows:

Transmission Line B-C is at its limit with a Shadow Price = $40/MW

Transmission Line A-C is at its limit with a Shadow Price = $30/MW

Transmission Line A-B is not at its limit (Shadow Price = $0/MW)

Shift Factor for Bus B on Line B-C is 30%

Shift Factor for Bus B on Line A-C is -80%

Then ACP at Bus B is equal to - [($40/MW * .3) + ($30/MW * (-.8))] = $12/MW

A similar calculation is performed for Bus C based on Bus C Shift Factors. The ACP at Bus A is

equal to zero since Bus A is the Reference Bus.

Proposed Tariff Language Revision

Attachment AE

7.4 Annual Transmission Congestion Right Auction

Market Participants may obtain TCRs by purchasing them in the annual TCR

auction or through conversion of ARRs into TCRs. The percentages of the Transmission

System capability made available during the annual TCR auction are listed in Table 7-1

in Section 7.4.2 of this Attachment AE. TCRs in the annual auction are auctioned in a

single two round process for all months and seasons. If there are any changes to the

transmission system topology or Parallel Flow data after the conclusion of Annual ARR

Allocation Process, the Transmission Provider will post such changes no later than three

(3) Business Days prior to the start of the Annual TCR Auction Process.

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 6 of 10

7.4.1 Transmission Congestion Right Offer and Bid Submittal

(1) Market Participants that have satisfied the applicable credit requirements may

participate in the annual TCR auction.

(2) Market Participants holding ARRs associated with a specific source and sink may

elect to self-convert all or a portion of those ARRs into TCRs by specifying the

self-convert option as part of the TCR Bid submittal.

(3) For each month and season included in the annual TCR auction, Market

Participants may submit TCR Bids and/or Offers in 0.1 MW increments, for On-

Peak and Off-Peak periods. A valid TCR Bid and/or Offer must contain the

following information:

(a) Source: any valid Settlement Location;

(b) Sink: any valid Settlement Location;

(c) Class: On-Peak or Off-Peak;

(d) Period: specific month or season;

(e) Type: Bid, Offer or self-convert;

(f) TCR MW; and

(g) TCR Price;

(i) TCR Bids and Offers cannot exceed $100,000/MW-Month;

(ii) TCR Bids and Offers cannot be less than negative $100,000/MW-

Month;

(4) For each TCR round, a Market Participant is limited to a maximum of 2,000 TCR

Bids and/or Offers for each Asset Owner it represents. Market Participants may

not submit offers to buy TCRs between Settlement Locations that are collocated

and electrically equivalent.

7.4.2 Annual Transmission Congestion Right Auction

In the annual TCR auction, TCRs are made available in a single two round for

each month and season as follows:

(1) Round 1 - For the month of June, one hundred percent (100%) of the

Transmission System capability is made available, for the July-September period

ninety percent (90%) is made available, and for the Fall, Winter and Spring

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 7 of 10

seasons sixty percent (60%) is made available. For additional details see Table 7-

1;

(a) Only Eligible Entities holding ARRs may submit a self-convert TCR Bid.

(b) The self-convert TCR MWs are evaluated simultaneously with TCR Bids

and Offers and are subject to reductions that may result from the

Simultaneous Feasibility Test.

(c) The self-convert TCR Bid or Offer must specify the same source and sink

as the associated ARR and the TCR MW must be less than or equal to the

associated ARR MW.

(d) The self-convert type option will convert ARRs associated with the

specified source to sink pair into the TCR MW specified subject to

simultaneous feasibility.

(2) Round 2 - The same model and the same percentages of the SPP Residual

Transmission System Capability as described above in (1) will be used in Round

2;

(a) Any remaining ARRs may be submitted in this round. TCR Bids of the remaining

Self-Convert Type may be submitted for each source to sink pair that the Market

Participant desires to convert the associated ARRs into TCRs. The Self-Convert

Type option will convert ARRs associated with the specified source to sink pair

into the TCR MW specified subject to simultaneous feasibility.

(b) Only Eligible Entities holding ARRs may submit a Self-Convert TCR Bid.

(c) All awarded ARRs from section 5.3.3(1)(c) that resulted from GFA Carve Outs

will be automatically submitted to the TCR auction as self-convert TCR Bids.

(d) The Self-Convert TCR Bid must specify the same source and sink as the

associated ARR and the TCR MW must be less than or equal to the associated

ARR MW

(e) Any TCRs awarded in Round 1 of the Annual TCR Auction, including Self-

Converted TCRs, may be offered for sale.

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 8 of 10

Table 7-1: TCR Auction Summary

______________________

1 October and November

2 December, January, February, March

3 April and May

Auction Month

Auction Type

TCR Award Periods TCR

Products

Auction

Rounds

Total Auctions

May Annual (System Capability %)

Jun (100)

Jul (90)

Aug (90)

Sep (90)

Fall1 (60)

Winter2 (60)

Spring3 (60)

On-Peak/

Off-Peak

1

14

Jun Monthly (System Capability %)

Jul (100)

On-Peak/

Off-Peak

1 2

Jul Monthly (System Capability %)

Aug (100)

On-Peak/

Off-Peak

1 2

Aug Monthly (System Capability %)

Sep (100)

On-Peak/

Off P k

1 2

Sep Monthly (System Capability %)

Oct (100)

On-Peak/

Off-Peak

2 4

Oct Monthly (System Capability %)

Nov (100)

On-Peak/

Off-Peak

2 4

Nov Monthly (System Capability %)

Dec (100)

On-Peak/

Off-Peak

2 4

Dec Monthly (System Capability %)

Jan (100)

On-Peak/

Off-Peak

2 4

Jan Monthly (System Capability %)

Feb (100)

On-Peak/

Off-Peak

2 4

Feb Monthly (System Capability %)

Mar (100)

On-Peak/

Off-Peak

2 4

Mar Monthly (System Capability %)

Apr (100)

On-Peak/

Off-Peak

2 4

Apr Monthly (System Capability %)

May (100)

On-Peak/

Off-Peak

2 4

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 9 of 10

7.4.3 Annual Transmission Congestion Right Auction Clearing and Simultaneous Feasibility

The auction is performed with an objective of maximizing the total TCR auction value

while ensuring that the cleared TCRs are also simultaneously feasible. A Simultaneous

Feasibility Test is performed in each round.

The Simultaneous Feasibility Test is performed using the most up to date Network Model

including planned transmission outages for the corresponding ARR allocation period. For the

Simultaneous Feasibility Test:

(1) TCR submittals of both the self-convert type and Bid type are modeled as a

generation injection at the source and a corresponding load withdrawal at the sink.

(2) TCR submittals of the Offer type are modeled as a generation injection at the sink

and a corresponding load withdrawal at the source; and

(3) Directly converted TCRs from LTCRs are modeled as fixed injections and

withdrawals.

7.4.4 Annual Transmission Congestion Right Awards

Simultaneously feasible TCRs are awarded based upon the TCR Bid prices such that the

total TCR auction value is maximized. Self-converted TCRs are evaluated concurrently with all

other submitted TCR Bids and are given the highest priority subject to simultaneous feasibility.

In the event there is a tie during the Simultaneous Feasibility Test, each competing TCR Bid and

Offer will be awarded a TCR on a pro rata share based on the individual impact on the

constraint. ACPs are calculated based on the shift factor for a specific bus to the Reference Bus

with the corresponding Shadow Price for such bus, for each Settlement Location using the

formula for the MCC as described in Section 8.3.1.2 of this Attachment AE.

Proposed Criteria Language Revision N/A

Attachment 19 - MPRR 224 Second Round to the SPP TCR Annual Auction.docx Page 10 of 10

Inertia Power III, LLC

PROTOCOL REVISION REQUEST

DECEMBER MWG

MPRR NO. 224

Proposal This protocol revision requests the addition of another round to the annual TCR Auction.

Currently, Section 5.3 of the Protocols and 7.3 of the SPP tariff calls for a single round annual TCR auction.

This protocol revision requests that the annual TCR auction be a two round annual auction.

Reasons for the Enhancement:

Reason 1: Price Discovery

A two round auction leads to better price discovery.

We have seen evidence of this in the two round monthly auctions, as some market participants will not bid their entire portfolio or won’t bid at all in the first round. A two round auction allows market participants to get an idea of the market circumstances, in the first round, and adjust bidding behavior accordingly for the second round.

Reason 2: More Effective Hedging

Currently, an entity hoping to hedge its physical exposure using a CRR, has only one opportunity to clear its hedging transaction in the annual auction.

This results in the hedging entity bidding a higher price to clear the transaction to ensure it has a hedge, as opposed to placing an economically sensitive bid, knowing it can increase its price in the second round.

Therefore, having a one round auction forces hedgers to pay more for the path and bid price insensitively, sending inefficient economic signals to the market.

Reason 3: A Two Round Auction Is In Line With Other ISO Practices

Every other ISO has multiple rounds for its annual auction.

For example, PJM has a four round annual auction, releasing 25% of the feasible FTR capability in each round.

MISO has a three round annual auction.

Both MISO and PJM have indicated multiple rounds are better for hedging purposes and price discovery.

Recent trends have all gone towards more rounds, not less.

Reason 4: Software Capability Already In Place

Currently, the SPP software is set up for a two round process. However, some minor modifications and testing will have to be conducted.

Therefore, minimal changes would be required to transition from a one round annual TCR auction to a two round annual TCR auction.

Monthly auctions, in SPP, held from October through May are two round auctions.

