Southwest Power Pool

MARKET WORKING GROUP MEETING

March 18-19, 2014

AEP Offices – Dallas, TX

• Summary of Motions • Agenda Item 6 – MPRR 169-Clear and Unambiguous Day-Ahead Must Offer Proposal — Amber Metzker (Xcel) motioned and Richard Ross (AEP) seconded to postpone implementation and filing of MPRR130 and to table MPRR169 until after MWG can consider market operations up to October 1, 2014 and then make further recommendations to MOPC. The motion passed with no opposition and one abstention (GSEC). Agenda Item 7 – Finalize Strategic Plan Input — Richard Ross (AEP) motioned and Rick McCord (EDE) seconded to submit the MWG input to the SPP Strategic Plan as modified. The motion passed with no opposition and no abstentions. Agenda Item 9 – MPRR171-LTCR Clarification — Jim Flucke (KCPL) motioned and Matt Moore (GSEC) seconded to expedite MPRR171. The motion passed with no opposition and no abstentions. — Ann Scott (Tenaska) motioned and Jim Flucke (KCPL) seconded to approve MPRR171 as modified and with direction to SPP Staff to make conforming Tariff changes. The motion passed with no opposition and no abstentions. Agenda Item 10 – MPRR170-OOME Protocol Clarifications — Amber Metzker (Xcel) motioned and Ann Scott (Tenaska) seconded to expedite MPRR170. The motion passed with no opposition and no abstentions. — Matt Johnson (CUS) motioned and Aaron Rome (Midwest Energy) seconded to reject MPRR170. The motion did not pass in a roll call vote with four yes votes (Midwest Energy, NPPD, Edison Mission, CUS), four oppositions (AECC, EDE, GSEC, OGE) and eight abstentions (AEP, OMPA, KMEA, KCPL, Tenaska, OPPD, WR, Xcel). — Rick McCord (EDE) motioned and Bruce Walkup (AECC) seconded to reject all changes to MPRR170 except the change to remove the “or prevent” language and with direction to SPP Staff to make conforming Tariff changes. The motion passed in a roll call vote with six yes votes (OMPA, KMEA, KCPL, AECC, EDE, WR), four oppositions (Midwest Energy, NPPD, CUS, Edison Mission) and five abstentions (AEP, Tenaska, GSEC, Xcel, OGE). Agenda Item 11 – MPRR172-Dispute Clarification — Jim Flucke (KCPL) motioned and Neal Daney (KMEA) seconded to expedite MPRR172. The motion passed with no opposition and no abstentions. — Marguerite Wagner (Edison Mission) motioned and Matt Johnson (CUS) seconded to approve MPRR172 as modified. The motion passed with no opposition and no abstentions.

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Agenda Item 12 – MPRR168-Regulation Priority Groups — Jim Flucke (KCPL) motioned and Ron Thompson (NPPD) seconded to approve MPRR168 as submitted. The motion passed with no opposition and no abstentions.

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Southwest Power Pool

MARKET WORKING GROUP MEETING

March 18-19, 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 March 18-19 2014). The following members were represented by proxy:

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

• Gary Clear (OGE) for Shawn McBroom (OGE) (Attachment 1b - Proxy Shawn McBroom)

The group reviewed the agenda (Attachment 2—MWG Agenda for Mar 18-19 2014) and agreed to some changes in agenda order to accommodate presenters and audience. Agenda Item 2a and 2b — Minutes Approval Richard Ross (AEP) asked for feedback on the minutes from the MWG February 11-12 2014 meeting (Attachment 3 - MWG February 11-12 2014 Minutes) and the MWG February 21 2014 meeting (Attachment 4 - MWG February 21 2014 Minutes). No changes were made and the minutes were deemed approved as posted. Agenda Item 3 — Working Group/Committee Updates

• Richard Ross (AEP) told the group that SPP is working on updates to spp.org and if anyone had suggestions for the Web site to send them to Debbie James (SPP) via email. Richard mentioned having an area on the Web site similar to “Dropbox” so that updates to Working Group meeting materials for example are automatically populated without the Member having to re-download materials. Cliff Franklin (Westar) suggested tab or dropdown from the home page to frequently referenced documents such as the Tariff, Protocols, etc.

• Debbie James (SPP) reminded the group of the previously announced Joint Working Group (JWG) meeting on Wednesday afternoon, March 19, at 1:30-5:00 at the Doubletree Hotel in Dallas-Addison. She also informed the group that the JWG meeting has now been extended until Thursday, March 20, at 8:30-12:00 and MWG Members may want to stay over or dial in for that session.

• Richard Ross (AEP) announced the formation of a Mitigated Offer Task Force (MOTF) to address post go-live questions and issues related to mitigated offers and the mitigated offer

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development rules and guidelines. Amber Metzker (Xcel) will chair the task force and will work with Richard Ross on developing a Charter and establishing membership, scope and duration. SPP Staff will appoint someone to act as Staff Secretary for the task force.

Agenda Item 4 — 2013 Organizational Group Survey Results Debbie James (SPP) pointed out the 2013 Organization Group Survey Results (Attachment 5 - 2013 org survey_analysis) in the background materials and asked for any questions or additional feedback. No questions were raised from the group at this time. Agenda Item 5 — Market-to-Market Design Review Gay Anthony (SPP) presented a review of the Market-to-Market design similar to the presentation and examples delivered to the MWG and Seam Steering Committee in December 2012 (Attachment 6 - Market to Market_MWG_FINAL). The primary objective of the review was to remind Members of the Market-to-Market process flow and the subsequent Settlements process. Gay announced that a similar review will be delivered to the Seams Steering Committee as the request of some of its Members and asked for and received feedback from MWG on the presentation and examples in preparation for that Seams SC session. There were some questions around the details of the Settlements process and associated RNU which SPP Staff will be researching further and creating examples for future presentations.

Agenda Item 6 — MPRR169-Clear and Unambiguous Day-Ahead Must Offer Proposal Richard Ross (AEP) introduced MPRR169 (Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG). A draft version of the MPRR was previously introduced and discussed in the February 2014 MWG meeting. This MPRR addresses part of MOPC action item #225 which directs MWG to reexamine the need for Designated Resources in the Marketplace Day-Ahead Must Offer. MPRR169 proposes an approach for under which all Designated Resources must submit a day ahead must offer. Some exceptions to the must offer requirement are also included in the MPRR, including exceptions for partially uncommitted resources, Wind Farms, and Behind-The-Meter Generation. The group reviewed the proposed MPRR169 language and discussed comments submitted by GSEC, OMPA, OPPD and SPP. Some of the comments questioned the MPRR’s proposal to remove the Must Offer penalty. SPP Legal Staff offered guidance in this area since FERC had originally directed SPP to add the penalty which was not part of the original design. SPP Legal stated that they are not advocating a penalty or not, but given the FERC history on this, there does need to be some kind of incentive for MPs to comply. Some comments also spoke to the fact that FERC may not view any new filing on Must Offer as a positive, especially since they directed SPP to come back to FERC in 15 months after go-live with results and findings from the Must Offer design that was implemented with the Marketplace go-live. SPP Legal’s response to this was that FERC’s standard of “just and reasonable” would still be honored in reviewing a new filing on Must Offer, but that making a major change so quickly after go-live may cause more scrutiny. Other comments spoke against the Must Offer for Designated Resources because SPP does not have a capacity market. Others stated opinions that we do in essence have a capacity market in the form of designated resources; it’s just a bilateral capacity market. The group also heard from John Hyatt (SPP MMU) on the state of the currently implemented Must Offer design. John stated there are no disastrous issues with the design, but it does continue to take a lot of Staff time and resources to administer and monitor it.

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The general consensus of the group seemed to evolve to tabling this MPRR169 and postponing implementation of any other proposed change to the DA Must Offer design (such as MPRR130) and continuing to monitor and view results from the current design that is now in production. An action item was captured for SPP Staff to evaluate and analyze the Must Offer design currently in production in Marketplace and bring results and findings to the October 2014 MWG meeting. Amber Metzker (Xcel) motioned and Richard Ross (AEP) seconded to postpone implementation and filing of MPRR130 and to table MPRR169 until after MWG can consider market operations up to October 1, 2014 and then make further recommendations to MOPC. The motion passed with no opposition and one abstention (GSEC).

Agenda Item 7 — Finalize Strategic Plan Input Debbie James (SPP) presented an updated version of the proposed items for MWG to provide to the Strategic Planning Committee as input to the SPP Strategic Plan (Attachment 8 - MWG Strategic Plan Input_MWG). This updated version contains the descriptions and additional detail requested by the MWG in previous discussions on the Plan. The group discussed the plan and made additional updates. Part of the discussion led to questions and needs regarding posting of Marketplace data and MP needs in that area. As a result of that discussion, an action item was captured for SPP Staff to evaluate what data is posted – both publicly and on secure portals – by other RTOs and bring that list to MWG for evaluation and decisions on what data that SPP Market Participants would like to see posted. Richard Ross (AEP) motioned and Rick McCord (EDE) seconded to submit the MWG input to the SPP Strategic Plan as modified. The motion passed with no opposition and no abstentions. Agenda Item 8 — TCR Update Gay Anthony (SPP) pointed out in the posted background materials an updated version of the MP Congesting Hedging Guide (Attachment 9 - MP Guide_SPP 2014 Congestion Hedging.v2). This version contains and update requested by the MWG in February to include information on credit posting deadlines. Next, Ty Mitchell (SPP) presented a TCR Update (Attachment 10 - TCR Update - 2014_March_Monthly_Summary_v1) which focused on results from the monthly auction for March 2014. During the presentation and discussion, several suggestions were made from MWG Members for future TCR updates, such as 1) showing MWs bid in addition to number of bids; 2) researching the possibility of showing more information on the valuing of competitive bids vs. self-converted bids; and 3) providing a more detailed report on limit expansion. Ty said that he and the SPP Congestion Hedging team will research how to provide these suggested items. There was also discussion regarding issues and inconsistencies for transmission outage scheduling, both from a TO perspective and from the perspective of the handling of outages in the TCR Auction process. The group was reminded of an open MWG action item from February 2014 for SPP Staff to convene a sub-group to gather and address concerns regarding SPP outage coordination processes related TCR processes. Agenda Item 9 — MPRR171-LTCR Clarification (Expedited) Wayne Camp (SPP) introduced MPRR171 (Attachment 11 - MPRR 171 Recommendation Report), which proposes changes necessary to preserve the original intent of the MPRR 138 design by directly converting awarded LTCRs into TCRs prior to the ARR Annual Allocation. These TCRs are then directly modeled as fixed injections and withdrawals as an input into both the Annual ARR Allocation and Annual TCR Auction. This change ensures that LTCRs holder receive their LTCRs at zero cost and allows the

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associated TCRs to be resold in the Annual TCR Auction. Changes are also included that clarify that total LTCR selection is limited to a maximum amount. This MPRR needs expedited treatment in order to not hold up the FERC filing of the LTCR design which needs to include this correction in order to comply with Criteria 7 of the FERC Order on LTCR design. — Jim Flucke (KCPL) motioned and Matt Moore (GSEC) seconded to expedite MPRR171. The motion passed with no opposition and no abstentions. — Ann Scott (Tenaska) motioned and Jim Flucke (KCPL) seconded to approve MPRR171 as modified and with direction to SPP Staff to make conforming Tariff changes. The motion passed with no opposition and no abstentions. Agenda Item 10 — MPRR170-OOME Protocol Clarifications (Expedited) Carrie Simpson (SPP) introduced MPRR170 (Attachment 12 - MPRR 170 Recommendation Report), which clarifies language that was erroneously added during MPRR155-Modification of OOME Rules. The incorrect language told SPP to call NDVERs at all times when there was an issue. This MPRR corrects the language to allow SPP to call the NDVERs only when there is an Emergency Condition. As previously described in MPRR155, notifications via ICCP and XML will be made for non-emergency conditions. The MPRR also contains language additions suggested by ORWG for further clarity. This MPRR170 needs expedited treatment in order for it to be considered by MOPC at the April 2014 meeting so that it can be included in a pending post go-live FERC filing. Several MWG members and MPs voiced concerns regarding logistics issues around a Non-Dispatchable resources’ ability to respond to ICCP/XML signals, and the fact that many time these NDVERs are resources are represented by multiple Market Participants, which complicates the process of communicating multiple dispatch signals from SPP to the generator operator. One motion was made to reject MPRR170; this motion did not pass. A second motion was made to reject all changes contained in MPRR170 except the corrective removal of the “or prevent” language. This motion passed. The results of all motions and votes, including the expedited treatment are as follows: — Amber Metzker (Xcel) motioned and Ann Scott (Tenaska) seconded to expedite MPRR170. The motion passed with no opposition and no abstentions. — Matt Johnson (CUS) motioned and Aaron Rome (Midwest Energy) seconded to reject MPRR170. The motion did not pass in a roll call vote with four yes votes (Midwest Energy, NPPD, Edison Mission, CUS), four oppositions (AECC, EDE, GSEC, OGE) and eight abstentions (AEP, OMPA, KMEA, KCPL, Tenaska, OPPD, WR, Xcel). — Rick McCord (EDE) motioned and Bruce Walkup (AECC) seconded to reject all changes to MPRR170 except the change to remove the “or prevent” language and with direction to SPP Staff to make conforming Tariff changes. The motion passed in a roll call vote with six yes votes (OMPA, KMEA, KCPL, AECC, EDE, WR), four oppositions (Midwest Energy, NPPD, CUS, Edison Mission) and five abstentions (AEP, Tenaska, GSEC, Xcel, OGE).