Contact Information

For questions or concerns regarding this proposal, please feel free to call or email me at the information below:

Email address: noha@inertiaispower.com

Phone: 571-242-0469

PRR Recommendation Report

MPRR No. 225 PRR

Title Ramp Reservation Requirements Change

Timeline Normal Expedited Urgent Action

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

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Rating-Ranking Rating – Ranking Rating: 1 – FERC Compliance 2 – Defect

– 3 – Member Request 4 – Other

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

SPP Staff will complete this section. Member Software Impact Yes No

Protocol Section(s) Requiring Revision

Section No.: 4.2.5 Title: Ramp Reservation Requirements Protocol Version: 22.a

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description

The BPWG has recently reviewed section 4.2.5 bullets 3 and 4 of the Marketplace Protocols to determine if the statements accurately represent actions that can be taken if a customer is unable to get approved scheduled Interchange transactions based upon available Ramp. Bullet 3 – states: “Market Participants may be required to shift their schedule requests….” SPP OASIS and Scheduling systems do not currently allow a customer to “shift” a scheduled transaction without purchasing additional transmission service. The BPWG will review the systems and see if there is a change to the system requirements that could accommodate this protocol language. It is also to be noted that if the change was made it would only be allowed for non-DC tie scheduled transactions. BPWG requests that the current Bullet 3 be deleted from the Market Protocols until such time that the any decisions could be implemented that would make this language feasible. Bullet 4 – states: “If a Market Participant choose to fix their Ramp violation by extending the duration of the transaction, they do not have to purchase additional transmission….” SPP OASIS and Scheduling systems do not currently allow a customer to “extend” a scheduled transaction without purchasing additional transmission service. The BPWG will review the systems and see if there is a change to the system requirements that could accommodate this protocol language. It is also to be noted that if the change was made it would only be allowed for non-DC tie scheduled transactions. BPWG requests that the current Bullet 4 be deleted from the Market Protocols until such time that the any decisions could be implemented that would make this language feasible.

Tariff Implications or Changes

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

No

Attachment 21 - MPRR 225 Recommendation Report.docx 12/19/2014 Page 1 of 3

Criteria Impact or Changes

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

No

MWG Review PRR Recommendation

Date of Vote: 12/17/2014 Vote: Unanimously Approved

Opposed: N/A

Abstained: N/A

RTWG Review Date of Vote: Vote:

ORWG Review Date of Vote: Vote:

MOPC Recommendation Date of Vote: Vote:

Board Review Date of Vote: Vote:

Date 11/26/2014

Sponsor Name Shari Brown, Mgr. Tariff & Interchange, on behalf of BPWG E-mail Address sbrown@spp.org Company Southwest Power Pool Phone Number 501.614.3236

Proposed Protocol Language Revision

4.2.5 Ramp Reservation Requirements

SPP uses a ramp reservation system to limit schedule changes to an amount equal to or less than the

available ramp capability. The ramp reservation system allows SPP to ensure that sufficient ramp is

available before the schedules created under Sections 4.2.2.7 and 4.2.3.3 are approved. SPP determines

a limit for the net amount of schedule change into or out of the SPP BA for any 10 minute period based

on projected available ramping capability and updates these limits on an ongoing basis. SPP will not

approve schedules that violate this limit.

Market Participants may optionally submit requests to reserve ramping capability. A ramp reservation

can be made to “hold” ramp room while Market Participants complete their scheduling responsibilities.

Ramp reservations are then associated on the Tag when the Market Participant submits the schedule.

The ramp reservation is validated against the submitted Tag to ensure the energy profile and path

matches. If a Market Participant does not submit a specific request, the ramp reservation system will

automatically generate a ramp reservation when the schedule is submitted, if there is sufficient ramp

capability available. The follow business rules apply to submittal and approval of ramp reservation

requests. Additional detail regarding ramp reservations can be found in the Interchange Scheduling

Reference Manual.

(1) There are two time periods during which Market Participants can submit requests to reserve

ramping capability:

Attachment 21 - MPRR 225 Recommendation Report.docx 12/19/2014 Page 2 of 3

(a) Up to 1100 hours on the day prior to the Operating Day in order to reserve ramping

capability for import or export transactions that clear in the DA Market. Any unused

reserved ramping capability is made available for use in import and/or export scheduling

in the RTBM for the Operating Day.

(b) Beginning at 1100 hours on the day prior to the Operating Day, ramp reservation requests

may be submitted for import and/or export scheduling in the RTBM for the Operating

Day, up to 30 minutes prior to the Operating Hour.

(2) Market Participant ramp reservation requests are evaluated and granted on a first come, first

served basis;

(3) Market Participants may be required to shift their schedule requests in order to get their ramp

reservation requests approved. If the Market Participant shifts their schedule up to one hour in

either direction, they are not required to purchase additional transmission;

(4) If a Market Participant chooses to fix their ramp violation by extending the duration of the

transaction, they do not have to purchase additional transmission if the total MWh capacity of the

transmission request is not exceeded;

(5)(3) Market Participants may submit one or more schedules associated with one or more

approved ramp reservations, such that the sum of the submitted schedule MWhs do not exceed

the MWhs of approved ramp on that path. Any approved ramp reservations for a path in excess

of the associated schedules is released for use in the RUC processes and RTBM;

(6)(4) SPP updates available ramping capability on a five (5) minute basis.

Proposed Tariff Language Revision

N/A

Proposed Criteria Language Revision N/A

Attachment 21 - MPRR 225 Recommendation Report.docx 12/19/2014 Page 3 of 3

Protocols Revision Request

MPRR 226 PRR Title Settlement Area Definition Change

Timeline Normal Expedited Urgent Action

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

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Rating-Ranking Rating – Ranking Rating: 1 – FERC Compliance 2 – Defect

– 3 – Member Request 4 – Other

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

SPP Staff will complete this section. Member Software Impact Yes No

Protocol Section(s) Requiring Revision

Section No.: 1; 4.1.2; 4.1.2.1; 4.1.2.1.1; 4.1.2.1.2; 4.1.2.1.3; 4.1.2.1.4; 4.1.2.1.6 Title: Glossary; Forecasting; Short Term and Mid-Term Load Forecasting; Conforming Load; Non-conforming Load; Losses; Demand Response Adjustments; Load Distribution Protocol Version: 22.a

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description

Currently, Settlement Areas and the legacy BA Areas (known as SPP BA Participant Area under Attachment AN to the Tariff) map 1 to 1 between the physical EMS model and the Commercial Model. Recent requests from MPs desiring to become their own Settlement Areas require SPP to update the physical model such that multiple Settlement Areas can exist within a single SPP BA Participant Area so that actual Settlement Area losses can be calculated correctly for use in Settlement. These changes will require a change in the use of the Settlement Area term in load forecasting and local MWP cost allocation. For the Protocols, the proposed changes are clarifying that load forecasting will still be done at the SPP BA Participant Area level; however, the calculation of transmission losses for the top down load will be at a more granular level (i.e., Settlement Area) within a SPP BA Participant Area. For the Tariff, the proposed changes are necessary to disassociate the definition of Settlement Area to be the functional equivalent of a SPP BA Participant Area which will allow entities embedded within a SPP BA Participant Area to become its own Settlement Area for purposes of calculating transmission losses for the top down load.

Tariff Implications or Changes

Yes – Section No.: (Include a summary of impact and/or specific changes) Attachment AE Section 1.1 Definitions and Section 8.6.7 Reliability Unit Commitment Make Whole Payment Distribution Amount

No

Criteria Impact or Changes

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

No

Attachment 22 - MPRR 226 Recommendation Report.docx 12/17/2014 Page 1 of 8

MWG Review PRR Recommendation

Date of Vote: 12/16/2014 Vote: Unanimously approved as modified

Opposed: N/A

Abstained: N/A

RTWG Review Date of Vote: Vote:

ORWG Review Date of Vote: Vote:

MOPC Recommendation Date of Vote: Vote:

Board Review Date of Vote: Vote:

Date 12/8/2014

Sponsor Name Micha Bailey E-mail Address mcbaily@spp.org Company Southwest Power Pool Phone Number 501.688.2522

Comments Received Comment Author Jared Greenwalt on behalf of MWG Date 12/16/2014

Comment Description MWG deleted “BA” in SPP BA Forecast Area to avoid confusion with the entire SPP BA. The phrase “within the geographic area” was removed as redundant in the definition of Settlement Area in the Tariff.

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

Proposed Protocol Language Revision

1. Glossary

Mid-Term Load Forecast

A Settlement Area Load load forecast developed by SPP on a rolling hourly basis for the next

seven days for input into Reliability Unit Commitment.

Short-Term Load Forecast

A Settlement Area Load load forecast developed by SPP on a rolling 5-minute basis for the next

120 Dispatch Intervals for input into the Real-Time Balancing Market.

SPP Forecast Area

A geographic area within the SPP BA defined by SPP based upon historical operating experience

for the purposes of developing load forecasts.

4.1.2 Forecasting

4.1.2.1 Short Term and Mid-Term Load Forecasting

SPP develops Short-Term Load Forecasts and Mid-Term Load Forecasts for each SPP Forecast

Settlement Area. The Short-Term Load Forecast produces values on a rolling 5-minute basis for input

Attachment 22 - MPRR 226 Recommendation Report.docx 12/17/2014 Page 2 of 8

into the RTBM. The Mid-Term Load Forecast produces hourly values for the next hour through seven

(7) days and is used in all of the RUC processes. Load forecasts are derived through a combination of

conforming load and non-conforming load forecasts for each SPP ForecastSettlement Area as described

under Sections 4.1.2.1.1 and 4.1.2.1.2. The SPP ForecastSettlement Area short-term and mid-term

forecasts are then summed up to SPP Balancing Authority Area short-term and mid-term forecasts.

These forecasts include an estimate of losses that must be removed, as described under Section 4.1.2.1.3,

prior to execution of the Market applications in order for the dispatch to reflect losses appropriately

under the marginal losses approach. Once the estimated losses have been removed, both the Mid-Term

Load Forecast and the Short-Term Load Forecast is distributed to the PNode level for modeling

purposes for use in the RUC and RTBM processes respectively as described under Section 4.1.2.1.6.

The DA Market relies on bid-in demand so these load forecasts are not used in that process.

4.1.2.1.1 Conforming Load

Conforming load is load that changes in a reasonably predictable, uniform ratio that is environmentally

driven (i.e. changes in temperature as) as opposed to process driven (i.e. large industrial or irrigation

processes). SPP uses a load forecasting tool to produce the mid-term and short-term load forecasts for

conforming load within each SPP ForecastSettlement Area. The load forecasting tool use historical

actual conforming load values as well as temperature, wind speed, dew point and any other

environmental variables determined necessary to accurately forecast the conforming load within each

SPP Forecast Settlement Area.

4.1.2.1.2 Non-conforming Load

Non-Conforming Load, as described in Section 6.2.2, is more process driven and needs to be separated

from the load forecast application because it does not follow a predictable pattern. Load associated with

stored energy devices such as pumped storage hydro or compressed air Resources shall be considered a

Non-Conforming Load. Market Participants with registered Non-Conforming Load shall submit hourly

load forecasts of Non-Conforming Load consumption to SPP by 1700 hours Day-Ahead for the

Operating Day and for six (6) days following the Operating Day. Once the initial submission is received

at or before 1700 hours, Market Participants are allowed to submit hourly load forecasts of Non-

Conforming Load after 1700 hours up to thirty minutes before the Operating Hour. Market Participants

are encouraged to submit a forecast of each registered Non-Conforming Load for two (2) hours

following the current interval for each 15-minute interval that the forecast deviates from the hourly

profile. If the 15-minute forecast is unavailable, SPP shall interpolate using the submitted hourly Non-

Conforming Load forecast. Market Participants shall also submit a forecast on a 5-minute rolling 15-

minute ahead basis. The submitted Non-Conforming Load will be added to the conforming load

forecasts to create the total SPP ForecastSettlement Area forecast. Market Participants are required to

submit actual Non-Conforming Load data for each Non-Conforming Load for which metering is

available or estimates of Non-Conforming Load for which metering is not available (submitted forecast

value can be used as actual).

Attachment 22 - MPRR 226 Recommendation Report.docx 12/17/2014 Page 3 of 8

4.1.2.1.3 Losses

Both the short-term and the mid-term load forecasts for each SPP ForecastSettlement Area are originally

calculated including an estimate of losses. To allow for the correct dispatch using a marginal losses

approach, the losses estimates from the original forecasts must be removed before distributing the

forecast load to the loads at the individual PNodes.

For the RTBM, loss estimates are determined based on State Estimator solutions. SPP determines the

SPP ForecastSettlement Area loss percentage for each SPP ForecastSettlement Area by dividing the

solved losses of the SPP ForecastSettlement Area by the total load plus losses of the SPP

ForecastSettlement Area from the most recent valid solution. SPP then multiplies the Short-Term Load

Forecast of the SPP ForecastSettlement Area by (1 – SPP ForecastSettlement Area loss percentage) to

obtain the SPP ForecastSettlement Area load forecast without estimated losses for use in the RTBM

study.

For each RUC execution, SPP estimates the future system operating conditions and a power flow study

is used to determine loss estimates. Using the estimated future system operating conditions, SPP

determines the SPP ForecastSettlement Area loss percentage with an approach similar to the RTBM

approach: for each area, dividing the study solution losses of the SPP ForecastSettlement Area by the

total load plus losses of the SPP ForecastSettlement Area in the solution. SPP then multiplies (1 – SPP

ForecastSettlement Area loss percentage) by the Mid-Term Load Forecast of the SPP

ForecastSettlement Area to obtain the SPP ForecastSettlement Area load forecast without estimated

losses for use in the RUC study.

4.1.2.1.4 Demand Response Adjustments

In developing the Short-Term Load Forecast, SPP will perform a gross-up adjustment in real-time for

deployed Demand Response Resources (DRR) in order to continue to forecast the total load to be served

by the RTBM. SPP will gross-up the SPP ForecastSettlement Area actual real-time load received via

SCADA by adding the real-time DRR output to the SPP ForecastSettlement Area actual load where the

DRR resides. The DRR output, in this case, is the estimated DRR output as calculated pursuant to

Section 4.2.2.4.1.

4.1.2.1.6 Load Distribution

SPP uses historical hourly load consumption patterns at each PNode within each SPP

ForecastSettlement Area, as determined by the State Estimator from a reference day, to allocate the SPP

ForecastSettlement Area Mid-term Load Forecast down to the PNode level within each SPP

ForecastSettlement Area for all RUC processes. The reference day used for each SPP

ForecastSettlement Area will be determined by SPP Operations Staff who are also responsible for load

forecasting. By default the reference day will be the same day of the week seven (7) days prior but SPP

has the discretion to choose a different reference day if more appropriate due to holidays, dramatic

weather pattern changes or other factors as appropriate.

Attachment 22 - MPRR 226 Recommendation Report.docx 12/17/2014 Page 4 of 8

For the DA Market, bid-in demand at each Settlement Location will be distributed using the same

weighting used for the RUC process.

For the RTBM, the Short-term Load Forecast will be distributed to each PNode weighted by the load at

each PNode from the latest State Estimator solution.

Proposed Tariff Language Revision

Attachment AE

1.1 Definitions S

Settlement Area

A geographic area within an the SPP BA Participant Balancing Authority Area, as defined under

Attachment AN to this Tariff, for which transmission interval metering can account for the net area load

within the geographic area where, for the purposes of the local allocation of costs pursuant to Section

8.6.7(B) of Attachment AE of this Tariff, such geographic area is equivalent to an SPP BA Participant

Area, as defined under Attachment AN of this Tariff.

RUC Local Settlement Area

A geographic area equivalent to an SPP BA Participant Area, as defined under Attachment AN to this

Tariff, for purposes of the local allocation of costs pursuant to Section 8.6.7(B) of Attachment AE.

8.6.7 Reliability Unit Commitment Make Whole Payment Distribution Amount

An RTBM system-wide and local charge will be calculated at each Settlement Location

for each Asset Owner for each hour in order to fund the payments made under Section 8.6.5.

The system-wide amount will be determined by multiplying an Asset Owner’s system-wide

distribution volume by a daily system-wide RUC make whole payment rate as described in

Section 8.6.7(A) of this Attachment AE. The local amount for each RUC Local Settlement Area

impacted by a Local Reliability Issue will be determined by multiplying an Asset Owner’s RUC

lLocal Settlement Area distribution volume by a the RUC Local Settlement Area Make Whole

Payment Distribution Ratedaily local Settlement Area RUC make whole payment rate as

described in Section 8.6.7(B) of this Attachment AE.

A. The RUC System-Wide Make Whole Payment Distribution Amount shall be calculated

as follows:

The RUC System-Wide Make Whole Payment Distribution Amount =

Attachment 22 - MPRR 226 Recommendation Report.docx 12/17/2014 Page 5 of 8

[(RUC System-Wide Make Whole Payment Distribution Rate) *

(RUC System-Wide Make Whole Payment Distribution Volume)]

(1) The RUC System-Wide Make Whole Payment Distribution Rate is the sum of all

make whole payments for the Operating Day as calculated under Section 8.6.5

excluding make whole payments made to Resources committed to address a Local

Reliability Issue by the Transmission Provider at the request of a local

transmission operator or committed by a local transmission operator to address a

Local Emergency Condition, divided by the sum of Asset Owners’ RUC System-

Wide Make Whole Payment Distribution Volumes for all Settlement Locations

for the entire Operating Day.

(2) An Asset Owner’s RUC System-Wide Make Whole Payment Distribution

Volume at a Settlement Location for an hour is equal to the sum of following

values that are calculated for each Dispatch Interval within the hour:

(a) The absolute value of the sum of actual Real-Time Settlement Location

deviations from Day-Ahead Market cleared amounts for load, virtual offer

transactions and interchange transactions except that, during any Dispatch

Interval in which the Transmission Provider has declared an Emergency

Condition due to a capacity shortage, Real-Time actual load deviations

from Day-Ahead Market cleared amounts shall be limited to deviations

associated with actual Real-Time load in excess of amounts cleared in the

Day-Ahead Market;

(b) For Resources cleared in the Day-Ahead Market, (a) the positive

difference between the RTBM Resource applicable minimum limits and

Day-Ahead Market Resource cleared Energy quantity; or (b) if the

Resource has cleared regulation in the RTBM and has not cleared

regulation in the Day-Ahead Market, the positive difference between (1)

the RTBM Resource regulation minimum limit and (2) the greater of the

Day-Ahead Market Resource cleared Energy quantity or the Resource’s

Day-Ahead Market regulation minimum limit, provided that:

(i) The applicable RTBM Resource minimum limit is greater than the

comparable Day-Ahead Market Resource minimum limit by more

than the Resource’s Operating Tolerance; and

Attachment 22 - MPRR 226 Recommendation Report.docx 12/17/2014 Page 6 of 8

(ii) The applicable RTBM Resource minimum limit is greater than the

Day-Ahead Market cleared Energy amount; and

(iii) The Resource received a Dispatch Instruction less than or equal to

the RTBM applicable minimum limit for at least one Dispatch

Interval in the hour.

(c) For Resources cleared in the Day-Ahead Market, (a) the positive

difference between the Resource Day-Ahead Market cleared Energy

quantity and the RTBM Resource applicable maximum limit or (b) if the

Resource has cleared regulation in the RTBM and has not cleared

regulation in the Day-Ahead Market, the positive difference between (1)

the lesser of the Resource’s RTBM regulation maximum limit or the

Resource’s Day-Ahead Market Resource cleared Energy quantity and (2)

the Resource’s RTBM regulation maximum limit, provided that:

(i) The applicable RTBM Resource maximum limit is less than the

comparable Resource maximum limit submitted for use in the

Day-Ahead Market by more than the Resource’s Operating

Tolerance; and

(ii) The applicable RTBM Resource maximum limit is less than the

Day-Ahead Market cleared Energy amount; and

(iii) The Resource received a Dispatch Instruction greater than or equal

to the RTBM applicable maximum limit for at least one Dispatch

Interval in the hour.

(d) For Resources cleared in the Day-Ahead Market, the Resource’s Day-

Ahead Market cleared amount if that Resource is off-line in the RTBM

and if the Resource has not been de-committed by the Transmission

Provider;

(e) For Resources that cleared in the Day-Ahead Market that are not able to

follow Dispatch Instructions, the absolute value of the difference between

a Resource’s actual output and the Resource’s economic operating point.

The Resource’s economic operating point is calculated as described under

Section 8.6.5(4)(d);

(f) For Resources that were not offered in the Day-Ahead Market and that

self-committed following the close of the Day-Ahead Market, and for

Attachment 22 - MPRR 226 Recommendation Report.docx 12/17/2014 Page 7 of 8

Resources that were offered and not cleared in the Day-Ahead Market and

that self-committed following the close of the Day-Ahead RUC, the actual

Resource output if the Resource received a Dispatch Instruction less than

or equal to the RTBM applicable minimum limit for at least one Dispatch

Interval in the hour;

(g) A Resource’s economic operating point, as calculated as described under

Section 8.6.5(4)(d), for Resources that were committed following the close

of the Day-Ahead Market if that Resource is off-line in the RTBM and

that Resource was not de-committed by the Transmission Provider; and

(h) The absolute value of a Resource’s URD if that Resource operated outside

of its Operating Tolerance and the Resource has not been exempted from

URD as described under Section 6.4.1.1 of this Attachment AE.