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Agenda Item 11 — MPRR172-Dispute Clarification (Expedited) Micha Bailey (SPP) introduced MPRR172 (Attachment 13 - MPRR 172 Recommendation Report), which makes corrections to the Protocols to match the Tariff regarding the amount of time to file a dispute on a final or resettlement. The correction changes the amount of time to file a dispute on a resettlement to be 30 days after the posting of the resettlement invoice instead of 14 days as incorrectly stated. — Jim Flucke (KCPL) motioned and Neal Daney (KMEA) seconded to expedite MPRR172. The motion passed with no opposition and no abstentions. — Marguerite Wagner (Edison Mission) motioned and Matt Johnson (CUS) seconded to approve MPRR172 as modified. The motion passed with no opposition and no abstentions. Agenda Item 12 — MPRR168-Regulation Priority Groups Jared Greenwalt (SPP) introduced MPRR168 (Attachment 14 - MPRR 168 Recommendation Report), which updates the Protocol language on Regulation Deployment priority groups to show a current configuration of 6 groups instead of 1 group. This proposed change is a result of SPP’s research and testing of one priority group versus six priority groups, which showed that setting the number of priority groups to six gave a faster and smoother ACE response with fewer Resources cleared for Regulation. Based on those test results, SPP proposed to change the number of priority groups from ‘1’ to ‘6’. Jim Flucke (KCPL) motioned and Ron Thompson (NPPD) seconded to approve MPRR168 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 13 — Marketplace Re-pricing since March 1, 2014 Debbie James (SPP) informed that group that the Marketplace Re-pricing presentation and discussion is scheduled for the Joint Working Group (JWG) meeting on the afternoon of March 19. The group agreed to not have the discussion here at the MWG meeting but to wait until the JWG meeting. Agenda Item 14 — TSRs with Rollover Rights in regards to ARR/TCRs Nick Parker (SPP) presented information on the process SPP intends to use for TSRs with Rollover Rights in regards to ARRs/TCRs (Attachment 15 - TSRs with Rollover Rights). This information was requested by the MWG in a previous meeting. Agenda Item 15 — MPRR151-Real-Time Data Precision MPRR151 was tabled by the submitter until a future MWG meeting. Agenda Item 16a — Day-Ahead Market Updates-Regulation Clearing Discussion Jodi Woods (SPP) brought two specific items and observations from the Day-Ahead Market on which she and SPP Staff are seeking guidance from the MWG (Agenda Items 16a and 16b). One is the fact that if a Resource is cleared in DA for Regulation Up, Spinning Reserve or Supplemental Reserve, the Max Daily Energy amount submitted for the Resource will be decremented by 50% of the cleared amount for reserve product. Resources cleared for Regulation Down will have their Max Daily Energy incremented

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by 50% of the cleared reg-down amount. This design is not specifically defined in the Protocols, so Jodi is asking for MWG guidance on what should be included in the Protocols for this or if the design should be changed. Jodi and SPP Staff will use the guidance given here to create and MPRR accordingly. Richard Ross (AEP) suggested that SPP Staff write the MPRR to clarify as simply as possible the current design as Jodi described and for those with issues or concerns to submit comments to the MPRR. Cliff Franklin (Westar) also added a suggestion to put some discretion in the Protocols regarding the 50% allowing SPP a range, such as “up to 50%.” SPP Staff will add the suggested language and bring the MPRR to the April MWG meeting. Agenda Item 16b — Day-Ahead Market Updates-Not Participating MPRR The second item (see Agenda item 16a) in which Jodi Woods (SPP) is seeking guidance from MWG is regarding current design in the Day-Ahead Market where a resource with a commitment status of “Not Participating” can actually be cleared for offline Supplemental Reserve if the Dispatch Status for that product is “Market”. The MP can change the Dispatch Status for Supplemental to “Not Qualified” if they do not want to be cleared for offline Supplemental, but just putting the resource in “Not Participating” will not automatically keep it from being cleared for offline Supplemental. Jodi is asking for guidance from MWG on whether or not to keep this design and practice as is or to systematically disqualify a resource for offline Supplemental if it has a Commitment Status of “Not Participating”. The general consensus from the group was to not change the way it is being done now, which means that resources in “Not Participating” status can be cleared for offline Supplemental reserve. No MPRR will be needed on this since there is no change being made. Agenda Item 17 — Update on Offer Cap Adjustments John Hyatt (SPP MMU) presented the following two updates as requested from the February MWG meeting (Attachment 16 - MWG Gas Price Offer Cap March 2014):

• The first update was regarding SPP Staff’s research on the possibility of re-pricing in the EIS Market for the hours of 0000-0900 on February 7-12, 2014 when EIS Offer Cap adjustments were made due to spikes in gas prices and the coverage provided by those adjustments was inadvertently disrupted due to the EIS Offer Cap process being based on the electric day versus the gas price day (0900-0900). John reported that since this was not a software issue, then the Protocols and Tariff do not allow re-pricing for this event.

• The second update was regarding a request by MWG for SPP Staff to research how PJM handled Offer Caps when the gas prices went above $1000. John reported that PJM suspended the Offer Cap during that time and that PJM did implement procedures to reprice and make the resources whole, but did not implement those procedures retroactively. Some discussion from the group and from John indicated the possibility of not even needing an offer cap in markets with sophisticated mitigation logic. It was suggested that this be a topic considered and discussed by the newly formed Mitigated Offer Task Force. An MWG Action Item was captured directing the Mitigated Offer Task Force to evaluate options for SPP Marketplace design in regards to handling extreme price variation days due to fuel cost spikes or other situations; specifically evaluating the need for a Safety Net Offer Cap or not in Marketplace .

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Agenda Item 18 — Regulatory Report Marisa Choate (SPP) presented the Regulatory Report and answered questions from the group (Attachment 17 - 2014 03 Regulatory Report to MWG). Marisa specifically pointed out the busy week of filings on February 24-28, and the Order 755 Deficiency Letter received from FERC on March 7 with a response required by SPP on or before April 7.

Agenda Item 19 — Marketplace Phase II Update Alice Wright (SPP) presented an updated on Marketplace Phase II projects (Attachment 18 - Marketplace Phase II Update). Of primary concern in the update to many of the MWG Members and attendees was the SPP’s communicated risk of not being able to implement the Enhanced Combined Cycle by March 1, 2015 as originally planned. Some of the concerned Members and MPs asked that the minutes officially record their concern of the implications to the Marketplace of delaying implementation of Enhanced Combined Cycle. Those Members and MPs are: John Varnell (Tenaska), Roy True (Aces), Matt Moore (GSEC) and Cliff Franklin (Westar). Alice and Debbie James (SPP) communicated to the group that SPP is committed to the Enhanced Combined Cycle design and to working through the implementation issues as fast as we can. Alice thanked the group for their feedback. Debbie announced that the official Marketplace Phase II updates would be presented at the CWG meetings going forward, with shorter more topic specific updates mentioned at the MWG meetings as needed or requested. Agenda Item 20 — Review MWG Action Item List Gay Anthony (SPP) reviewed the MWG Action Item list (Attachment 19 - MWG Action Items 03-11-14), specifically pointing out the items in a “pending closure” status and asking for MWG approval to change the status to “closed”. MWG did agree to the closure of all items pending closure. Agenda Item 21 - Review of Motions, Action Items and Future Meetings

Motions: Agenda Item 6 – MPRR 169-Clear and Unambiguous Day-Ahead Must Offer Proposal — Amber Metzker (Xcel) motioned and Richard Ross (AEP) seconded to postpone implementation and filing of MPRR130 and to table MPRR169 until after MWG can consider market operations up to October 1, 2014 and then make further recommendations to MOPC. The motion passed with no opposition and one abstention (GSEC). Agenda Item 7 – Finalize Strategic Plan Input — Richard Ross (AEP) motioned and Rick McCord (EDE) seconded to submit the MWG input to the SPP Strategic Plan as modified. The motion passed with no opposition and no abstentions. Agenda Item 9 – MPRR171-LTCR Clarification — Jim Flucke (KCPL) motioned and Matt Moore (GSEC) seconded to expedite MPRR171. The motion passed with no opposition and no abstentions.

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— Ann Scott (Tenaska) motioned and Jim Flucke (KCPL) seconded to approve MPRR171 as modified and with direction to SPP Staff to make conforming Tariff changes. The motion passed with no opposition and no abstentions. Agenda Item 10 – MPRR170-OOME Protocol Clarifications — Amber Metzker (Xcel) motioned and Ann Scott (Tenaska) seconded to expedite MPRR170. The motion passed with no opposition and no abstentions. — Matt Johnson (CUS) motioned and Aaron Rome (Midwest Energy) seconded to reject MPRR170. The motion did not pass in a roll call vote with four yes votes (Midwest Energy, NPPD, Edison Mission, CUS), four oppositions (AECC, EDE, GSEC, OGE) and eight abstentions (AEP, OMPA, KMEA, KCPL, Tenaska, OPPD, WR, Xcel). — Rick McCord (EDE) motioned and Bruce Walkup (AECC) seconded to reject all changes to MPRR170 except the change to remove the “or prevent” language and with direction to SPP Staff to make conforming Tariff changes. The motion passed in a roll call vote with six yes votes (OMPA, KMEA, KCPL, AECC, EDE, WR), four oppositions (Midwest Energy, NPPD, CUS, Edison Mission) and five abstentions (AEP, Tenaska, GSEC, Xcel, OGE). Agenda Item 11 – MPRR172-Dispute Clarification — Jim Flucke (KCPL) motioned and Neal Daney (KMEA) seconded to expedite MPRR172. The motion passed with no opposition and no abstentions. — Marguerite Wagner (Edison Mission) motioned and Matt Johnson (CUS) seconded to approve MPRR172 as modified. The motion passed with no opposition and no abstentions. Agenda Item 12 – MPRR168-Regulation Priority Groups — Jim Flucke (KCPL) motioned and Ron Thompson (NPPD) seconded to approve MPRR168 as submitted. The motion passed with no opposition and no abstentions. Action Items:

• SPP Staff to investigate market incentives for NDVERS to become DVERS. • SPP Staff to evaluate what data is posted – both publicly and on secure portals – by other RTOs

and bring that list to MWG for evaluation and decisions on what data that SPP Market Participants would like to see posted.

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

• Mitigated Offer Task Force will evaluate options for SPP Marketplace design in regards to handling extreme price variation days due to fuel cost spikes or other situations. Specifically evaluating the need for a Safety Net Offer Cap or not in Marketplace .

Future Meetings: Joint Working Group March 19, 2014 (1:30 p.m. – 5:00 p.m.) Location: Doubletree Hotel – Dallas, TX

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April 22, 2014 (8:15 a.m. – 6 p.m.) April 23, 2014 (8:15 a.m. – 12 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor May 20, 2014 (8:15 a.m. – 6 p.m.) May 21, 2014 (8:15 a.m. – 12 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor May 21, 2014 Possible Joint Working Group Meeting Time: TBD Location: TBD

Agenda Item 22 – Adjournment Richard Ross (AEP) thanked the group and adjourned the meeting at 10:46 a.m.