B. RUC Local Settlement Area Make Whole Payment Distribution Amount shall be

calculated as follows:

RUC Local Settlement Area Make Whole Payment Distribution Amount =

[(RUC Local Settlement Area Make Whole Payment Distribution Rate) * (RUC Local

Settlement Area Make Whole Payment Distribution Volume)]

(1) The RUC Local Settlement Area Make Whole Payment Distribution Rate is the

sum of all make whole payments for the Operating Day for a RUC Local

Settlement Area as calculated under Sections 8.6.5 and 8.6.6 of this Attachment

AE for Resources committed by the Transmission Provider at the request of a

local transmission operator or by a local transmission operator to address a Local

Reliability Issue in the RUC Local Settlement Area, divided by the sum of Asset

Owners’ RUC Local Settlement Area Make Whole Payment Distribution

Volumes within the impacted RUC Local Settlement Area for the entire

Operating Day.

(2) An Asset Owner’s RUC Local Settlement Area Make Whole Payment

Distribution Volume for the impacted RUC Local Settlement Area for an hour is

equal to that Asset Owner’s Reported Load in that RUC Local Settlement Area

for that hour.

Proposed Criteria Language Revision N/A

Attachment 22 - MPRR 226 Recommendation Report.docx 12/17/2014 Page 8 of 8

2014 Frequently Constrained Area Study

Dec 15, 2014

Market Monitoring Unit

2014 FCA Study

The SPP Market Monitor is required to reevaluate the Frequently Constrained Areas at least annually; the 2014 Study is complete and a draft report is available.

Stakeholder Process:

Review the results with the MWG;

Submit tariff updates to the RTWG;

Submit the final report the MOPC for review;

Seek BOD Approval

File the tariff changes with FERC

2

Transmission Upgrades

Kansas City FCA

Eastowne Transformer – connects a 161kV system to the 345 kV line from St Joseph to Iatan;

Completed in late spring/early summer of 2013; Upgraded in spring 2014;

Congestion in the Lake Road to Alabama area resolved

3

Transmission Upgrades

Impacting the Northwest Kansas FCA

Tuco to Woodward 345 kV

Hitchland to Woodward 345 kV Double Circuits

Woodward to Thistle 345 kV Double Circuits

Clark County to Thistle 345 kV Double Circuits

Post Rock to Spearville 345 kV

Axtell to Post Rock 345 kV

Woodward to Border 345 kV

4

5

0.00%

5.00%

10.00%

15.00%

20.00%

25.00%

30.00%

35.00%GENTLMREDWIL SHIFT-FACTORS on SELECT RESOURCES

January 2012 - November 2014

6

Top 15 Binding Constraints

* Pivotal Supplier Hours do not reflect the impact analysis

Rank Constraint Name Monitored ElementBinding

Hours

Pivotal

Supplier

Hours*

1 OSGCANBUSDEA Osage Switch to Canyon, 115kV 4808 4726

2 IATSTRSTJHAW Iatan to Stranger Creek, 345 kV 999 348

3 ELKXFRTUCOKU Elk City Xfr, 230/138 795 77

4 WDWFPLWDWTAT Woodward to FPL, 138 kV 793 111

5 TEMP56_19273 Harrington to Randall, 230kV 675 646

6 EASXFREASSTJ Eastowne Xfr, 345/161 628 617

7 IATSTRIATEAT Iatan to Stranger Creek, 345 kV 516 363

8 PENMUN87TCRA Pentagon to Mund, 115kV 498 405

9 NEORIVNEOBLC Neosho to Riverton, 161kV 489 235

10 TEMP06_18995 Smokey Hills to Summit, (AR), 230kV 455 106

11 IATSTRIATSTJ Iatan to Stranger Creek, 345 kV 408 251

12 REDWILLMINGO Redwillow to Mingo, 345kV 369 300

13 VICXFRWAYSTE Victory Hill Xfr, 230/115 304 0

14 GENTLMREDWIL Gentlemen to Redwillow, 345 kV 302 283

15 TEMP47_20353 Montrose to Archie (Active), 161kV 241 2

Top 15 Binding Constraints

Texas Panhandle Highly Congested

OSGCANBUSDEA, HARRANNICAMA

Pivotal Supplier Percentage exceeding 95%

Significant Congestion in the Kansas City Area

IATSTRSTJHAW, IATSTRIATEAT, PENMUN87TCRA, IATSTRIATSTJ

Pivotal Supplier percentages ranging from 35% to 80%

Congestion on EASXFREASSTJ relieved by Eastowne Transformer upgrade in Spring 2014

7

Top 15 Binding Constraints

Significant Congestion in Northwest Kansas

REDWILLMINGO, GENTLMREDWIL each with 300 hours

Pivotal Supplier percentages exceeding 80%

Congestion exceeding 500 hours on ELKXFRTUCOKU

Low Pivotal Supplier Percentages

Congestion exceeding 500 hours on WDWFPLWDWTAT

Low Pivotal Supplier Percentages

8

Top 15 Binding Constraints

Significant Congestion on NEOSHORIVNEOBLC

Binding hours less than 500 hours and no other area constraints with substantial binding hours

9

FCA Candidate Areas

Three Candidates Identified

Kansas City Area

Primary Constraint: IATSTRSTJHAW

Shift-Factor Cut Off: -6.8%

Northwest Kansas

Primary Constraint: REDWILLMINGO

Shift-Factor Cut Off: -6.6%

Texas Panhandle

Primary Constraint: OSGCANBUSDEA

Shift-Factor Cut Off: -5.3%

10

FCA Resource Candidates

Primary Constraint Candidates and Shift-Factor Cut-offs are used to identify the FCA Resource Candidates

11

FCA Candidate

Number of

Resources

Total Capacity

(GW)

Number of

Market

Participant

Kansas City Area 86 9.5 6

Texas Panhandle 39 5.0 4

Northwest Kansas 108 10.4 17

Secondary Constraints

The 70 Percent threshold identified 55 secondary constraints

The following criteria were used to determine if the inclusion as FCA defining constraints is warranted

Electrical proximity to the primary constraint

Temporary constraints with short-term activation periods were not included

Constraints with less than 10 hours of binding hours were not included

12

Secondary Constraints

Kansas City Area – 8 secondary constraints identified by the 70% threshold

All identified constraints are in the Wichita Area; the Wichita area was considered as a candidate area but the results of the congestion and pivotal supplier analysis did not warrant further consideration

All but two of the constraints were created for outages or special studies

The Kansas City Area has no secondary constraints

13

Secondary Constraints

Texas Panhandle – 15 secondary constraints identified by the 70 % threshold

Ten temporary constraints were removed - created for outages or experienced less than 10 hours of congestions during the study period

Two permanent flowgates were removed - experienced less than 10 hours of congestion during the study period (ROOXFRROOOAS, SUNAMOTOLYOA)

Three secondary constraints defined for Texas Panhandle - SPSNORTH_STH, TEMP13_20178 (Bushland to Deaf Smith), HARRANNICAMA/TEMP56_19273

14

Secondary Constraints

Northwestern Kansas – 31 secondary constraints identified by the 70 % threshold

All Texas Panhandle constraints, primary and secondary, were picked up by the 70% threshold;

50% of the Resource Capacity in the Western Kansas FCA Candidate Area is not in the Texas Panhandle FCA Candidate Area and contributes to congestion on the Texas Panhandle primary constraint

Texas Panhandle defining constraints were removed as well as several short-term temporary constraints, leaving GENTLMREDWIL and TEMP02_18982 (Axtell to Postrock) as secondary constraints

15

Impact Analysis

• An FCA Candidate has a significant impact from a pivotal supplier during a 5 minute interval if the total impact (shift-factor x shadow price) from FCA Constraints exceeds the Impact Test threshold

16

Candidate Area Binding Hours Pivotal Supplier Hours $15

Impact Threshold

Kansas City Area 999 79

NW Kansas 678 219

Texas Panhandle 5,234 2,182

Impact Threshold Sensitivity

17

Candidate Area

Total Hours at

$5/MWH

Threshold

Total Hours at

$15/MWH

Threshold

Total Hours at

$25/MWH

Threshold

Kansas City Area 175 79 58

NW Kansas 405 219 84

Texas Panhandle 3,616 2,182 1,254

Comparison with Previous Study

Impact Analysis Comparison

18

Candidate AreaBinding

Hours

Pivotal Supplier Hours

$5 Impact Threshold

Binding

Hours

Pivotal Supplier Hours

$5 Impact Threshold

Kansas City Area 1,105 751 999 175

NW Kansas 1,556 1,463 678 405

Texas Panhandle 2,514 2,489 5,234 3,616

2014 FCA Study2013 FCA Study

Conclusions

Key conclusions from 2014 FCA Study:

The Texas Panhandle area experienced heavy congestion and still has a strong pivotal supplier presence;

The Kansas City area experienced significant congestion but transmission upgrades have reduced the impact of pivotal suppliers in the area;

The NW Kansas area experienced a reduction in both congestion and pivotal supplier impacts.

19

Recommendations

SPP Market Monitor recommendations:

The Texas Panhandle area shall remain a Frequently Constrained Area with a few modifications to the defining constraints and Resource group indicated in the FCA Report;

The Kansas City and the NW Kansas areas no longer require designation as Frequently Constrained Areas;

No other areas in the footprint meet the criteria for designation as an Frequently Constrained Area.

20

S o u t h w e s t P o w e r P o o l

F r e q u e n t l y C o n s t r a i n t A r e a s - 2 0 1 4 S t u d y

December 2014

Southwest Power Pool Market Monitoring & Analysis

Draft Report

Southwest Power Pool, Inc.

Table of Contents

Table of Contents .........................................................................................................................................1

I. Introduction .......................................................................................................................................2

II. Summary & Recommendations ........................................................................................................2

Summary of Results .........................................................................................................................2

Recommendations ...........................................................................................................................6

III. Methodology .....................................................................................................................................8

Data and Study Period .....................................................................................................................8

Study Process ...................................................................................................................................8

Appendix A – Updates to Addendum 1 to Attachment AF ..........................................................................11

Appendix B – Binding & Pivotal Supplier Hours ...........................................................................................13

SPP Frequently Constrained Areas – 2014 Study 1

Southwest Power Pool, Inc.

I. Introduction

Frequently Constraint Areas (FCAs) are areas of the Integrated Marketplace footprint that

experience high levels of congestion and are associated with a dominate or pivotal supplier.

Attachment AF, Section 3.1.1 of the SPP Open Access Transmission Tariff defines Frequently

Constrained Areas as electrical areas with one or more binding transmission constraints or Reserve

Zone constraints that are expected to be binding for at least five-hundred (500) hours during a

given twelve (12)-month period and within which one or more suppliers are pivotal. Prior to the

start of the Integrated Marketplace, Potomac Economics Ltd., under contract with the SPP Market

Monitor, recommended the designation of three Frequently Constrained Areas: (1) the Kansas City

area, (2) the Northwest Kansas area, and (3) the Texas Panhandle area.

The SPP Market Monitor, as required, by Attachment AE, Section 3.1.1.3, has reexamined the FCA

designations to determine if the current designations are still warranted and if any new areas need

to be designated as an FCA. The contents of this report include a summary of the major findings

and recommendations in Section II and a description of the study process in Section 3. Appendix A

consists of the recommended changes to Addendum 1 of Attachment AF and Appendix B is a list of

binding and pivotal supplier hours by constraint.

II. Summary & Recommendations

Summary of Results The initial phase of the study identified three candidates for the FCA designation; the identified

candidates are the same areas they were designated to be Frequently Constrained Areas in the

2013 study. These areas are (1) the Kansas City area, (2) the Northwest Kansas area, and (3) the

Texas Panhandle area. The identification of candidate areas and associated primary constraints is

based on the number of hours the constraints are binding and the number of hours for which the

constraints have a pivotal supplier. Table 1.1 shows each area’s primary constraint, and the shift-

factor cut-off for each area. The primary constraint for each candidate area is the constraint with

the most binding hours and the shift-factor cut-off is used to identify the candidate resources

associated with the candidate FCA. The Kansas City Area and Northwest Kansas areas have

SPP Frequently Constrained Areas – 2014 Study 2

Southwest Power Pool, Inc.

experienced significant changes to the transmission system since the period examined in the 2013

study. The upgrades to the transmission system impacted the selection of a primary constraint in

the Kansas City area and the number of candidate FCA resources. As noted in Table 1.1, there is

only one primary constraint associated with the Kansas City area whereas the 2013 study

designated the Lake Road to Alabama constraint as a primary constraint in addition to the Iatan to

Stranger Creek constraint. Lake Road to Alabama is no longer a significant constraint in the area

due to the Eastowne transformer. The Eastowne transformer connects a 161 kV electrical system

north of Kansas City to the 345 kV line from St. Joseph to Iatan. This upgrade to the transmission

system, completed in the summer of 2013, relieved the congestion on the Lake Road to Alabama

constraint and there were zero hours of congestion on the 161 kV system associated with the Lake

Road to Alabama constraint during the study period for this analysis. The change in the primary

constraint results in a smaller number of FCA resource candidates for the Kansas City Area. The

resource candidate group includes all resources with a shift-factor less than the shift-factor cut-off.

Eighty-six resources were identified in the 2014 study compared with one hundred-twenty in the

2013 study.

The shift-factor cut-off for the Northwest Kansas area changed from −12% in the 2013 study to

−6.6% in the current study. This change can be attributed to upgrades to the transmission system

in the western part of the SPP footprint. Three upgrades that are impacting the area are the

Hitchland to Woodward 345 kV double circuit line, the Axtell to Post Rock 345kV line, and the Post

Table 1.1 - Primary Constraints and Shift-Factor Cut-Offs

Candidate Area Primary Constraint Shift-Factor Cut-Off

Kansas City Area IATSTRSTJHAW -6.8%

NW Kansas REDWILLMINGO -6.6%

Texas Panhandle OSGCANBUSDEA -5.3%

SPP Frequently Constrained Areas – 2014 Study 3

Southwest Power Pool, Inc.

Rock to Spearville 345 kV line. These large volume lines reduce the ability of the pivotal suppliers to

cause congestion and, in the event a pivotal supplier is able to load a constraint, the smaller price

impacts, as reflected by the lower shift-factors, significantly reduce the potential benefits of such

behavior.

The changes to the Kansas City area are also reflected in the determination of each candidate FCA’s

secondary constraints. Secondary constraints are constraints for which the candidate FCA

resources provide at least seventy percent (70%) of the congestion relief. No secondary constraints

were identified for the Kansas City area. Table 1.2 shows the defining constraints for each

candidate FCA.

Table 1.2 – Candidate FCA Defining Constraints

Candidate Area Constraint Type Constraint Name

Kansas City Area Primary IATSTRSTJHAW

NW Kansas

Primary REDWILLMINGO

Secondary GENTLMREDWIL

Secondary TEMP02_18982 (Axtell to Post Rock)

Texas Panhandle

Primary OSGCANBUSDEA

Secondary HARRANNICAMA

Secondary SPSNORTH_STH

Secondary Temp13_20278 (Bushland to Deaf Smith)

SPP Frequently Constrained Areas – 2014 Study 4

Southwest Power Pool, Inc.

No significant changes from the 2013 study are found in the Texas Panhandle candidate FCA. The

primary constraint is the same, the shift-factor cut-off has changed from −6% to −5.3%, the

defining constraint group has not change substantially, and there is a net change of three candidate

resources due to new registrations and de-registrations.

With the candidate FCAs fully defined by the candidate resource group and defining constraints, we

conduct an impact analysis to determine the number of hours each candidate FCA is both binding

and susceptible to the exercise of market power. We record these results in Table 1.3.

To determine the sensitivity of the results to the impact test threshold, we repeated the impact

analysis at the $5/MWh and $25/MWh threshold levels. The results are shown in Table 1.4. The

sensitivity analysis indicates that the choice of impact threshold does not affect the FCA

designation decision. Kansas City and Northwest Kansas fall below the 500 hour level at the three

threshold levels, and the Texas Panhandle exceeds the 500 hour level at all three impact test

threshold levels.

Table 1.3 – Candidate FCA Binding & Pivotal Supplier Hours

Candidate Area Binding Hours Pivotal Supplier Hours $15 Impact Threshold

Kansas City Area 999 79

NW Kansas 678 219

Texas Panhandle 5,234 2,182

SPP Frequently Constrained Areas – 2014 Study 5

Southwest Power Pool, Inc.

Recommendations The results of the analysis clearly show that the Texas Panhandle candidate FCA should remain a

designated FCA. The binding hours and pivotal supplier results in Table 1.3 show that congestion

and market power issues in the area have not been resolved. The pivotal supplier hours with price

impacts easily exceed 500 hours. The Market Monitor recommends the Texas Panhandle area

maintain the designation as an FCA and that the FCA defining constraints and FCA resource lists in

Addendum 1 to Attachment AF be updated to reflect the lists provided in Appendix A of this report.

The conclusions regarding the Kansas City candidate FCA are equally unambiguous; the Kansas City

area does not warrant continued designation as a Frequently Constrained Area. Table 1.3 shows

that there is still significant congestion in the area with binding hours at 999 hours. However, Table

1.4 indicates that the price impacts are in excess of the $5/MWh threshold in 175 hours or 18% of

the binding hours; and in excess of the $15/MWh threshold in 79 hours or 8% of the binding hours.

This is in sharp contrast to the results of the 2013 study where a supplier was pivotal with price

impacts in the Kansas City area in 94% of the binding hours.

The analysis also shows that the Northwest Kansas area does not warrant continued designation as

a Frequently Constrained Area. Table 1.3 shows significant congestion but the number of hours

with price impacts exceeding the impact test threshold does not reach the 500 hour threshold. This

Table 1.4 – Impact Analysis Sensitivity

Candidate Area Total Hours at $5/MWH Threshold

Total Hours at $15/MWH Threshold

Total Hours at $25/MWH Threshold

Kansas City Area 175 79 58

NW Kansas 405 219 84

Texas Panhandle 3,616 2,182 1,254

SPP Frequently Constrained Areas – 2014 Study 6

Southwest Power Pool, Inc.

differs greatly from the 2013 study where the number of hours in the Northwest Kansas area with

price impacts exceeded 2,000 hours.

SPP Frequently Constrained Areas – 2014 Study 7

Southwest Power Pool, Inc.

III. Methodology

Data and Study Period The study period runs from September 1, 2013 through August 31, 2014, and therefore includes

the last six months of the EIS Market and the first six months of the Integrated Marketplace.

Congestion and dispatch data, and resource plans from the EIS Market are used in the analysis for

the period from September 1, 2013 through February 28, 2014. RTBM congestion and dispatch

data and resource parameter offers for online resource are used in the analysis for the period from

March 1, 2014 through August 31, 2014.

Study Process The study consists of the same six step process used in the 2013 study.

1. Binding Hours Computation: The number of binding hours is computed for each modeled

transmission constraint. A constraint is counted as binding in a five minute interval if the

loading on the constraint is within the greater of five megawatts (5 MW) or 2% of the

effective constraint limit.

2. Pivotal Supplier Analysis: The number of pivotal supplier hours is computed for each

modeled transmission constraint. A constraint is counted as having a pivotal supplier during

a five minute interval if the supplier can cause a constraint to exceed the effective

constraint limit by decreasing generation on resources that provide congestion relief and by

increasing generation on resources that contribute to congestion. The re-dispatch of the

potential pivotal supplier’s resources is governed by the submitted ramp rates, and the

economic minimum and maximum capabilities. A thirty minute re-dispatch period is

considered. The ability of the market to react to the actions of the potential pivotal supplier

is accounted for by allowing a similar re-dispatch of all resources not owned or controlled

by the potential pivotal supplier.

3. Selection of FCA candidates: Candidates for designation as a Frequently Constrained Area

are chosen based on the binding hours and pivotal supplier analyses. Constraints that are in

the same electrical proximity and have the same pivotal suppliers are grouped together; if

SPP Frequently Constrained Areas – 2014 Study 8

Southwest Power Pool, Inc.

the aggregate number of binding and pivotal supplier hours is significant, then the area is

selected as a candidate FCA. A primary constraint for the candidate FCA is generally

selected as the constraint with the highest number of binding hours.

4. Identify the candidate FCA Resources: A resource is a candidate FCA resource if its shift-

factor relative to the candidate FCA primary constraint is less than or equal to the candidate

FCA shift-factor cut-off. To determine the shift-factor cut-off we first compute the relief

capability of the largest pivotal supplier on the primary constraint. The shift-factor cut-off is

then set at the shift-factor corresponding to the ninetieth percentile of the relief capability.