Respectfully Submitted, Debbie James Secretary Attachments Attachment 1 - MWG Attendance March 18-19 2014 Attachment 1a - Proxy Ann Scott Attachment 1b - Proxy Shawn McBroom Attachment 2 - MWG Agenda for Mar 18-19 2014 Attachment 3 - MWG Feb 21 2014 Minutes Attachment 4 - MWG February 11-12 2014 Minutes Attachment 5 - 2013 org survey_analysis Attachment 6 - Market to Market_MWG_FINAL Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Attachment 8 - MWG Strategic Plan Input_MWG Attachment 9 - MP Guide_SPP 2014 Congestion Hedging.v2 Attachment 10 - TCR Update - 2014_March_Monthly_Summary_v1 Attachment 11 - MPRR 171 Recommendation Report Attachment 12 - MPRR 170 Recommendation Report Attachment 13 - MPRR 172 Recommendation Report Attachment 14 - MPRR 168 Recommendation Report Attachment 15 - TSRs with Rollover Rights Attachment 16 - MWG Gas Price Offer Cap March 2014 Attachment 17 - 2014 03 Regulatory Report to MWG Attachment 18 - Marketplace Phase II Update Attachment 19 - MWG Action Items 03-11-14

X = In PersonP = By Phone* = By Proxy

Day 1 Day 2 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) 645-2280X X Aaron Rome Midwest Energy arome@mwenergy.com (785) 625-1431X X Amber Metzker Xcel Energy amber.l.metzker@xcelenergy.com (303) 571-6202X * Ann Scott Tenaska ascott@tnsk.com (817) 462-1514X X 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 (785) 213-9722X X Debbie James (Sec) SPP djames@spp.org (501) 614-3577X X Jim Flucke KCPL jim.flucke@kcpl.com (816) 701-7836P P Lee Anderson LES landerson@les.com (402) 467-7591X Marguerite Wagner Edison Mission Energy mwagner@edisonmission.com (617) 529-3127X X Matt Johnson City Utilities, Springfield mjohnson@teainc.org (904) 360-1460X X Matt Moore Golden Spread Electric Coop mmoore@gsec.coop (806) 379-7766X X Neal Daney KMEA daney@kmea.com (913) 660-0242X X Rick McCord EDE rmccord@empiredistrict.com (417) 625-5129P P Rick Yanovich OPPD ryanovich@oppd.com (402) 514-1031X X Ron Thompson NPPD rfthomp@nppd.com (402) 845-5202

* / P * Shawn McBroom OGE mcbroosr@oge.com (405) 239-0255A Sharma AEP asharma@aep.comAdam McKinnie MOPSC adam.mckinnie@psc.mo.gov (573) 522-8706Aiden Smith SWPA aiden.smith@swpa.govAl Taylor BBRS Law ataylor@bbrslaw.comAlan Adams Utilicast aadams@utilicast.comAlan Rukin JSS Law arukin@jsslaw.com

P X Alice Wright SPP awright@spp.orgAlison Hayes SPP ahayes@spp.orgAllan George SECI ageorge@sunflower.net

P Amy Casavechia SPP acasaechia@spp.orgAndrew Ferris BPU aferris@bpu.comAnthony Lemaire TNSK alemaire@tnsk.comAustin Hoekman MREnergy ahoekman@mrenergy.comBarbara Stroope SPP bestroope@spp.org (501) 688-1792Barry Huddleston Clean Line bhuddleston@cleanlineenergy.com (832) 319-6358Barry Warren EDE bwarren@empiredistrict.com (417) 625-4234Bart Tsala PCI btsala@powercosts.com (405) 447-6933

X X Becky Gifford SPP bgifford@spp.orgBen Stander OATI ben.stander@oati.netBenjamin Maher NMPP bmaher@nmppenergy.org

Market Working GroupMarch 18 - 19, 2014

Face to Face Conference

Bernie Kinsella EDPR bernie.kinsella@edpr.comBeth Miller Accenture beth.miller@accenture.comBeth Watts Accenture beth.j.watts@accenture.comBill Grant Xcel Energy william.a.grant@xcelenergy.com (806) 378-2928Bill Leung BJLEUNG bleung@bjleung.comBill Nolte SECI bdnolte@sunflower.net (420) 272-5458Bill Olson Xcel Energy bill.olson@xcelenergy.comBill Reid Climate Energy Project wmreid@sbcglobal.net (405) 816-5456

P P Billy Cutsor MEAN bjcutsor@nmppenergy.orgBilly Yancey EPE Consulting byancey@epeconsulting.comBlaine Erhardt BEPC berhardt@bepc.comBlythe French Xcel blythe.f.french@xcelenergy.comBob Burner Duke Energy g.burner@duke-energy.comBob Tumilty AEP retumilty@aep.comBrenda Fite SPP bfite@spp.orgBrenda Lee Structure brenda.lee@thestructuregroup.comBrent Hebert PSI/EPV/KELSON/ETEC brent.hebert@psisot.net (832) 663-1373Brent Hendrickson Nexant bhendrickson@nexant.com (404) 276-9008Brent Wilcox SPP bwilcox@spp.org (501) 688-8267Brett Hooten SPP bhooten@spp.org (501) 688-1684Brett Kruse Calpine brett.kruse@calpine.com (713) 830-8732Brian Gedrich Nextera brian.gedrich@nee.com (512) 284-4168Brian Hurst GRDA bhurst@grda.comBrian Skinner Tenaska bskinner@tnsk.comBrittney Miller APSC brittney_miller@psc.state.ar.usBruce Rew SPP brew@spp.comCarl Monroe SPP cmonroe@spp.orgCarla Holly BP Energy carla.holly@bp.comCarol Shoemake OGE shoemaca@oge.comCarrie Bumgarner Wright Talisman bumgarner@wrightlaw.comCarrie Carrigan TEA ccarrigan@teainc.orgCarrie Cooper ETEC carrie.cooper@gdsassociates (770) 715-7189

X X Carrie Simpson SPP csimpson@spp.org (501) 688-1757X Casey Cathey SPP ccathey@spp.org (501) 614-3267

Casey Strange OGE strangcl@oge.comCatherine Mooney SPP cmooney@spp.orgCelso Alonso OGE alonsoc@oge.com

P Charles Cates SPP ccates@spp.orgCharles Marshall ITC Transco cmarshall@itctransco.com (248) 946-3276Chris Casale Iberdrola chris.casale@iberdrolausa.comChris Davis SPP cdavis@spp.org (501) 688-2546Chris Devon Michigan PSC devonc@mighigan.govChris Jones Duke Energy chris.jones@duke-energy.comChris Lax SPP clax@spp.org (501) 614-3594

Chris Matthes AEP camatthes@aep.comChris Standifer KCPL chris.standifer@kcpl.comChris Werner AEP cmwerner@aep.com

P P Chris Winburn INDN cwinbrun@indepmo.orgChristi Nicolay Macquarie christi.nicolay@macquarie.comChristina Labij Acciona clabij@acciona-na.com

P Cindy Ireland AR PSC cireland@psc.state.at.usCJ Brown SPP cbrown@spp.org

P Clint Savoy SPP csavoy@spp.org (501) 614-3590Courtney Mehan Tenaska cmehan@tnsk.comCyril Canezin Durable Power ccanezin@durablepwr.comDan Lenihan OPPD djlenhan@oppd.comDan Trent AECI dtrent@aeci.orgDanny Trent OGE trentdw@oge.com (405) 553-3687Daniel Harless SPP dharless@spp.orgDarrell Wilson OGE wilsondw@oge.comDave Almsted MCG Energy dalmsted@mcgenergy.com (612) 240-9733Dave Hines MISO dhines@misoenergy.orgDave Osburn OMPA iphone_test@webex.comDave Pettinger OPPD dpettinger@oppd.comDave Savage RES-Americas david.savage@res-americas.comDavid Charles Basin Electric Power Co. dcharles@bepc.com (701) 557-5631David Dan Power Settlements david.dan@powersettlements.comDavid Daniels SPP ddaniels@spp.orgDavid Erickson AEP dgerickson@aep.com (614) 583-7405David Hackett KEMA dhackett@us.kema.com (321) 600-1228David Hastings DHASTCO david@dhast.com (317) 217-9563David Hurtado SPP dhurtado@spp.orgDavid Kelley SPP dkelley@spp.org (501) 688-1671David Lee SPP dlee@spp.org (501) 614-3333David Lemmons Xcel david.f.lemmons@xcelenergy.comDavid Linton ITC-GP dlinton@itctranso.com (314) 341-5769David Shaffer Wright Talisman shaffer@wrightlaw.comDeb Roby JSS Law droby@jsslaw.comDebbie Prater Oklahoma Corp Comm d.prater@occemail.com (405) 521-6950Dennis Reed Westar dennis.l.reed@westarenergy.comDerek Mosolf MCG Energy dmosolf@mcgenergy.comDiane Janicki Edison Mission djanicki@edisonmission.com (312) 583-6028Dirk Dietz NPPD drdietz@nppd.comDirk Ludwig NPPD daludwi@nppd.comDon Gulley SECI dgulley@sunflower.netEddie Watson SPP ewatson@spp.orgEdmundo Toro INV Energy etoro@invenergyllc.comElie Nassar Ventyx elie.nassar@ventyx.abb.com

P P Eric Alexander GRDA ealexander@grda.com (918) 824-7245Eric Barreveld APX eric.barreveld@apx.comErin Cullum SPP ecullum@spp.orgFarris Wallace Southernco fwallace@southernco.com

P P Farrokh Rahimi OATI farrokh.rahimi@oati.net (612) 360-1654Frank Bristol Acciona fbristol@acciona-na.comFrank Harris Southernco faharris@southernco.com (205) 4827202Garrett Crowson SPP gcrowson@spp.orgGary Cate SPP gcate@spp.org

X X Gary Clear OGE clearf@oge.comGary Rosenwald The Glarus Group gary.rosenwald@theglarusgroup.comGary Shannon AEP gwshannon@aep.com

X X Gay Anthony SPP ganthony@spp.org (501) 688-1722Gayle Freier SPP gfreier@spp.orgGentry Tubbs SPP gtubbs@spp.orgGeoff Coventry Trade Wind gcoventry@tradewindenergy.comGeoff Hocker SWPA geoff.hocker@swpa.gov

P P Geoffrey M Rush OCC g.rush@occemail.comGeorge Fee AEP gfee@aep.comGeorge Kelly Accenture george.kelly@accenture.comGerardo Ugalde SPP gugalde@spp.orgGerry Murphy Xcel gmurphy@xcel.comGina Wilson ITC Transco gwilson@itctransco.com

P P Grant Wilkerson Westar grant.wilkerson@westarenergy.comGreg Adams adamswind@gmail.comGuadalupe Vazquez Acciona gvazquez@acciona-na.comHailey McKewon GRDA hmckewon@grda.com

P Hanhan Hammer SPP hhammer@spp.org (501) 688-8248Harry Skilton Director hskiltondra@comcast.netHarshikesh Panchal XO Energy hpanchal@xo-energy.comHassan Shah SPP hshah@spp.orgHsin Foo KCPL hsin.foo@kcpl.comIshwar Saini Macquarie ishwar.saini@macquarie.com

P Jack Madden GDA Associates jack.madden@gdsassociates.comJacob Justice Aces Power Marketing jacobj@acespower.comJacob Springman Aces Power Marketing jacobs@acespower.comJake Langthorn OGE langthjs@oge.comJamie Johnson NMPP jjohnson@nmppenergy.orgJamel Thomas SPP

X James Fife PSI/EPV/KELSON/ETEC jfife1@entergy.com (281) 297-5406James Lewis Noble Power lewisJ@noblepower.comJames Lemley SPP jlemley@spp.org (501) 614-3575James Meitner Westar james.meitner@westarenergy.comJames Sanderson KCC j.sanderson@kcc.ks.gov (785) 271-3159

James Sweatt Southernco jmsweatt@southernco.comX X Jared Greenwalt SPP jgreenwalt@spp.org

Jarrald Woodcock Nextera jarrald.woodcock@nexteraenergy.comJarrett Friddle SPP jfriddle@spp.orgJason Bailey OGE baileyjd@oge.comJason Davis SPP jdavis@spp.org (501) 614-3374Jason Doerr Basin Electric Power Co. jdoerr@bepc.com (701) 557-5388

P Jason Fix LES jfix@les.comJason Hebert PCI jhbert@powercosts.comJason Minalga INV Energy jminalga@invenergyllc.comJason Robison SPP jrobison@spp.org (501) 688-1711Jason Smith SPP jsmith@spp.orgJason Terhune SPP jterhune@spp.orgJeff DiSciullo Wright Talisman disciullo@wrightlaw.comJeff Knottek City Utilities, Springfield jeff.knottek@cityutilities.netJennifer Swierczek SPP jswierczek@spp.orgJennifer Weatherford GRDA jweatherford@grda.comJerin Purtee KBPU jpurtee@bpu.comJerry Ohmes KCBPU johmes@bpu.com (913) 573-6816

P P Jerry Tielke MREnergy jtielke@mrenergy.comJessica Collins Xcel jessica.l.collins@xcelenergy.comJianfeng Zhang CES-LTD jzhang@ces-ltd.comJill Coffey KCPL jill.coffey@kcpl.comJill Jones NMPP jjones@nmppenergy.orgJim Fort TEA jfort@teainc.orgJim Gonzales SPP jgonzalez@spp.orgJim Guidroz Supervisor of Tariff Administration jguidroz@spp.org (501) 614-3900Jim Hotovy NPPD jrhotov@nppd.comJim Jacoby AEP jwjacoby@aep.com

X X Jim Krajecki Customized Energy Solutions jkrajecki@ces-ltd.comJim Stevens PSI/EPV jim@psisoft.net (713) 253-9396JJ Guo AEP jguo@aep.com

X X Jodi Woods SPP jwoods@spp.orgP Joe Ghormley SPP jghormley@spp.org

Joe Lang LES jlang@les.com (402) 473-3401Joe Smith Joe joe@joe.comJoe Taylor Xcel Energy josepth.c.taylor@excelenergy.com (303) 571-7462Joe Waszak OPPD jmwaszakjr@oppd.comJohn Fernandes ResAmericas john.fernandes@res-americas.com

P John Grotzinger MPUA jgrotzinger@mpua.orgJohn Harvey Exelon john.harvey@exeloncorp.com (515) 221-5717John Henry jh@yahoo.comJohn Holloway AEP jpholloway@aep.com

X X John Hyatt SPP jhyatt@spp.org

John Krajewski Energy Consulting jk@jkenergyconsultmy.com (402) 440-0227P John Luallen SPP jluallen@spp.org

John Seck KMEA seck@kmea.comJohn Snyder SPP jsnyder@spp.orgJohn Stephens City Utilities John.Stephens@cityutilities.net (417) 831-8470John Sturm Aces Power Marketing (APM) jsturm@acespower.com (317) 696-9031

P John Tennyson City UtilitiesX John Varnell Tenaska jvarnell@tnsk.com (817) 462-1037

John Weber MREnergy john.weber@mrenergy.comJon Olson MCG Energy jolson@mcgenergy.com (615) 253-8820Jon Sunneberg NPPD jmsunne@nppd.comJosh Weinstein Chase weinstein@chase.netJoshua Roper KCPL joshua.roper@kcpl.comJudith Judson McQueeney CES jjudson-mcqueeney@ces-ltd.comJuliana Brint Platts juliana_brint@platts.comJustin Cochran SPP jcochran@spp.orgKaren Howland Southernco khowland@southernco.comKarl Pierce BP Energy karl.pierce@bp.comKara Sidman BP Energy kara.sidman@bp.comKatherine Prewitt SPP kprewitt@spp.org (501) 614-3518Kathy Schuerger Xcel Energy kathy.schuerger@xcelenergy.comKatie Seiverling CES-LTD kseiverling@ces-ltd.comKatie Sussen Basin Electric Power Co. ksussen@bepc.com (701) 557-5154Katy Onnen KCPL katy.onnen@kcpl.comKeith Tynes ETEC/GDS keith.tynes@gdsassociates.com (850) 490-2874Kelli Graff Xcel kelli.j.graff@xcelenergy.comKen Donald Utilicast kendonald@me.com

P P Ken Laughlin Tres Amigas klaughlin@tresamigasllc.com (484) 524-5052Keven Szarkowski BEPC kszarkowski@bepc.comKevin Bates SPP kbates@spp.org

P P Kevin Carter Duke-Energy kevin.carter@duke-energy.comKevin Kingsley MDU kevin.kingsley@mdu.comKevin Shipp Ameren kshipp@ameren.comKevin Warren SPP kwarren@spp.org

P P Kim Sullivan WFEC k_sullivan@wfec.comKimberly Badenhop BEPC kbadenhop@bepc.comKip Fox AEP kfox@aep.comKoldo Basterra Acciona kbasterra@acciona.comKristen Rodriguez Electric Power Engineers/Wind Coalition krodriguez@epeconsulting.com (254) 399-8676Kristy Tackett Empire ktackett@empiredistrict.comLaliya Agrawal Nexant lagrawal@nexant.com (972) 369-7572Lanny Nickel SPP lnickel@spp.org (501) 614-3232Laura Manz Tres Amigas lmanz@viridityenergy.com (858) 354-8333Lauren Krigbaum SPP lkrigbaum@spp.org

Lee Robinson SPP lrobinson@spp.orgLeslie Sink SPP lsink@spp.orgLevi Lyons SPP llyons@spp.orgLiam Noailles SPS liam.noailles@xcelenergy.com (303) 571-2794Linda Fellone SPP lfellone@spp.orgLisa Caserta SPP lcaserta@spp.orgLisa Szot Enel lisa.szot@enel.comLloyd Prichard OPPD laprichard@rainbowenergy.comLonnie Lindekugel SPP llindekugel@spp.org

P Luigi Sciaccaluga Enel luigi.sciaccaluga@enel.comLuke Haner OPPD lphaner@oppd.comLyman Wilkes Physical Systems Integration lwilkes@psisoft.net (713) 443-4026Lyudmila Siegel Constellation lyudmila.siegel@constellation.comMalcolm Booker OMPA mbooker@ompa.comManasa Ganoothula TEA mganoothula@teainc.org

P Margaret Sailors OPPD msailors@oppd.comMarguerite Wagner Edison Mission mwagner@edisonmission.com

P P Marisa Choate SPP mchoate@spp.org (501) 688-1707Mark Holler TNSK mholler@tnsk.comMark McGrail EGPNA mark.mcgrail@enel.comMark Watson Platts markham_watson@platts.comMark Wiggins PCI mwiggins@powercosts.comMartin Parizek CPV mparizek@cpv.comMarty Knight SPP mknight@spp.orgMary Jo Montoya Xcel Energy mary.j.montoya@xcelenergy.com (303) 571-7191Mary Lou Walker Charter marylouwalker@charter.net

P Matt Binette Wright Talisman binette@wrightlaw.comMatt Cupps Westar matt.cupps@westarenergy.comMatt Egger NPPD mdegger@nppd.com

P Matthew Harward SPP mharward@spp.orgMatthew Hazelwood TEA hazelwoodml@teainc.orgMatthew Johnson TEA mjohnson@teainc.org (904) 665-0388Maureen Ochola GDS Associates maureen.ochola@gdsassociates.comMeena Thomas Public State of Texas meena.thomas@puc.state.tx.usMehdi Assadian OATI mehdi.assadian@oati.net (925) 202-5017Mei Cheong CCI mei.cheong@ci.com

X X Micha Bailey SPP mcbailey@spp.org (501) 688-2522P Michael Daly SPP mdaly@spp.org

Michael Desselle SPP mdesselle@spp.orgMichael Erbrick DHASTCO michael@dhast.com (281) 687-0609Michael Hutson RES Americas michael.hutson@res-americas.comMichael Massery AECC michael.massery@aecc.comMichael Ray SPP mray@spp.orgMike Berlinski Beacon Power berlinski@beaconpower.com

Mike Collins OGE collinmc@oge.comP Mike Grimes EDP Renewables mike.grimes@eopr.com (713) 265-0316

Mike Hood AECC mike.hood@aecc.comMike Moltane ITC mmoltane@itctransco.com (248) 946-3093Mike Mushrush OMPA mmushrush@ompa.comMike Oliver LES moliver@les.comMike Riley SPP mriley@spp.orgMike Sheriff OGE sherifmd@oge.comMike Wech SWPA mike.wech@swpa.govMitch Elmore Xcel Energy mitch.elmore@xcelenergy.com

P P Mitch Williams WFEC m_williams@wfec.comMonica Strain KCPL monica.strain@kcpl.comNarsi Vempati Nexant nvempati@nexant.comNatalie McIntire natalie.mcintire@gmail.comNathan Case Aces Power Marketing (APM) nathanc@acespower.comNeil Robertson SPP nrobertson@spp.org

P P Nick Parker SPP nparker@spp.org (501) 614-3574P P Nicole Wagner SPP jwagner@spp.org

Nolan Conover TEA nconover@teainc.orgNoumvi Ghomsi MOPSC noumvi.ghomsi@psc.mo.govOmar Martino EDF omarmartino@edf-re.com (612) 618-6272Oliver Burke Entergy oburke@entergy.com (601) 985-2613Pamela Newberry OPPD pnewberry@oppd.comPat Bourne SPP pbourne@spp.orgPat McGarry TEA pmcgarry@tea.inc (904) 993-9511Pat Mosier ARPSC pat_mosier@psc.state.ar.us

P P Patti Kelly SPP pkelly@spp.org (501) 614-3381Patty Denny KCPL patricia.denny@kcpl.comPatty Harrell DC Energy harrell@dc-energy.comPaul Dietz Westar paul.a.dietz@ westarenergy.comPaul Krebs KCPL paul.krebs@kcpl.comPaul Mahlberg INDN pmahlberg@indepmo.orgPaul Malone NPPD pjmalon@nppd.comPaul Oleary YUMAELEC poleary@yumaelec.com

X X Pete Kinney WAPA kinney@wapa.gov (605) 882-7560Phil Stiles Acciona pstiles@acciona.com (312) 673-3027Phillip Bruich SPP pbruich@spp.orgPhuong Phu KCPL phuong.phu@kcpl.comPhyllis Bernard SPP Board of Directors phyllis_bernard@sbcgobal.netPurvi Patel ITC Transco ppatel@itctransco.com (248) 946-3465Rachel Hulett SPP rhulett@spp.orgRajesh Nelli AEP rbnelli@aep.comRaleigh Mohr SPP rmohr@spp.org

P Randy Root GRDA rroot@grda.com

Ray Kershaw ITC Transco rkershaw@itctransco.comRebecca Atkins MPUA ratkins@mpua.orgRebecca Gillespie FERC rebecca.gillespie@ferc.govRebecca Hohnstein LES rhohnstein@les.comRebecca Sanders SPP rsanders@spp.orgRene Garza AEP rfgarza@aep.comRhonda Robinson Calpine rhonda.robinson@calpine.comRich Deming Citi richard.j.deming@citi.com

P P Richard Dillon SPP rdillon@spp.org (501) 614-3228Rick Kosch LES rkosch@les.comRick Mueller OPPD rjmueller@oppd.comRick Running rickrunning@hotmail.com

P Rob Jones GRDA rjones@grda.comP Robert Janssen Kelson Energy rob.janssen@kelsonenergy.com

Robert Pennybaker AEP rlpennybaker@aep.comP P Robert Pick NPPD rjpick@nppd.comX X Robert Safuto Customized Energy Solutions rsafuto@ces-ltd.com (917) 446-2579

Robert Shields AECC rshields@aecc.comX X Robert Stillwell IPL rstillwel@indepmo.org (813) 325-7482

Robert Walker Cargill robert_walker@cargill.com (952) 984-3747P P Roberto Rösner Enel roberto.rosner@enel.com

Ron Chartier SECI rchartier@sunflower.netRoy Boyer Xcel Energy roy.boyer@xcelenergy.comRoy Klusmeyer WFEC r_klusmeyer@wfec.com (405) 247-4275

X X Roy True Aces Power Marketing (APM) royt@acespower.com (317) 695-4146Ryan Burkhalter Citi ryan.burkhalter@citi.comRyan Hicks SPP rhicks@spp.orgRyan Stock AEP rtstock@aep.com

P P Sam Ellis SPP sellis@spp.orgSam Mall City of Denton sam.mall@cityofdenton.comSandeep Baidwan Lspower sbaidwan@lspower.comSanjoy Ksarawgi AEP sksarawgi@aep.comSarah Cost Wind Coalition sarah@windcoalition.orgScott Shepherd ABB scott.shepherd@abb.ventyx.comScott Smith SPP ssmith@spp.orgSeth Cochran DC Energy cochran@dc-energy.comShah Hossain EDE shossain@empiredistrict.comShalini Gupta SPP sgupta@spp.orgShane Jensen OPPD sjenson@oppd.com

X X Shawn Geil KEPCo sgeil@kepco.orgX X Shawnee Claiborn-Pinto PUCT shawnee.claiborn-pinto@puc.state.tx.us (512) 936-7388

Sherman Elliott shermanelliott@comcast.netP Sherry Hamilton SPP shamilton@spp.org

P P Steve Gaw Wind Capital Group RSGaw1@gmail.com (573) 645-0727

Steve Haun LES shaun@les.comSteve McDonald Aces Power Marketing (APM) smcdonald@acespower.com (317) 344-7113Steve Terelmes PCI sterelmes@powercosts.comSteven Harrington GSEC sharrington@gsec.coopSteven Larry Tenaska slarry@tnsk.comStuart Rein Boston Pacific srein@bostonpacific.comSusan Polk SPP spolk@spp.orgSusan Quinn Westar susan.quinn@westarenergy.comTamika Barker SPP tbarker@spp.orgTemujin Roach SPP troach@spp.orgTerri Wendlandt WR terri.wendlandt@westarenergy.com

P Terry Gates AEP tlgates@aep.com (614) 583-6574Tessie Kentner SPP tkentner@spp.org

P Tim Hooker GRDA thooker@grda.comTim Larson Host Integrity Systems tim.larson@hostintegritysystems.comTim Miller SPP tmiller@spp.orgTJ Sandoz OPPD tjsandoz@oppd.comTom Burke Aces Power Marketing (APM) tburke@acespower.com (512) 788-4901Tom DeBaun KCC t.debaun@kcc.ks.govTom Dunn SPP tdunn@spp.orgTom Fritsche SPP tfritsche@spp.orgTom Hestermann Sun Flower tkhestermann@sunflower.netTom Kleckner SPP tkleckner@spp.orgTom Mayhan OPPD tmayhan@oppd.comTony Alexander SPP talexander@spp.orgTony Brill TNSK abrill@tnsk.comTony Delacluyse PCI tony@powercost.com (405) 326-1496Trent A. Campbell OCC t.campbell@occemail.comTrent Carlson JP Morgan trent.a.carlson@jpmorgan.comTrey Fleming SAIC trey.s.fleming@saic.com (713) 345-0753

P Ty Mitchell SPP tmitchell@spp.orgTyler Wolford TEA twolford@teainc.org (904) 360-1460Valerie Barros valerie.barros@edf-re.comVeronica Bosquez CES-LTD vbosquez@ces-ltd.com