In other words, ninety percent (90%) of the largest pivotal supplier’s relief capability has a

shift-factor less than or equal to the candidate FCA shift-factor cut-off.

5. Identify the candidate FCA secondary constraints: A constraint is eligible to be defined as a

secondary constraint for the candidate FCA if the candidate FCA resource group contributes

at least seventy percent (70%) of the total relief capability on the constraint. Additional

considerations for defining a constraint as a secondary constraint consist of (i) electrical

proximity to the primary constraint, (ii) an expectation that the constraint is not a short-

term or temporary constraint, and (iii) an expectation that the constraint will experience

significant congestion in the upcoming year.

6. Impact Analysis: An impact analysis is employed to determine the number of hours for

which the candidate FCA Resource group has significant impacts on prices in the candidate

FCA. For each five minute interval in the study period, the resource price impacts on each

defining constraint are calculated by multiplying the shadow price and the candidate

resource’s corresponding shift-factor. The resource price impacts are then summed over

the candidate FCA defining constraints to obtain a five minute price impact. This calculation

is equivalent to finding the contribution from the candidate FCA defining constraints to the

candidate resource’s marginal congestion component of the LMP.

Any interval for which a candidate resource’s price impact exceeds the impact test

threshold is counted as an interval that is susceptible to the exercise of market power by a

pivotal supplier. The market impact test threshold used in the Marketplace mitigation

system transitioned from $5/MWh to $15/MWh on September 1, 2014, and is expected to

increase to $25/MWh on March 1, 2014. We computed the impact analysis in this study at

SPP Frequently Constrained Areas – 2014 Study 9

Southwest Power Pool, Inc.

threshold levels ranging from $5/MWh to $15/MWh in order to test the sensitivity of the

results to the various impact threshold levels.

SPP Frequently Constrained Areas – 2014 Study 10

Southwest Power Pool, Inc.

Appendix A – Updates to Addendum 1 to Attachment AF

Table 1 – Defining Constraints for the Texas Panhandle Frequently Constrained Area Line #

Constraint Name

1 HARRANNICAMA

2 OSGCANBUSDEA

3 SPSNORTH_STH

4 TEMP13_20178

Table 2 – Units in the Texas Panhandle Frequently Constrained Area

Line #

Resource Name

1 SPSCAPROCKUNWINDFARM

2 SPSCARLSBADUN5

3 SPSCIRRUSUNCIRRUS_WIND

4 SPSCUNNSUBUN1

5 SPSCUNNSUBUN2

6 SPSCUNNSUBUN3

7 SPSCUNNSUBUN4

8 SPSDOLLARHIUNSUNE_SPS1

9 SPSHOBBSPLT1

10 SPSHOBBSPLT2

11 SPSHOPI_SUBUNSUNE_SPS5

12 SPSJONESSUBUN1

13 SPSJONESSUBUN2

14 SPSJONESSUBUN3

15 SPSJONESSUBUN4

16 SPSLEA_ROADUNSUNE_SPS3

17 SPSLOVINGTOPLT1

18 SPSLOVINGTOUNWILDCATWIND

19 SPSLP-COOP2UNLUBBOCK_WIND

20 SPSLP-HOLL2UNCOOKE_GT2

21 SPSLP-HOLL2UNCOOKE_GT3

22 SPSLP-HOLL2UNCOOKE_ST1

23 SPSLP-HOLL2UNCOOKE_ST2 24 SPSMADDOXSUUN1

25 SPSMADDOXSUUN2

SPP Frequently Constrained Areas – 2014 Study 11

Southwest Power Pool, Inc.

Table 2 – Units in the Texas Panhandle Frequently Constrained Area Line # PNODE NAME

26 SPSMONUMENTUNSUNE_SPS4

27 SPSMSTNGPLT1

28 SPSMSTNGUN4

29 SPSMSTNGUN5

30 SPSMSTNGUN6_GSEC

31 SPSPLXSUBUN1

32 SPSPLXSUBUN2

33 SPSPLXSUBUN3

34 SPSPLXSUBUN4

35 SPSQUAYCNTYUNQUAYCOUNTY1

36 SPSSAN_JUANUNWINDFARM

37 SPSS_JALUNSUNE_SPS2

38 SPSTOLKSUBUN1

39 SPSTOLKSUBUN2

SPP Frequently Constrained Areas – 2014 Study 12

Southwest Power Pool, Inc.

Appendix B – Binding & Pivotal Supplier Hours

Rank Constraint Name Monitored Element Binding Hours

Pivotal Supplier Hours1

1 OSGCANBUSDEA Osage Switch to Canyon, 115kV 4808 4726 2 IATSTRSTJHAW Iatan to Stranger Creek, 345 kV 999 348 3 ELKXFRTUCOKU Elk City Xfr, 230/138 795 77 4 WDWFPLWDWTAT Woodward to FPL, 138 kV 793 111 5 TEMP56_19273 Harrington to Randall, 230kV 675 646 6 EASXFREASSTJ Eastowne Xfr, 345/161 628 617 7 IATSTRIATEAT Iatan to Stranger Creek, 345 kV 516 363 8 PENMUN87TCRA Pentagon to Mund, 115kV 498 405 9 NEORIVNEOBLC Neosho to Riverton, 161kV 489 235

10 TEMP06_18995 Smokey Hills to Summit, (AR), 230kV 455 106 11 IATSTRIATSTJ Iatan to Stranger Creek, 345 kV 408 251 12 REDWILLMINGO Redwillow to Mingo, 345kV 369 300 13 VICXFRWAYSTE Victory Hill Xfr, 230/115 304 0 14 GENTLMREDWIL Gentlemen to Redwillow, 345 kV 302 283 15 TEMP47_20353 Montrose to Archie (Active), 161kV 241 2 16 TEMP28_20001 Sundown Xfr, (AR), 230/115 216 199 17 SHAHAYKNOXFR South Hays to Hays, 115 kV 214 94 18 TEMP49_19494 Hale County to Tuco, (AR), 113kV 210 210 19 GGS Gentleman to N. Platte, 230kV 209 101 20 SHAXFRELKXFR Shamrock Xfr, 115/69 201 0

21 SPPSPSTIES

(1) Oklaunion to Tuco, 345 kV; (2) Wheeler to Sweetwater, 230 kV; (3) Finney to Hitchland, 345 kV; (4) Shamrock to McClean, 115 kV; (5) Liberal to Texas Co., 115 kV; (6) Beaver County to Hitchland, 345 kV; (7) Border to Hitchland 345 kV

197 171 22 HAYVINPOSKNO Hays to Vine St, retired 181 37 23 GRAXFRSWEELK Grapevine Xfr, 230/115 156 0 24 TEMP45_19952 Hobbs to Cunningham, (AR), 115kV 153 153 25 POTXFRHITXFR Potter Co. Xfr, 345/230 145 105 26 TEMP14_20121 Gordon Evans to Maize, (AR), 138kV 145 109 27 TEMP38_20360 Sun City to Medicine Lodge, (Active), 115kV 142 3 28 REDARCREDARC Redbud to Acadia, 345kV 135 118 29 TEMP67_20472 Renfrow7-Renfrow WF, (Active) 133 17

1 Pivotal supplier hour values do not reflect the impact analysis

SPP Frequently Constrained Areas – 2014 Study 13

Southwest Power Pool, Inc.

Rank Constraint Name Monitored Element Binding

Hours

Pivotal Supplier

Hours 30 TEMP22_20292 Creswell to Rome, Active, 69kV 127 15 31 TEMP35_19020 Circ Xfr, AR, 230/115 125 24 32 HARRANNICAMA Harrington to Randall, 230kV 119 119 33 TEMP17_19635 Sweetwater to Grand Island, AR, 345kV 118 6 34 TEMP47_19592 Grapevine Xfr - Reversed direction,115/230, AR 114 31 35 TEMP03_19960 Knoll to North Hays, AR, 115kV 110 26 36 HOBXFRHOBLEA Hobbs Xfr, 230/115 106 5 37 TEMP80_19668 Clearwater to Milan, AR 104 1 38 SHAXFRTUCOKU Shamrock Xfr, 115/69 102 13 39 TEMP72_20480 SW Lawrence to Waka, AR, 115kV 99 0 40 TEMP38_19908 Cunningham Xfr, AR 98 98 41 TEMP33_19963 Woodring Xfr, AR, 345/138 98 74 42 TEMP28_19744 Brook LN, XFT2, AR 95 62 43 SUBTEKFTCRAU Substation 1226 to Tekamah, 161kV 87 0 44 TEMP15_20172 Snake Creek to Alliance, AR, 115kV 83 0 45 HOBCARHOBALT Hobart to Carnigie, 138kV 81 10 46 CBLS56ROLMAD Council Bluffs, 345kV 77 15 47 TEMP65_20468 Montrose to Archie , 161kV, AR 69 0 48 TEMP94_20182 Cannaday to Elm Creek, AR, 115kV 63 0 49 TEMP48_20358 Longwood to Oak PH, AR, 138kV 63 62 50 TEMP72_19639 Kelly to Tecumseh, AR, 161kV 61 14 51 TEMP44_20033 Woodring 345 kV - Woodring 138 kV, AR 59 21 52 TEMP38_19163 Muskogee to Pecan1, AR, 345kV 58 44 53 IATXFRIATSTR Iatan Xfr, 345/161 58 48 54 TEMP62_19792 Sub 1211 to Sub 1250, AR, 161kV 58 42 55 TEMP26_19708 SPERVI2 to Mulgre2, AR, 230kV 58 5 56 ELKXFRSWEWHE Elk City Xfr ftlo Sweetwater to Wheeler, 230/138 57 0 57 CATXFRCATXFR Catoosa Xfr 161/138 55 49 58 TEMP16_19634 Cooper to Fairport, 345kV, AR 52 4 59 TEMP04_19602 Gracmont to Anadarko, 138kV, AR 50 19 60 SHAHAYPOSKNO South Hays to Hays, 115 kV 50 9 61 TEMP09_20424 Gordan Evans Xfr, 345/138, Active 49 30 62 TEMP13_20278 Bushland to Deafsmith, 230 kV, Active 48 39 63 ASHCRALYDVAL Ashdown West to Craig Junction, 138kV 48 43 64 ONEBANNESTUL Oneta to Broken Arrow North, 138kV 46 43 64 MILCLEBARSAW Milan Tab to Clearwater, 138kV 46 0 65 TEMP73_20364 Wolf Creek to Bent, 345kV, AR 45 34

SPP Frequently Constrained Areas – 2014 Study 14

Southwest Power Pool, Inc.