P Vince Vandaveer CUS vince.vandaveer@cityutilities.netVincent Musco Boston Pacific vmusco@bostonpacific.comVirat Kapur Electric Power Engineers/Wind Coalition vkapur@epeconsulting.com (512) 382-6700W. H. Thompson AEP whthompson@aep.comWalt Cecil MOPSC walter.cecil@psc.mo.gov

X X Walt Shumate Shumate & Associates waltshumate@sbcglobal.net (512) 496-7704Walt Yeager Duke Energy walt.yeager@duke-energy.com

P P Wayne Camp Accenture wayne.camp@accenture.com (856) 204-0298Wenchun Zhu Wind Capital Group zxhu@windcapitalgroup.comWendell Drost Alstom wendell.drost@areva-td.com (318)348-0014

P P Y Mei Dufossat ymei@dufossat.comYassar Bahbaz SPP ybahbaz@spp.orgYohan Sutjandra TEA ysutjandra@teainc.orgZac Edstrom Cargill zac_edstrom@cargill.comZac Hager OGE hagerzc@oge.comZachary Sharp SPP zsharp@spp.org (501) 688-2548

78 63

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

Micha Bailey

From: Debbie JamesSent: Thursday, February 20, 2014 12:01 PMTo: McBroom, Shawn; Ross, Richard C. (AEP)Cc: Gay Anthony; Micha Bailey; Jared GreenwaltSubject: RE: Proxy to Gary Clear

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: McBroom, Shawn [mailto:McBrooSR@oge.com] Sent: Wednesday, February 19, 2014 12:31 PM To: Debbie James; Ross, Richard C. (AEP) Subject: Proxy to Gary Clear

Debbie, I will be passing my Proxy to Gary Clear for the remainder of February and all of March 2014 for any and all MWG activities. We are in the trenches trying to get everything ready to go with Market start and TCRs, so Gary has volunteer to actually do some real work and help out with our MWG seat. I will resume my seat in April. Thanks Shawn McBroom | OGE Energy Corp. | Office 405.553.3267 | Cell 405.239.0255| mcbroosr@oge.com  

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Southwest Power Pool, Inc.

MARKET WORKING GROUP MEETING

March 18-19, 2013

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. February 11 – 12, 2014

b. February 21, 2014

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

4. 2013 Organizational Group Survey Results ........................................................................ Debbie James

5. Market to Market Design Review ........................................................................................ Gay Anthony

6. MPRR169 - Clear and Unambiguous Day-Ahead Must Offer Proposal ................................ Richard Ross

7. Finalize Strategic Plan Input ............................................................................................... Debbie James

Lunch – 12:00-1:00

8. TCR Update ............................................................................................................................. Ty Mitchell

9. MPRR171 - LTCR Clarification (Expedited) .......................................................................... Wayne Camp

10. MPRR170 – OOME Protocol Clarifications (Expedited) .................................................... Carrie Simpson

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

11. MPRR172 – Dispute Clarification (Expedited) ......................................................................Micha Bailey

12. MPRR168 - Regulation Priority Groups .......................................................................... Jared Greenwalt

13. Marketplace Repricing since March 1, 2014 ....................................................................... Casey Cathey

14. TSRs with Rollover Right in regards to ARR/TCRs ................................................................... Nick Parker

15. MPRR151 - Real-time Data Precision .................................................................................... Terry Gates

16. Day-Ahead Market Updates .................................................................................................. Jodi Woods

a. Regulation Clearing discussion

b. Not Participating MPRR

Day 2 – 8:15 a.m. – 12:00 p.m.

17. Update on Offer Cap Adjustments .......................................................................................... John Hyatt

18. Regulatory Report ............................................................................................................. Marisa Choate

19. Marketplace Phase II Update ............................................................................................... Alice Wright

20. Review MWG Action Item List ............................................................................................. Gay Anthony

21. Review of Motions, Action Items and Future Meetings ..................................................... Debbie James

22. Adjournment ........................................................................................................................ Richard Ross

Southwest Power Pool

MARKET WORKING GROUP MEETING

February 11-12, 2014

AEP Offices – Dallas, TX

• Summary of Motions • Agenda Item 5 – MPRR164-Mitigated Offer Clarifications — Ron Thompson (NPPD) motioned and Matt Johnson (CUS) seconded to approve MPRR164 as modified. The motion passed with no opposition and four abstentions (AEP, Xcel, OGE, OPPD). Agenda Item 9 – MPRR167-Removal of Data Posting for Constraints and RLDFs — Shawn McBroom (OGE) motioned and Lee Anderson (LES) seconded to expedite MPRR167. The motion passed with no opposition and no abstentions. Agenda Item 9 – MPRR167-Removal of Data Posting for Constraints and RLDFs — Shawn McBroom (OGE) motioned and Amber Metzker (Xcel) seconded to approve MPRR167 as submitted. The motion passed with no opposition and one abstention (WR). Agenda Item 10 – MPRR165-Pseudo-Tie Losses Correction — Amber Metzker (Xcel) motioned and Chris Lyons (Exelon) seconded to expedite MPRR165. The motion passed with no opposition and no abstentions. Agenda Item 10 – MPRR165-Pseudo-Tie Losses Correction — Bruce Walkup (AECC) motioned and John Varnell (Tenaska) seconded to approve MPRR165 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 11 – MPRR163-Demand Reduction Clarification — Jim Flucke (KCPL) motioned and Bruce Walkup (AECC) seconded to approve MPRR163 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 12 – MPRR162-General Cleanup — Lee Anderson (LES) motioned and Ron Thompson (NPPD) seconded to approve MPRR162 as modified and including SPP Comments to MPRR162. The motion passed with no opposition and no abstentions. Agenda Item 13 – MPRR80-Impact Assessment — Shawn McBroom (OGE) motioned and Amber Metzker (Xcel) seconded to approve the MPRR80 Impact Assessment for continued movement through the SPP Stakeholder Process and implementation. The motion passed with no opposition and one abstention (OGE). Agenda Item 16 – Day-Ahead Must Offer with MOPC Provisions— Bruce Walkup (AECC) motioned and Amber Metzker (Xcel) seconded to recommend that SPP delay the filing with FERC of MPRR130 until after the April 2014 MOPC meeting. The motion passed one opposition (GSEC) and two abstentions (KCPL, Exelon).

Minutes No. [222]

Agenda Item 17 – MPRR166-Net Benefits Test — Bruce Walkup (AECC) motioned and Jim Flucke (KCPL) seconded to expedite MPRR165. The motion passed with no opposition and no abstentions. Agenda Item 17 – MPRR166-Net Benefits Test — Matt Johnson (CUS) motioned and Shawn McBroom (OGE) seconded to approve MPRR166 as submitted. The motion passed with no opposition and no abstentions.

Minutes No. [222]

Southwest Power Pool

MARKET WORKING GROUP MEETING

February 11-12, 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 8:20 a.m. The attendance was recorded and proxies were announced (Attachment 1 – MWG Attendance February 11-12 2014). The following members were represented by proxy:

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

• Proxy for Feb 12 only: Richard Ross (AEP) for Rick McCord (EDE) (Attachment 1b - Proxy Rick McCord - Feb 12 Only)

The group reviewed the agenda (Attachment 2—MWG Agenda for Feb 11-12 2014) and agreed to some changes in agenda order to accommodate presenters and audience. Debbie James (SPP) announced that agenda item 19, Regulatory Report, should be considered a written report for this meeting and asked the group to direct any questions to Marisa Choate (SPP) during the discussion on agenda item 4, Marketplace FERC Order. Agenda Item 2a — Minutes Approval Gene Anderson (OMPA) asked for feedback on the minutes from the MWG January 2014 meeting (Attachment 3 - MWG January 21-22 2014 Minutes). No changes were made and the minutes were deemed approved as posted. Agenda Item 3a — Working Group/Committee Updates Casey Cathey (SPP) reported that the Marketplace Go-Live Team voted unanimously for the Marketplace to proceed with Marketplace Go-Live on March 1, 2014. Casey also reported that everything was still on track for the 4/1/14 go-live and that he would be giving a detailed report about go-live status and issues at the CWG meeting on February 13-14.

Agenda Item 4 — Marketplace FERC Order – MCRR200 Matt Binette (Wright and Talisman) presented Tariff changes associated with the Marketplace FERC Order issued on 1/29/14 (Attachment 4 - MCRR 200). A compliance filing in response to the 1/29/14 Order is due by 2/28/14. Matt Binette first reported that the Order was very prescriptive by FERC, so the corresponding language changes contained wording exactly as FERC directed it to be. Therefore, Gene Anderson (OMPA) asked the group to refrain as much as possible from making changes to the wording

Minutes No. [222]

in MCRR200. Matt Binette also reported that language for 5 of the FERC Order paragraphs (par. 78, 173, 174, 188 and part of 195) was not yet included in this MCRR200 and would hopefully be included in time for the MWG to review them during their proposed Net Conference meeting on 2/21/14, when the corresponding Protocol Language to MCRR200 is scheduled to be reviewed by MWG. The group expressed continued concerns over paragraphs 24-25 of the FERC Order which meant the removal of “Outage” status from the list of commitment statuses that count towards the offering of all resources in relation to the Day-Ahead Must Offer requirement. SPP Staff assured that MWG Members that a status of “Outage” would not count against the Must Offer measurement. Several MWG Members requested that language be added to confirm this assurance. The suggestion was made to add the word “available” to describe the Resources being checked for Must Offer compliance in Section 2.11.1.B(1) of the Tariff. Some of the group also expressed concern over addition of language involving Local Reliability and the fact that a local TOP is being asked to consider cost when committing units. The concern is that the TOP will not have or know the appropriate cost information. Matt Binette pointed out that FERC included an appendix in the Order for the Local Reliability language that directed the exact language to be used. The group was not able to change such prescriptive language but some did want it recorded that there are concerns over the TOP being directed to consider cost data that is likely not available to them. In the section on the TCR Process and the handling of TSRs with Rollover Rights, the group asked for more details on how the process surrounding this handling would work. Debbie James (SPP) reported that the process was still being defined and that SPP Staff would present the process in a future MWG meeting. The group chose not to vote any language changes at this time since there were still more Tariff language changes to come plus corresponding Protocol language changes. The plan was made to review additional Tariff changes and the Protocol changes in a Net Conference MWG meeting on 2/21. Debbie James (SPP) also reported that SPP Staff is planning to publish version 19 of the Marketplace Protocols as the “go-live” version and to include the Protocol changes related to items in the FERC compliance filing. This discussion ended with Matt Johnson (CUS) asking for clarification on 3 paragraphs from the FERC Order (par. 145, 207, 217), for which he did not see language in the MCRR200. Agenda Item 5 — MPRR164 – Mitigated Offer Clarifications Catherine Mooney (SPP MMU) introduced MPRR164 (Attachment 5 - MPRR 164 Recommendation Report), which provides clarity that only the short-run marginal cost items in fuel and VOM FERC Accounts are includable in mitigated offers. It also makes a correction to the Hydro cost formula and updates historical VOM inflation escalation factors. During the discussion on this MPRR, it was pointed out that an MWG Member has asked for an agenda item for the April MWG to discuss more clarifications regarding cost information, including costs related to long term service agreements (LTSAs). Ron Thompson (NPPD) motioned and Matt Johnson (CUS) seconded to approve MPRR164 as modified. The motion passed with no opposition and four abstentions (AEP, Xcel, OGE, OPPD). Agenda Item 6 — NITSA Sink Locations for TCRs Nick Parker (SPP) made the group aware of a potential issue currently being researched by SPP Staff regarding inconsistencies between NITSA/TSR sinks and their alignment to appropriate Settlement Locations (Attachment 6 - TSR sinks). The results of the research could possibly mean MCST changes for some MPs. The group asked that MPs know about any changes they would need to make in time for the beginning of the 2015 TCR Annual Auction process that begins in February 2015.

Minutes No. [222]

Agenda Item 7 — Ramp Sharing Jarrett Friddle (SPP) and Casey Cathey (SPP) presented data supporting the SPP Staff recommendation for ramp sharing settings at Marketplace go-live on March 1, 2014 (Attachment 7 - Ramp Sharing Update). The ramp sharing settings will be 50% regulation ramp sharing and 100% contingency reserve ramp sharing. Casey pointed out that one of the findings from the data was that the System Marginal Price (SMP) tended to decrease when ramp sharing was turned off, which was likely due in part to the VRL hierarchy in the Marketplace design. Because of these findings, Casey suggested that MWG and SPP Staff work in the near future to revisit price administration for ramp sharing violations. An MWG Action Item was captured to reflect this suggestion. Casey also told the group that SPP Staff will follow up with MWG on how things are going with the go-live ramp sharing settings; this follow-up will be short term immediately after go-live, then every few months going forward.

Agenda Item 8 — Regulation Deployment Yasser Bahbaz (SPP) presented results from research conducted by SPP Staff regarding regulation deployment distribution during integrated deployment testing (IDTs) (Attachment 8 - Regulation Deployment Distribution). The results showed an issue where regulation deployment for the SPP BA had to be increased – which increased cost – in order to get of the small deployments that are in the generator “dead band” ranges. The proposed solution for this issue is to add more priority groups with a smaller list of units cleared for regulation in each group. The recommendation for MWG is to make a setting change for the IDT on 2/25/14, prior to go-live, to add more priority groups and see how it goes. SPP Staff will report the IDT results to MPs at the Joint Working Group (JWG) scheduled for 2/26/14 at 1:00-3:00. A resulting production change would require MWG, ORWG and MOPC approval. MWG endorsed SPP Staff’s recommendation to increase the number of regulation deployment priority groups for the IDT on 2/25/14.

Agenda Item 9 — MPRR167-Removal of Data Posting for Constraints and RLDFs Gay Anthony (SPP) introduced MPRR167 (Attachment 8 - Regulation Deployment Distribution), which removes language from the Protocols related to posting of data on constraints and Resource to Load Distribution Factors (RLDFs). This MPRR was a result of the discussion on this topic at the MWG meeting on January 21-22, during which MWG directed SPP Staff in an MWG Action Item (#235) to research with SPP Compliance and Legal on what of the data can and cannot be posted. The research by SPP Staff led to guidance from SPP Legal and SPP Operations to not post the resource/constraint data or the RLDF data. This MPRR is on an expedited timeline and therefore needs approval to expedite from the MWG before an approval vote on the Protocol revisions. — Shawn McBroom (OGE) motioned and Lee Anderson (LES) seconded to expedite MPRR167. The motion passed with no opposition and no abstentions. — Shawn McBroom (OGE) motioned and Amber Metzker (Xcel) seconded to approve MPRR167 as submitted. The motion passed with no opposition and one abstention (WR).

Minutes No. [222]

Agenda Item 10 — MPRR165-Pseudo-Tie Losses Micha Bailey (SPP) introduced MPRR165 (Attachment 10 - MPRR 165 Recommendation Report) which conforms language from MPRR69 to contain corrected language regarding pseudo-tied assets changes in order to reflect comprehensive changes directed by FERC regarding over-collection of losses, as detailed in MCRR116. This MPRR is on an expedited timeline and therefore needs approval to expedite from the MWG before an approval vote on the Protocol and Tariff revisions. — Amber Metzker (Xcel) motioned and Chris Lyons (Exelon) seconded to expedite MPRR165. The motion passed with no opposition and no abstentions. — Bruce Walkup (AECC) motioned and John Varnell (Tenaska) seconded to approve MPRR165 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 11 — MPRR163-Demand Reduction Clarification Micha Bailey (SPP) introduced MPRR163 (Attachment 11 - MPRR 163 Recommendation Report), which corrects Protocol language in a number of sections related to Settlements information for Demand Reduction. Jim Flucke (KCPL) motioned and Bruce Walkup (AECC) seconded to approve MPRR163 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 12 — MPRR162-General Cleanup Micha Bailey (SPP) introduced MPRR162 (Attachment 12 - MPRR 162 Recommendation Report), which makes miscellaneous Protocol language corrections needed in various Sections of the Protocols, and which includes SPP Comments from 1/31/2014 to add language regarding “fuel supply limitations” back into Section 8.2.2.3-Mitigation Measures for Energy Offer Curves, as directed by FERC. Lee Anderson (LES) motioned and Ron Thompson (NPPD) seconded to approve MPRR162 as modified and including SPP Comments to MPRR162. The motion passed with no opposition and no abstentions. Agenda Item 13 — MPRR80 Impact Assessment Jared Greenwalt (SPP) presented the MPRR80 Impact Assessment (Attachment 13 - MPRR 80 Impact Analysis), so that the changes approved in MPRR80 can move on through the SPP Stakeholder Process and to eventual implementation. MPRR80 incorporates and automatic calculation to keep a Resource from getting compensation for output beyond an OOME instruction. A manual adjustment via the Miscellaneous charge type will be used pending the implementation of MPRR80. Debbie James (SPP) reminded the group that the changes associated with MPRR80 are not currently prioritized to be in the first round of deferrals from Marketplace Phase 1. The MWG agreed with this prioritization. Agenda Item 14 — Strategic Plan Input Update Debbie James (SPP) led the group in a follow-up discussion of some of the strategic plan suggestions that were introduced to the group in the January MWG meeting (Attachment 14 - SPP Strategic Plan Suggestions). The group requested a new item to be added to the list and given a high priority for improvements to coordination of the processes at SPP surrounding Transmission-planning related activities such as Planning and TSRs and GIAs to related processes in SPP Operations. SPP Staff agreed to write a more detailed description of this new strategic item and to add more detailed descriptions for each of the other suggested strategic items and to bring the new list for review at the March MWG meeting.

Minutes No. [222]

Agenda Item 15 — TCR Update Rachel Hulett (SPP) presented the TCR Update (Attachment 15 - MWG TCR Update_Feb 2014), which includes a review of the schedules for the upcoming interim Monthly Auctions for April and May and the 2014 Annual Auction. Rachel also brought to the group a proposal for modifications to business practices related to outage types being used in the TCR model. The proposal is to add “submitted” to the list of outage types. The reason for this proposed change is to allow MPs extra time to get their outages reflected in the TCR model data. After much discussion, the group concluded that the underlying issues really are that MPs are not getting their outages submitted in a timely manner and that the SPP Criteria regarding outages needs further clarification. Because more focus is needed on these underlying issues, MWG decided not to endorse this proposed business practice modification. They instead directed SPP Staff to lead an effort to convene a sub group of MWG Members and MPs to gather concerns regarding the SPP outage coordination processes and related TCR processes; and to propose possible short-term and long-term solutions to address the concerns, including bringing proposed SPP Criteria changes to the ORWG. This directive was captured as an MWG Action Item. Preliminary volunteers for the sub group include: Rob Safuto (Customized Energy Solutions), Terry Gates (AEP), Cliff Franklin (Westar), Amber Metzker (Xcel), Richard Ross (AEP), Marguerite Wagner (Edison Mission), and Rick McCord (EDE). Agenda Item 16 — Day-Ahead Must Offer with MOPC Provisions Richard Ross (AEP) introduced a draft proposal for discussion to make language and design changes via a future MPRR to the Marketplace Day-Ahead Must Offer requirement in order to comply with provisions set forth from the MOPC in October 2013 (Attachment 16 - MPRRxxx DRAFT Clear and Unambiguous Must Offer Proposal). The proposal’s author suggests a change to the nature of the must offer from a complicated, costly and ambiguous limited must offer, to a very simple, cost effective and clear approach under which all Designated Resources must submit a day ahead must offer. Some exceptions to the must offer requirement are also included in the proposal, including exceptions for partially uncommitted resources, Wind Farms, and Behind-The-Meter Generation. A question was asked during the discussion about how this design would handle situations where an MP has a DR unit in SPP that they are not offering Day-Ahead in lieu of offering it into another market. The answer from the proposal’s author was that the MP representing that unit could simply “un-designate” the DR unit. The next step for this proposal would be to officially submit an MPRR for movement through the SPP Stakeholder Process ending with review by the MOPC in April. In the meantime, the MWG could recommend that the filing with FERC of MPRR130 be delayed until after MOPC has had a chance to review the must offer design being proposed here, which includes provisions for DRs as directed by MOPC. This is because if the design being proposed here is approved, then the design in MPRR130 would no longer be relevant. Bruce Walkup (AECC) motioned and Amber Metzker (Xcel) seconded to recommend that SPP delay the filing with FERC of MPRR130 until after the April 2014 MOPC meeting. The motion passed one opposition (GSEC) and two abstentions (KCPL, Exelon).

Minutes No. [222]

Agenda Item 17 — MPRR166-Net Benefits Test Micha Bailey (SPP) introduced MPRR166 (Attachment 17 - MPRR 166 Recommendation Report), which makes changes to the Protocols to maintain consistency with FERC approved language for the Net Benefits Test (“NBT”) for the EIS Market. The calculation for the first 12 months of the Marketplace will use EIS Market data so no substantive changes should be made to the language that FERC approved for use prior to go-live. This did lead to discussion that after the first 12 months of Marketplace, an language change would be need to be in place to state the use of Marketplace historical data instead of EIS historical data. An MWG Action Item was recorded directing SPP Staff to bring an MPRR by the end of 2014 changing that language to use Marketplace price data instead of EIS data effective March 1, 2015 and beyond. This MPRR is on an expedited timeline and therefore needs approval to expedite from the MWG before an approval vote on the Protocol revisions. — Bruce Walkup (AECC) motioned and Jim Flucke (KCPL) seconded to expedite MPRR165. The motion passed with no opposition and no abstentions. — Matt Johnson (CUS) motioned and Shawn McBroom (OGE) seconded to approve MPRR166 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 18 — EIS Market Update Catherine Mooney (SPP MMU) presented the EIS Market update for January 2014 and answered questions from the group (Attachment 18 - 201401 MWG MMU presentation). One question asked from the group was if the congestion in Nebraska reflected in the report could be due to external impacts, such as other RTOs or Markets. Catherine Mooney (SPP MMU) said that she would check on this and bring any findings back to the group. This EIS Update also included information on recent EIS Market activity on February 7-12, 2014 when EIS Offer Cap adjustments were made due to spikes in gas prices. This information included discussion around the fact that coverage provided by the Offer Cap adjustments was inadvertently disrupted for certain hours due to the EIS Offer Cap process being based on the electric day versus the gas price day. Some members of the group asked for the possibility of re-pricing during those hours of the disruption. John Hyatt (SPP MMU) reported that these events did not meet the stated criteria for re-pricing, so a decision to re-price would need an override by the MWG of the re-pricing criteria. An MWG Action Item was recorded for SPP Staff to SPP Staff will research the possibility of re-pricing in the EIS Market for the hours of 0000-0900 on February 7-12, 2014 when EIS Offer Cap adjustments were made due to spikes in gas prices and the coverage provided by those adjustments was inadvertently disrupted due to the EIS Offer Cap process being based on the electric day versus the gas price day (0900-0900). During this discussion, the Marketplace $1000 Offer Cap was raised as a concern. The MWG asked SPP Staff to follow up by researching how PJM adjusts their Tariff to accommodate resources with costs above $1000 and report back with any proposed design changes. Agenda Item 19 — Regulatory Report The Regulatory Report for this month’s meeting was included in the Background Materials as a written report (Attachment 19 - Regulatory Report to MWG 2014 02). MWG Members were asked to review the report and direct any questions to Marisa Choate (SPP).

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Agenda Item 20 - Review of Motions, Action Items and Future Meetings

Motions: Agenda Item 5 – MPRR164-Mitigated Offer Clarifications — Ron Thompson (NPPD) motioned and Matt Johnson (CUS) seconded to approve MPRR164 as modified. The motion passed with no opposition and four abstentions (AEP, Xcel, OGE, OPPD). Agenda Item 9 – MPRR167-Removal of Data Posting for Constraints and RLDFs — Shawn McBroom (OGE) motioned and Lee Anderson (LES) seconded to expedite MPRR167. The motion passed with no opposition and no abstentions. Agenda Item 9 – MPRR167-Removal of Data Posting for Constraints and RLDFs — Shawn McBroom (OGE) motioned and Amber Metzker (Xcel) seconded to approve MPRR167 as submitted. The motion passed with no opposition and one abstention (WR). Agenda Item 10 – MPRR165-Pseudo-Tie Losses Correction — Amber Metzker (Xcel) motioned and Chris Lyons (Exelon) seconded to expedite MPRR165. The motion passed with no opposition and no abstentions. Agenda Item 10 – MPRR165-Pseudo-Tie Losses Correction — Bruce Walkup (AECC) motioned and John Varnell (Tenaska) seconded to approve MPRR165 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 11 – MPRR163-Demand Reduction Clarification — Jim Flucke (KCPL) motioned and Bruce Walkup (AECC) seconded to approve MPRR163 as submitted. The motion passed with no opposition and no abstentions. Agenda Item 12 – MPRR162-General Cleanup — Lee Anderson (LES) motioned and Ron Thompson (NPPD) seconded to approve MPRR162 as modified and including SPP Comments to MPRR162. The motion passed with no opposition and no abstentions. Agenda Item 13 – MPRR80-Impact Assessment — Shawn McBroom (OGE) motioned and Amber Metzker (Xcel) seconded to approve the MPRR80 Impact Assessment for continued movement through the SPP Stakeholder Process and implementation. The motion passed with no opposition and one abstention (OGE). Agenda Item 16 – Day-Ahead Must Offer with MOPC Provisions— Bruce Walkup (AECC) motioned and Amber Metzker (Xcel) seconded to recommend that SPP delay the filing with FERC of MPRR130 until after the April 2014 MOPC meeting. The motion passed one opposition (GSEC) and two abstentions (KCPL, Exelon). Agenda Item 17 – MPRR166-Net Benefits Test — Bruce Walkup (AECC) motioned and Jim Flucke (KCPL) seconded to expedite MPRR165. The motion passed with no opposition and no abstentions.