Rank Constraint Name Monitored Element Binding

Hours

Pivotal Supplier

Hours

66 SPSNORTH_STH

(1) Bushland to Deafsmith, 230 kV; (2) Potter Co to Newhart 230kV; (3) Osage Switch to Canyon 115kV; (4) Randall Co. to Paloduro 115kV; (5) Amarillo So. To Swisher 230kV 44 36

67 TEMP37_20355 WR Smokey Hill to Summit, 230kV, Active 44 29 68 TEMP79_19669 Beverly Tag to Fort Smith, 161kV, AR 42 0 69 TEMP23_19876 Tulsa North to PP Tap, 138kV, AR 41 26 70 STR87TSTJHAW Stranger Creek to 87th Street, 345kV 41 30 71 TEMP50_20450 Ogalala to Brule 115kV, AR 40 0 72 TEMP18_20151 Yoakum Xfr, 230/115, AR 40 38

SPP Frequently Constrained Areas – 2014 Study 15

December MWG – Marketplace Update

• November operational situations

• Regulation Performance

• Congestion Overview

• RUC Update

• Pricing

• Load Forecast accuracy

– Weather/Load forecast relationship

• Wind forecast accuracy

– November WF Overrides

• DAMKT Update

• Appendix

2

• Roughly 1.8% of the total commitments made in the month of November were actual new manual commitments

• ‘Bridge’ were manual commitments performed by the RUC operator to bridge two existing commitments

• Last few months of New Manual Commitments

Manual Commitments

3

New Commit,

24%

Back End, 67%

Bridge, 5%

Front End, 4%

Month New Manual Commitment

Sep-14 1.890%

Oct-14 1.820%

Nov-14 1.920%

November Manual Commitments

REGULATION PERFORMANCE Section 1

4

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

5

November 2014 Regulation Up Performance

6

0123456789

10111213141516171819202122232425262728293031

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November 2014 System-Wide Regulation Up Performance

Reg Up

November 2014 Regulation Down Performance

7

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November 2014 System-Wide Regulation Down Performance

Reg Down

CONGESTION OVERVIEW Section 2

8

DA vs RT Constraints

• Top 10 Congested Constraints in DA

9

Constraint Intervals Binding/Breached Average Shadow Price TEXAS_CO_TXPS_TXCO_PHSHFT_PS 718 4.42

SUNAMOTOLYOA 508 28.58

OSGCANBUSDEA 327 75.03

TEMP95_20633 211 16.57

TEMP37_20355 175 13.12

TMP127_20536 165 22.21

TEMP12_20560 160 26.90

WDWFPLWDWTAT 157 13.42

TMP144_20608 138 5.19

TEMP66_20599 119 24.61

DA vs RT Constraints

• Top 10 Congested Constraints in RTBM

10

Constraint Intervals Binding/Breached Average Shadow Price OSGCANBUSDEA 4374 122.70

SUNAMOTOLYOA 2930 28.80

TEMP95_20633 1121 28.89

TEMP37_20355 984 23.63

COOPER_S 854 8.64

TEMP66_20599 715 19.15

TMP144_20608 710 6.10

WDWFPLWDWTAT 689 11.06

TMP109_20517 646 2.99

TEMP14_20279 516 2.85

RUC UPDATE Section 3

11

• The commitment breakdown for the month of October is shown to the right of total commitments made by DAMKT, RUC, SELF, and MANUAL.

• 64% of the commitments came from DAMKT, while 8% were considered manual.

Commitment Breakdown – November 2014

12

*SELF commits are post DAMKT

SELF 18%

DAMKT 64%

RUC 10%

MANUAL 8%

DAMKT 17,999,074.70 SELF 527,149.80 RUC 399,374.50 MANUAL 209,832.80

• The 8% of manual commitments shown on the last slide amounts to 582 commitments.

• Of these 582, roughly 107 (20%), 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, about 1.9% of the total commitments made in the month of November were actual new manual commitments

• ‘Bridge’ were manual commitments performed by the RUC operator to bridge two existing commitments

Manual Commitments – November 2014

13

New Commit,

24%

Back End, 67%

Bridge, 5%

Front End, 4%

TYPE MW New Commit 4,589,679.21 Back End 12,851,101.80 Bridge 988,546.29 Front End 706,104.49

NOVEMBER PRICING Section 4

14

15 *=more info for anomalies included on next slide

-35

15

65

115

165

215

265

315

10/31/2014 00:00 11/5/2014 00:00 11/10/2014 00:00 11/15/2014 00:00 11/20/2014 00:00 11/25/2014 00:00 11/30/2014 00:00

Hourly Avg LMP DA LMP RT LMP

16

RT LMP Outliers • Highest LMPs

– 11/8/2014 17:00 $199.67 High winds contributed to two flowgates in the SPS area breaching during this

hour causing large SMP spikes. One of the limits was relaxed by the operator that eventually helped the market solution and lowered violation costs on the system.

– 11/16/2014 17:00 $223.11

With a combination of under-forecasting load and over-forecasting wind (from a DA perspective) by the same amount caused us to be OR short and caused high SMP prices between $200-$1000. 9 flowgates were breaching throughout the day.

– 11/17/2014 17:00 $294.22

9 flowgates were breaching throughout the day and had 2 intervals 17:45 and 17:50 where SMP prices were $1392 and $1667 respectively. Studies were run at SPP and constraints had no impact. Load ramped up quickly (2500 MW that hour) and wind dropped causing us to go OR short. 1000 MW were RUCed on.

– 11/25/2014 06:00 $205.14

SMP spikes were due to REGUP shortage because of ramp shortage and not capacity. For the 6:35 and 6:40 intervals the next MW was taken from the demand curve setting the shadow price to $600 forcing high SMP spikes.

17

Day Ahead 14-Mar 14-Apr 14-May 14-Jun 14-Jul 14-Aug 14-Sep 14-Oct 14-Nov DA MEC $ 39.75 $ 39.24 $ 37.13 $ 33.14 $ 32.71 $ 34.18 $ 30.15 $ 31.79 $ 32.67 DA MLC $ (0.15) $ (0.16) $ (0.13) $ (0.15) $ (0.08) $ (0.08) $ (0.17) $ (0.16) $ (0.14) DA MCC $ (0.15) $ (0.39) $ (0.26) $ (0.09) $ (0.10) $ (0.08) $ (0.18) $ (0.15) $ (0.24) DA LMP $ 39.45 $ 38.69 $ 36.74 $ 32.89 $ 32.52 $ 34.03 $ 29.81 $ 31.48 $ 32.29 Real Time 14-Mar 14-Apr 14-May 14-Jun 14-Jul 14-Aug 14-Sep 14-Oct 14-Nov RT MEC $ 40.39 $ 33.89 $ 37.91 $ 28.91 $ 31.21 $ 33.55 $ 30.17 $ 31.84 $ 31.63 RT MLC $ (0.18) $ (0.15) $ (0.11) $ (0.11) $ (0.07) $ (0.08) $ (0.17) $ (0.14) $ (0.12) RT MCC $ (0.33) $ (0.55) $ (0.31) $ (0.26) $ (0.08) $ (0.23) $ (0.40) $ (0.24) $ (0.25) RT LMP $ 39.88 $ 33.19 $ 37.49 $ 28.54 $ 31.07 $ 33.24 $ 29.61 $ 31.46 $ 31.26

$0.00

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1-Mar 1-Apr 1-May 1-Jun 1-Jul 1-Aug 1-Sep 1-Oct 1-Nov

LMP

DA LMP

RT LMP

LOAD FORECAST Section 5

18

19

MTLF – Operator Error 11/29/2014

* Above temp pattern is for Tulsa but other areas are similar

• SPP should have selected a different MTLF for this DA_RUC case • The auto-selected MW was off ~1000-1400 at its worst points throughout the day

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

20 * Information may be specific to this or similar cases

21 * Load forecast data used from DA-RUC cases

0

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AVG MTLF by Hour AVG Actual by Hour AVG Error % Error Threshold %

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Daily AVG STLF Daily AVG Actual Error Threshold % Forecast Error %

WIND FORECAST Section 6

23

24 * Wind forecast data used from DA-RUC cases

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Daily AVG MTWF Daily AVG Actual MW Override Error Threshold % Forecast Error %

25 * Wind forecast data used from DA-RUC cases

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26

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DAMKT UPDATE Section 7

27

DA Obligations vs RUC Obligations - November • DA (Cleared Load + NSI – Virtual Offers – Wind Offers)

• RUC (Load Forecast + NSI – Wind Forecast)

28

14000

15000

16000

17000

18000

19000

20000

21000

22000

23000

24000

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 - November

• All November days averaged into one “average” day

• Average 655 MW short

• Peak 1121 MW short

• Differences – Virtuals

– Wind offered in DA vs Wind forecast in RUC

29

DA Obligations vs RUC Obligations - November

Average MW Short by Hour

30

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DA Fixed and PS Bid (with losses) vs MTLF

31

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MTLF

DemandBid

November - Cleared Virtual offers and bids

32

0

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Cleared Virtual Offers(MW)

Cleared Virtual Bids(MW)

APPENDIX

Section 8

33

34

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.

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).

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.

35

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.

TEMP12_20560

Shows up during high wind (westeast) and high northsouth flows; this has been recently aggravated by the Smoky Hills – Summit 230kV outage. During October it was aggravated by the Sun City – Medicine Lodge 115kV outage (which was previously the limiting element in the area). Difficult to control, usually ends up dispatching Nebraska (GGS) generation down to resolve the loading in RTBM.

TEXAS_CO_TXPS_TXCO_PHSHFT_PS

This has always been “activated”, but it is just now showing up in the MDB solutionconstraint tables since the 1.12 release. We control the Texas County phase-shifter to zero MW flow in the DAMKT/RUC MCE solution (per direction from SPS); this just represents the effect of controlling that phase-shifter to 0 MW flow.

SUNAMOTOLYOA

SPS northsouth constraint that is the most limiting path for feeding load in southern SPS and New Mexico, south of OSGCANBUSDEA. Recent generation outages at Mustang and Hobbs plant have loaded this constraint up more, so that more expensive generation is required on in New Mexico to replace the cheaper MSTNG, HOBBSCC1, HOBBSCC2 resources.

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).