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Agenda Item 17 – MPRR166-Net Benefits Test — Matt Johnson (CUS) motioned and Shawn McBroom (OGE) seconded to approve MPRR166 as submitted. The motion passed with no opposition and no abstentions. Action Items:

• Regarding the current Ramp Sharing design for Marketplace, SPP Staff and MWG will revisit applying price administration in Marketplace for system ramp violations. This Action Item was suggested by Casey Cathey (SPP) who reported research as showing that without price administration, the SMP drops due to VRL hierarchy in the Marketplace design.

• Regarding MPRR166 and the current language that states the use of EIS historical data, SPP Staff will bring an MPRR by the end of 2014 changing that language to use Marketplace price data instead of EIS data effective March 1, 2015 and beyond.

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

• SPP Staff will research the possibility of re-pricing in the EIS Market for the hours of 0000-0900 on February 7-12, 2014 when EIS Offer Cap adjustments were made due to spikes in gas prices and the coverage provided by those adjustments was inadvertently disrupted due to the EIS Offer Cap process being based on the electric day versus the gas price day (0900-0900).

Future Meetings: February 21, 2014 1:00 p.m. – 5:00 p.m. Location: Net Conference Joint Working Group (JWG) Meeting February 26, 2014 1:00 p.m. – 3:00 p.m. Location: Net Conference March 18, 2014 (8:15 a.m. – 6 p.m.) March 19, 2014 (8:15 a.m. – 12 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor April 22, 2014 (8:15 a.m. – 6 p.m.) April 23, 2014 (8:15 a.m. – 12 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor

Minutes No. [222]

Agenda Item 21 – Adjournment Gene Anderson (OMPA) thanked the group and adjourned the meeting at 11:55 a.m.

Respectfully Submitted, Debbie James Secretary Attachments Attachment 1 - MWG Attendance February 11-12 2014 Attachment 1a - Proxy Ann Scott Attachment 1b - Proxy Rick McCord - Feb 12 Only Attachment 2 - MWG Agenda for Feb 11-12 2014 Attachment 3 - MWG January 21-22 2014 Minutes Attachment 4 - MCRR 200 Attachment 5 - MPRR 164 Recommendation Report Attachment 6 - TSR sinks Attachment 7 - Ramp Sharing Update Attachment 8 - Regulation Deployment Distribution Attachment 9 - MPRR 167 Recommendation Report Attachment 10 - MPRR 165 Recommendation Report Attachment 11 - MPRR 163 Recommendation Report Attachment 12 - MPRR 162 Recommendation Report Attachment 13 - MPRR 80 Impact Analysis Attachment 14 - SPP Strategic Plan Suggestions Attachment 15 - MWG TCR Update_Feb 2014 Attachment 16 - MPRRxxx DRAFT Clear and Unambiguous Must Offer Proposal Attachment 17 - MPRR 166 Recommendation Report Attachment 18 - 201401 MWG MMU presentation Attachment 19 - Regulatory Report to MWG 2014 02

Southwest Power Pool

MARKET WORKING GROUP MEETING

February 21, 2014

Net Conference

• Summary of Motions •

Agenda Item 2 – MCRR200-Marketplace FERC Order – Protocol Language — Richard Ross (AEP) motioned and Bill Grant (Xcel) seconded to approve MCRR200 protocol language as modified and as satisfying the compliance filing requirements and as conforming the Protocols to the associated Tariff changes. The motion passed with no opposition and one abstention (CUS).

Minutes No. [216]

Southwest Power Pool

MARKET WORKING GROUP MEETING

February 21, 2014

Net Conference

• M I N U T E S •

Agenda Item 1—Call to Order, Proxies, Agenda Discussion Gene Anderson called the meeting to order at 1:00 p.m. The attendance was recorded and proxies were announced (Attachment 1 – MWG Attendance February 21 2014). The following members were represented by proxy:

Gary Clear (OGE) for Shawn McBroom (OGE) (Attachment 1a – Proxy Shawn McBroom) Bill Grant (Xcel) for Amber Metzker (Xcel) (Attachment 1b - Proxy Amber Metzker) The group reviewed the agenda (Attachment 2 - MWG Agenda for Feb 21 2014) and made no changes or additions. Agenda Item 2 – MCRR200-Marketplace FERC Order – Protocol Language Debbie James (SPP) introduced this agenda item and explained to the group that they would be presented with a version of MCRR200 that has been updated since the MWG meeting on 2/11-12/14 with additional Tariff language changes and with added Protocol language where applicable to conform to all of the added Tariff language (Attachment 3 - MCRR 200_2-18-2014_Protocols_RTWG_MWG). The proposed Tariff and Protocol language changes in MCRR200 are associated with the Marketplace FERC Order issued on 1/29/14. A compliance filing in response to the 1/29/14 Order is due by 2/28/14. Matt Binette (Wright and Talisman) presented the latest Tariff revisions in the updated MCRR200 and answered questions from the group. Jared Greenwalt (SPP) presented the proposed Protocol language to conform to all Tariff changes in MCRR200 and answered questions from the group. Some of the group expressed the same concern as communicated in the 2/11-12/14 MWG meeting over the addition of language involving Local Reliability and the fact that a local TOP is being asked to consider cost when committing units. The concern is that the TOP will not have or know the appropriate cost information. Matt Binette and Jared Greenwalt pointed out that FERC included an appendix in the order for the Local Reliability language that directed the exact language to be used. The group was not able to change such prescriptive language, but some did want it recorded again that there are concerns over the TOP being directed to consider cost data that is likely not available to them. Richard Ross (AEP) motioned and Bill Grant (Xcel) seconded to approve MCRR200 protocol language as modified and as satisfying the compliance filing requirements and as conforming to the Protocols to the associated Tariff changes. The motion passed with no opposition and one abstention (CUS).

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Agenda Item 3 – Review of Motions, Action Items, and Future Meetings Motions: Agenda Item 2 – MCRR200-Protocols — Richard Ross (AEP) motioned and Bill Grant (Xcel) seconded to approve MCRR200 protocol language as modified and as satisfying the compliance filing requirements and as conforming the Protocols to the associated Tariff changes. The motion passed with no opposition and one abstention (CUS). Action Items: No action items were recorded. Future Meetings: Joint Working Group (JWG) Meeting February 26, 2014 Afternoon (time TBD) Net Conference March 18, 2014 (8:15 a.m. – 6 p.m.) March 19, 2014 (8:15 a.m. – 12 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor April 22, 2014 (8:15 a.m. – 6 p.m.) April 23, 2014 (8:15 a.m. – 12 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor May 20, 2014 (8:15 a.m. – 6 p.m.) May 21, 2014 (8:15 a.m. – 12 p.m.) Location: AEP Office – Dallas, TX Room: 8th Floor

Agenda Item 4 – Adjournment

Gene Anderson (OMPA) thanked the group and adjourned the meeting at 3:30 p.m. Respectfully Submitted, Debbie James Secretary

Minutes No. [216]

Attachments Attachment 1 - MWG Attendance February 21 2014 Attachment 1a - Proxy Shawn McBroom Attachment 1b - Proxy Amber Metzker Attachment 2 - MWG Agenda for Feb 21 2014 Attachment 3 - MCRR 200_2-18-2014_Protocols_RTWG_MWG

Overview

2013 2012 2011 2010 2009 2013 2012 2011 2010 *2009Business Practices Working Group 71% 60% 64% 82% n/a 4.4 4.2 4.3 4.6 3.8Change Working Group 63% 61% 44% 65% 38% 4.1 3.9 4.3 4.2 3.3Corporate Governance Committee 100% 88% 88% 75% 43% 4.5 4.7 4.4 4.5 3.2Cost Allocation Working Group 67% 67% 50% 33% 27% 4.7 4.3 3.8 4.0 3.3Credit Practices Working Group 75% 80% 67% n/a n/a 4.0 4.5 4.0 n/a n/aCritical Infrastructure Protection Working Group 53% 71% 75% 69% 27% 4.5 4.3 4.6 4.6 4.3Economic Studies Working Group 63% 81% 67% 71% 38% 4.1 4.2 3.5 3.9 4.3Finance Committee 86% 86% 86% 86% 30% 4.8 4.8 4.5 4.2 3.7Generation Working Group 50% 60% 22% 50% 38% 4.3 4.4 3.5 4.2 2.8Human Resources Committee 86% 71% 100% 86% 40% 3.8 3.6 3.7 4.3 3.3Market Working Group 74% 41% 63% 81% 38% 3.9 4.1 4.3 4.2 3.2Markets and Operations Policy Committee 37% 46% 48% 47% 33% 4.3 3.8 3.7 3.9 3.2Model Development Working Group 100% 77% 100% 92% 48% 4.0 4.0 3.9 3.9 2.8Project Cost Working Group 65% 63% N/a N/a N/a 4.4 4.5 N/a N/a N/a

Operating Reliabilty Working Group 67% 94% 87% 77% 38% 3.7 4.2 4.2 4.2 3.6Operations Training Working Group 70% 92% 83% 92% 45% 4.4 4.5 4.6 4.7 3.7Oversight Committee 100% 100% 100% 100% 100% 4.8 4.8 4.8 4.8 3.5Project Cost Working Group 65% 63% n/a n/a n/a 4.4 4.5 n/a n/a n/aRegional Tariff Working Group 67% 52% 71% 67% 43% 4.7 3.7 4.2 4.2 3.5Seams Steering Committee 70% 40% N/a N/a N/a 4.0 4.3 N/a N/a N/a

Strategic Planning Committee 83% 92% 100% 92% 43% 4.2 4.4 4.3 4.2 3.1Systems Protection and Control Working Group 62% 69% 77% 77% 38% 4.5 3.9 4.5 3.5 3.6Transmission Working Group 54% 82% 79% 67% 41% 3.9 3.9 3.7 4.0 3.4

Average 71% 71% 74% 74% 42% 4.3 4.2 4.1 4.2 3.5

The Finance and Oversight Committees tied for highest overall effectiveness. This is the second year in a row for that. The lowest effectiveness score was the ORWG.

Every score across all groups and questions was 3.2 or higher.

Group

2013 Organizational Group Survey Analysis

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

Response rate Overall effectiveness

Respondents 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.

Table below shows overal response rates and overall effectiveness scores by Organizational Group in alphbetical order.

Overall average effectiveness is 4.3, a new record

SPP Phase II Market to Market OverviewMarch MWG

March 2014

Gay Anthonyganthony@spp.org501.614.3200

INTRODUCTIONSection 1

4

• Market to Market Overview

• Market to Market Process Example

• Market to Market Settlement

5

Topics

Session Objectives

• Identify the objectives of the Market to Market Program.

• List the steps that occur during the Market to Market process.  

• Identify the tasks the Monitoring RTO and Non‐Monitoring RTO complete during the process.

• Identify the key variables in the Market to Market Settlement process. 

• Identify how to settle Market to Market interactions. 

6

• DA – Day‐Ahead

• FFE – Firm Flow Entitlement

• FG – Flowgate

• GTL – Generation‐to‐Load

• JOA – Joint Operating Agreement

• LMP – Locational Marginal Price

• M2M – Market to Market

• MEC – Marginal Energy Component

• MP – Market Participant 

• MRTO – Monitoring Regional Transmission Organization

• NMRTO – Non‐Monitoring Regional Transmission Organization

• RCF – Reciprocal Coordinated Flowgate

• RNU – Revenue Neutrality Uplift

• RT – Real‐Time

• RTBM – Real‐Time Balancing Market 

• RTO – Regional Transmission Organization

• SP – Shadow Price

Key Acronyms and Initialisms

7

MARKET TO MARKET OVERVIEWSection 2

8

Market to Market (M2M) Objectives

More efficient re‐dispatch solution for coordinated constraints across multiple 

systems

More consistent pricing profile across the two (2) 

Markets

Enhanced system reliability by pooling Resources from both RTOs to jointly control transmission constraints near the RTO border

Compensation mechanism provided for two‐market congestion management

9

Key Definitions 

Term Definition

Coordinated Flowgates

Flowgates (FGs) on which one entity has significant impacts. 

Reciprocal Flowgates (RCFs)

FGs on which more than one entity has significant impacts. Coordinated for more than one entity and passed the coordination tests. 

Market Flow  The Firm Gen‐to‐Load (GTL) Flows that represent the directional sum of designated network Resources serving designated Network Native Loads within a particular market area. 

Firm Flow Entitlements (FFE)

The firm limit of net Market Flow that a market entity can have on a RCF.  In the interregional coordination process, that extra usage is subject to financial settlement. 

Network Native Load An entity’s Gen‐to‐Load impact on a FG.

10

M2M Process Overview 

1

• Monitoring RTO (MRTO) binds total flow on Reciprocal Coordinated Flowgate (RCF).   

2

• MRTO notifies Non‐Monitoring RTO (NMRTO) to initiate M2M, requesting MW relief on the RCF and providing Shadow Price Limit.