TEMP15_20574 Mostly an outlet for AES generation; they are dispatchable, but they rarely follow their setpoints, so we violate this a lot in RTBM.

GGS Stability constraint for western Nebraska flows coming out of GGS; this usually doesn’t bind (pretty much only limits GGS output anyway), but recent outages at Pauline 345kV (10/20 – 11/26 planned) have required a lower limit for the flowgate (per the standing GGS op-guide), so we have been binding more.

TEMP48_20597 This constraint was used during the Mingo 345/115kV transformer outage 10/20 – 11/3; it basically requires more generation in west Kansas to be brought up to help support the load in the area (there are also some northsouth impacts from NPPDSPS as well on this constraint)

FAIOSBSTJHAW TVA flowgate. This usually shows up during 345kV outages in and around Kansas City (most significantly for the recent Iatan – Eastowne 345kV outage 9/20 – 10/9); we occasionally receive a relief assignment from IDC when TVA calls a TLR on this constraint.

36

TEMP95_20633

This now shows up in the place of WDWFPLWDWTAT with the addition of new wind farms at Tatonga. It shows up during high NW to SE flows from the Texas Panhandle and West Kansas and also when there is high wind in the area. Usually resolved by dispatching just about anything in SPS down and bring up Mooreland generation if it is online. No related outages, this will probably be a permanent flowgate.

TMP127_20536

This is similar to TEMP12_20560, and was aggravated by the Smoky Hills – Summit 230kV outage in November. It is caused by high NW to SE flows coming across West Kansas. This is usually resolved in RTBM by dispatching down coal units in Nebraska and west Kansas (DVERs don’t really get curtailed for this one)

TMP144_20608 Loading during Arcadia – Northwest 345kV outage. This flowgate limits flow coming into Oklahoma City from the northeast side and is usually resolved in RTBM by dispatching down the nearby Redbud units.

TEMP66_20599

External flowgate caused by SPP outage of St Joe – Hawthorn 345kV; loading was driven by high external impacts (MISO and AECI wind) and was difficult for RTBM to solve at times (when we were assigned relief during a TLR) due to a lack of generation online in east Kansas City.

COOPER_S

North to south constraint that showed up in lieu of other Kansas City constraints when there were several large units offline in Kansas City. External impacts (primarily MISO and their wind) drive much of the loading on this constraint. It is usually resolved by issuing a TLR to get relief from MISO and tags, and if SPP gets assigned relief, this constraint just requires Nebraska generation to be dropped and Kansas City generation to be increased.

TMP109_20517

Drive by a variety of transmission and generation outages in east Kansas and Kansas City; there is north to south flow involved (from external impacts, MISO) and west to east flow to serve Kansas City load. This is usually resolved in RTBM pretty easily by dropping the Westar generation in east Kansas and picking up generation in south Kansas City.

TEMP14_20279 High north to south loading in SPS driven mostly by lack of cheap generation in the south as well as high wind in the north, this was showing up when the monitored element for OSGCANBUSDEA was out of service, so Temp14 was the next highest loaded constraint in the SPS north to south corridor

SPP November 2014 Marketplace Update

Market Monitoring Unit

Overview • LMPs and MCPs

• Summary of Scarcity Events

• DA Market Participation

• Make Whole Payments and RNU

• Congestion

• TCR Funding

2

Monthly Average LMPs

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SPP - DAMKT SPP - RTBM

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5/14

11/0

6/14

11/0

7/14

11/0

8/14

11/0

9/14

11/1

0/14

11/1

1/14

11/1

2/14

11/1

3/14

11/1

4/14

11/1

5/14

11/1

6/14

11/1

7/14

11/1

8/14

11/1

9/14

11/2

0/14

11/2

1/14

11/2

2/14

11/2

3/14

11/2

4/14

11/2

5/14

11/2

6/14

11/2

7/14

11/2

8/14

11/2

9/14

11/3

0/14

Coun

t of 5

Min

ute

Mar

ket I

nter

vals

RTBM Scarcity and Ramp Events

November 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

13

0.0%

2.0%

4.0%

6.0%

8.0%

10.0%

Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14

Cleared Virtual Bids as Percent of Report Load Cleared Virtual Offers as Percent of Reported Load

Virtual Participation – Hourly Volume

14

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

Aver

age

Hour

ly V

olum

e (M

Wh)

Hourly Average Uncleared Virtual Bids

Hourly Average Cleared Virtual Bids

Hourly Average Uncleared Virtual Offers

Hourly Average Cleared Virtual Offers

Average Hourly Load Participation in DA Market

15

90%

91%

92%

93%

94%

95%

96%

97%

98%

99%

100%

101%

102%

103%

104%

Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14Cleared Demand as Percent of Reported Load-Off PeakCleared Demand as Percent of Reported Load- ON Peak

Make Whole Payments

16

Revenue Neutrality Uplift

17

* This table is based on the latest available settlements data and is subject to change due to resettlement

14-Apr 14-May 14-Jun 14-Jul 14-Aug 14-Sep 14-Oct 14-NovDA Revenue Inadequacy 0 0 0 0 0 0 0 0RT Revenue Inadequacy 85,000 19,000 54,000 111,000 49,000 110,000 88,000 132,000OOME MWP 91,000 94,000 170,000 83,000 22,000 39,000 7,000 158,000RT Regulation Deployment Adj 131,000 -21,000 219,000 161,000 143,000 38,000 78,000 -36,000RT JOA 0 0 0 0 0 0 0 0RT Congestion 1,455,000 2,507,000 4,367,000 -179,000 -341,000 2,778,000 2,048,000 1,154,000Sub-Total 1,762,000 2,599,000 4,810,000 176,000 -127,000 2,965,000 2,221,000 1,408,000Less RT Net Inadvertent 1,078,000 504,000 196,000 268,000 426,000 907,000 -596,000 -191,000RNU * 684,000 2,095,000 4,614,000 -92,000 -553,000 2,058,000 2,817,000 1,599,000

18

November Congestion

19

CPT_CAL_YR_MO_NUM 201411

CONSTRAINTNAME Intv_in_Month BREACHED BINDING %_Breach %_Binding ShadowPrice_M ABS_SP Hourly_Avg_SP Top_Ten

OSGCANBUSDEA 8640 421 3,946 4.87 45.67 -1,060,098 1,060,098 122.697 1

SUNAMOTOLYOA 8640 249 2,671 2.88 30.91 -249,792 249,792 28.911 2

TEMP95_20633 8640 184 937 2.13 10.84 -249,609 249,609 28.890 3

TEMP37_20355 8640 70 913 0.81 10.57 -204,133 204,133 23.627 4

TEMP52_20619 8640 203 295 2.35 3.41 -203,081 203,081 23.505 5

TEMP66_20599 8640 110 605 1.27 7.00 -165,679 165,679 19.176 6

NEORIVNEOBLC 8640 132 358 1.53 4.14 -147,761 147,761 17.102 7

TMP127_20536 8640 143 168 1.66 1.94 -146,965 146,965 17.010 8

TEMP12_20560 8640 154 198 1.78 2.29 -141,586 141,586 16.387 9

WDWFPLWDWTAT 8640 43 638 0.50 7.38 -95,573 95,573 11.062 10

20

TCR Summary by Month

86.0% Funding

November TCR Summary

21

ARR Summary by Month

22

112% Funding

Regulatory Report to MWG for December 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 (MPRR 102) 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 (69b, 121, 135, 139) and TRRs (109M, 113M) 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.

Regulatory Report to MWG for December 2014

Compliance filing made on August 29, 2014. Comments due by October 21, 2014. Order issued by FERC on November 20, 2014 accepting the filing with a March 1, 2014 effective date.

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. Amendment to compliance filing (TRR 140) made on November 25, 2014. Comments due by December 16, 2014.

Awaiting order.

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. Motion for Extension of Time filed on November 14, 2014. Order issued by FERC on November 25, 2014 accepting the motion for extension of time until January 30, 2015.

Preparing compliance filing to be filed on or before January 30, 2015.

MPRR 180—Federal Service Exemption

ER14-2850 ER14-2851

Filing of MPRR 180 part of larger filing made on September 11, 2014. Comments due by October 2, 2014.

• Numerous interventions were filed and six protests were filed. SPP filed responses on October 24, 2014.

Order issued by FERC on November 10, 2014 conditionally accepting in part and rejecting in part the filing with compliance requirements outlined in the order.

Preparing compliance filing to be filed on or before December 10, 2014.

MPRR 183—Re- ER15-20 Filing of MPRR 183 made on October 2, 2014. Comments due by October 23, 2014.

Regulatory Report to MWG for December 2014

pricing Clarification • Three interventions were filed. Order issued by FERC on November 25, 2014 accepting the filing with a March 1, 2014 effective date.

MPRR 173—Physical Withholding Screen

ER15-21 Filing of MPRR 173 made on October 2, 2014. Comments due by October 23, 2014. • Three interventions were filed.

Order issued by FERC on December 1, 2014 conditionally accepting the filing with one compliance requirement outlined in the order.

Preparing compliance filing to be filed on or before December 31, 2014.

MPRR 190—MWP Start-Up Offer Recovery Eligibility Clarifications

ER15-45 Filing of MPRR 190 made on October 6, 2014. Comments due by October 27, 2014. • Three interventions were filed.

Motion for Deferral filed on November 14, 2014.

Awaiting new implementation schedule.

MPRR 178—DVER & NDVER Operating Limit Clarification

ER15-47 Filing of MPRR 178 made on October 6, 2014. Comments due by October 27, 2014. • One intervention was filed.

Order issued by FERC on December 2, 2014 accepting the filing with a December 5, 2014 effective date.

Regulatory Report to MWG for December 2014

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—12/31/2014 155 Modification of OOME Rules Tabled by SPP Operations

165 Pseudo-Tie Losses Correction Related to deficient filing (ER14-1653)

193 VRL and Market-to-Market coordination Phase II project—12/15/2014 194 Mitigation Tests for Manual Commitments 12/31/2014 195 Online Supplemental Reserve and OR Dispatch Status 12/15/2014 197 VOM Cost Clarification Remanded back to MWG 199 Intra-Day Mitigation Measures Clarifications 12/31/2014 201 Dispute Clarification 12/31/2014 202 Uneconomic Production Monitoring Screen 12/31/2014 204 Compliance and Additional Changes FERC Order 755 Phase II project—12/31/2014 212 Over Collected Losses Design Change 12/31/2014