3

• After M2M is initiated, there is a periodic exchange of data (e.g. Shadow Prices (SPs), Market Flows, relief amount, etc.).

11

M2M Process Overview (cont’d.)

4

• NMRTO must have Generation available to respond at a lower SP and the relief request must seek reduced Market Flow.

5

• If the NMRTO responds, it binds the RCF and starts to reduce Market Flow. It can do this by adjusting the RCF limit and re‐dispatching its Generation to control the RCF.

NMRTO controls RCF to either: A. Provide relief requested by MRTO.B. Re‐dispatch up to current SP from 

MRTO.

12

M2M Process Overview (cont’d.)

6• As the MRTO sees reduction in total flows (RCF realizes relief), re‐dispatch costs are reduced, which produces a lower MRTO SP. 

7

• When the MRTO can control the RCF at a lower SP, it may revise the amount of relief requested and sends that amount and updated SP to the NMRTO.

8• Both RTOs continue to re‐dispatch systems respecting the constrained Flowgate (FG).

9• When the MRTO stops binding and no longer produces a SP, the NMRTO stops binding.

13

M2M Process Overview (cont’d.)

10

• The MRTO sends a signal to the NMRTO to close the M2M event and makes a confirmation phone call. 

11

• After the Fact: The RTOs compensate each other for re‐dispatch provided based on Real‐Time (RT) Market Flow of the NMRTO compared to NMRTO FFE and applicable Shadow Prices.

12

• The result of this coordination is a cost‐effective re‐dispatch solution for the combined footprint.

14

MARKET TO MARKET EXAMPLESection 3

15

M2M Process Example – Assumptions

16

MISO is the MRTO

SPP is the NMRTO

MEC is assumed constant

Losses ignored

Various Firm Flow Entitlement (FFE) amounts will be assumed to illustrate the Settlement scenarios 

SF = Shift Factor

In the example on the following slide, assume: 

M2M ExampleSPPMEC = $40

Midwest ISOMEC = $40

• Load X (in MISO) and Load Y (in SPP) are electrically close to each other and have the same impact on Flowgate (FG) “A.”

• The initial SPP Market Flow on FG “A” is 35 MW.

SPP Mkt Flow = 35

17

SF SF

SF

SFSF

M2M Example (cont’d.)

SPP Midwest ISO

The flow on FG “A” increases to 110 MW due to the higher load in MISO.

18

SPPMEC = $40

Midwest ISOMEC = $40

SF SF

SF

SFSF

M2M Example (cont’d.)

SPP Midwest ISO

MISO dispatches Gen 2 and Gen 3 to control FG “A.”

19

SF SF

SF

SFSF

SPPMEC = $40

Midwest ISOMEC = $40

M2M Example (cont’d.)Midwest ISOSPP

• MISO dispatches GEN 2 and GEN 3 to control FG “A.”

• GEN 3 is marginal unit and constraint SP is ($60‐$40)/(‐.2) = ‐$100.

• GEN 2 LMP = $40 + (‐0.3 * ‐$100) = $70.

• LOAD X LMP = $40 + (0.15 * ‐$100) = $25. 20

SF SF

SF

SF SF

SPPMEC = $40

Midwest ISOMEC = $40Shadow Price = ‐$100

M2M Example (cont’d.)Midwest ISOSPP

• MISO notifies SPP to invoke M2M to control FG “A.”

• MISO requests 4 MW of relief at the current SP of ‐$100.

• SPP reduces GEN 1 to provide the relief requested by MISO.21

SF SF

SF

SF SF

SPPMEC = $40

Midwest ISOMEC = $40Shadow Price = ‐$100

M2M Example (cont’d.)Midwest ISOSPP

• GEN 1 is reduced by 12.5 MW (to 187.5 MW) to provide 4 MW of relief.

• The SPP constraint SP is ($22‐$40)/0.32 = ‐$56.25.

• Load Y LMP = $40 + (0.15 * ‐$56.25) = $31.6.22

SPP Mkt Flow = 31

SF SF

SF

SF SF

SPPMEC = $40Shadow Price = ‐$56.25

Midwest ISOMEC = $40Shadow Price = ‐$100

M2M Example (cont’d.)Midwest ISOSPP

With loading decreased on FG “A,” MISO can release the less cost‐effective GEN 3.

23

SF SF

SF

SF SF

SPPMEC = $40Shadow Price = ‐$56.25

Midwest ISOMEC = $40

M2M Example (cont’d.)Midwest ISOSPP

• With GEN 3 offline, GEN 2 becomes new marginal unit for the constraint.

• The Constraint SP is ($58‐$40) / (‐0.3) = ‐$60.

• GEN 3 LMP = $40 + (‐0.2 * ‐$60) = $52.

• LOAD X LMP = $40 + (0.15 * ‐$60) = $31. 24

SF SF

SF

SF SF

SPPMEC = $40Shadow Price = ‐$56.25

Midwest ISOMEC = $40Shadow Price = ‐$60

M2M Example – Observations

• The re‐dispatch cost for the individual markets would have been higher if each RTO had to control all transmission constraints on its own. 

Lower Congestion 

Cost

• When M2M coordination is in effect, the prices at the MISO and SPP border converge better than before. 

More Consistent 

Pricing across RTO Border

• Economic generation in both RTOs is now available for constraint control.

More Reliable Operation

25

MARKET TO MARKET SETTLEMENTSection 4

26

M2M Settlements – Overview

• Key Variables are: 

– Firm Flow Entitlement (FFE)

– Market Flow

– Shadow Prices (SPs)

• Specific rules are defined in the Joint Operating Agreement (JOA) to determine which SP is used in the Settlements calculations.

• Some exceptions to the rules (but not all) are defined in the JOA.

• Payments to SPP from MISO are paid to SPP Market Participants (MPs) via Revenue Neutrality Uplift (RNU).

• Payments from SPP to MISO are charged to SPP MPs via RNU.

27

Reminder: Key Variables

• Net Market Flows(Mkt Flows)

• Firm Flow Entitlements (FFEs)

• Shadow Prices (SPs)

Payment Formula:(NMRTO FFE – NMRTO MktFlow)*SP

Positive = Payment to NMRTONegative = Payment from NMRTO

M2M Settlements – Overview (cont’d.)

JOA Criteria for Settlements is based on three (3) scenarios:

1. NMRTO FFE > NMRTO Mkt Flow; NMRTO SP is used

2. NMRTO FFE < NMRTO Mkt Flow; MRTO SP is used 

3. NMRTO FFE = NMRTO Mkt Flow; Zero Settlement

Example

28

M2M Settlements – Example Midwest ISOSPP

• With GEN 3 offline, GEN 2 becomes new marginal unit for the constraint.

• The Constraint SP is ($58‐$40) / (‐0.3) = ‐$60.

• GEN 3 LMP = $40 + (‐0.2 * ‐$60) = $52.

• LOAD X LMP = $40 + (0.15 * ‐$60) = $31. 29

SF SF

SF

SF SF

SPPMEC = $40Shadow Price = ‐$56.25

Midwest ISOMEC = $40Shadow Price = ‐$60

SPP Mkt Flow = 31

M2M Settlements – Example (cont’d.)

JOA Criteria 1:

• NMRTO FFE > 0

• NMRTO Mkt Flow > 0

• NMRTO FFE > NMRTO Mkt Flow

Since SPP FFE > SPP Mkt Flow; SPP SP will be used for Settlement 

Variables

MISO SP (MRTO) $60 

SPP SP (NMRTO) $56.25

SPP FFE 50 MW

SPP Mkt Flow 31 MW

Payment Formula:(NMRTO FFE – NMRTO MktFlow)*SP(50 – 31)*$56.25 = $1,068.75

Positive means payment toNMRTO. Therefore, MISO pays SPP. SPP then distributes this amount to SPP MPs via RNU.

30

Reminder: Key Variables

• Net Market Flows(Mkt Flows)

• Firm Flow Entitlements (FFEs)

• Shadow Prices (SPs)

Payment Formula:(NMRTO FFE – NMRTO MktFlow)*SP

Positive = Payment to NMRTONegative = Payment from NMRTO

M2M Settlements – Example (cont’d.)

JOA Criteria for Settlements is based on three (3) scenarios:

1. NMRTO FFE > NMRTO Mkt Flow; NMRTO SP is used

2. NMRTO FFE < NMRTO Mkt Flow; MRTO SP is used 

3. NMRTO FFE = NMRTO Mkt Flow; Zero Settlement

Example

31

M2M Settlements – Example (cont’d.)

JOA Criteria 2:

• NMRTO FFE > 0

• NMRTO Mkt Flow > 0

• NMRTO FFE < NMRTO Mkt Flow

Since SPP FFE < SPP Mkt Flow; MISO SP will be used for Settlement 

32

Negative means payment from NMRTO. Therefore, SPP pays MISO. SPP then charges this amount to SPP MPs via RNU.

Variables

MISO SP (MRTO) $60 

SPP SP (NMRTO) $56.25

SPP FFE 25 MW

SPP Mkt Flow 31 MW

Payment Formula:(NMRTO FFE – NMRTO MktFlow)*SP(25 – 31)*$60 = ‐$360.00

M2M Settlements – Exceptions Not in JOA

• When FFE is negative and Market Flow is  greater than the FFE and positive, cap the FFE at zero (0) for settlements.

• When FFE is negative and the Market Flow is greater than the FFE but also negative, there is no settlement.

• When the FFE is negative and the Market Flow is equal to 0, there is no settlement.

33

NMRTO FFE ‐100 MW (Capped at 0)

NMRTO Mkt Flow 50 MW

NMRTO FFE ‐100 MW

NMRTO Mkt Flow ‐50 MW

NMRTO FFE ‐100 MW (Capped at 0)

NMRTO Mkt Flow 0 MW

M2M Settlements – Charge Type

34

RT JOA: RtJoaHrlyAmt a,h,f

Joint Operating Agreement

Charge (or credit) for Real‐Time Balancing Market (RTBM) congestion management coordination between SPP and JOA counterparties.

JOA Calculated Charge or Credit

Questions

35

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 1 of 11

PRR Comments

PRR No. MPRR169 PRR

Title Clear and Unambiguous Must Offer Proposal

Date 3/13/2014

Submitter Name Richard Dillon E-mail Address rdillon@spp.org Company Southwest Power Pool Phone Number 501.614.3228

Comments

FERC ruled in the October 2012 Order (paragraph 451) and reiterated in the September 2013 Order (paragraphs 370 and 373) that “SPP must provide that Market Participants will not be determined to have physically withheld if they are selling into another market at a higher price.” The following changes, highlighted in cyan, clarify the must offer language in regards to the FERC requirement and also synchronize the use of Designated Resource capacity. A resource that is qualified as a Designated Resource capacity is available to the SPP region on an ultimate call basis. If the capacity is also accepted into another region, it must either be accepted into the other region on a non-firm basis or undesignated in the SPP region to eliminate the double counting of the capacity.

Revised Proposed Protocol Language Revision

4.2.1.1 Day-Ahead Market

(1) For the Day-Ahead Market, Market Participants must submit Resource Offers for all Designated

Resources except for Designated Resources that are:

(a) On an outage (e.g. on forced outage, planned outage, or Reserve Shutdown);

(i) The outage must be documented in the outage scheduler tool, and the Resource

must have a Commitment Status of Outage;

(b) Variable Energy Resources; or

(i) Designated Resources that are Variable Energy Resources are allowed, but are not

required, to be offered in the Day-Ahead Market;

(c) Not registered.

(2) Market Participants must include in their Resource Offers the full amount of physical capacity

available as reflected in the Resource’s submitted Maximum Normal Capacity Operating Limit

and Maximum Emergency Capacity Operating Limit to the extent that available amounts of

Resource capacity are not in excess of:

(a) The Designated Resource volume; or

(a)(b) The capacity that is required to serve the hourly load as described in the NITSA

from the Designated Resource that is external to the SPP BA.

(3) A Market Participant may satisfy this requirement by offering Resources with a Commitment Status of

Market, Self, or Reliability.

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 2 of 11

(2)(4) A Market Participant that is offering a Designated Resource into another region’s market

at a higher price must undesignate the Resource for the period of time that the Resource is

offered into the other market. In addition, Market Participants will not be determined to have

physically withheld if they are selling into another market at a higher price.

(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:

(1) A Market Participant’s load for an Asset Owner for purposes of this section shall be equal

to the Market Participant’s maximum hourly Reported Load for that Asset Owner for the

Operating Day. When an Asset Owner selling power under a bilateral contract has

registered the load of the Asset Owner that is buying power under the bilateral contract as

described under Section 6.2.8, the buyer’s Reported Load shall be reduced by the amount

of the buyer’s load registered by the seller and the seller’s Reported Load shall be increased

by the amount of the buyer’s load registered by the seller.

(2) A Market Participant’s daily Operating Reserve obligation for an Asset Owner shall be

equal to the sum of that Market Participant’s maximum daily Regulation-Up, Regulation-

Down and Contingency Reserve obligation for that Asset Owner as calculated by SPP as

described in Section 4.1.3(4).

(3) Resources submitted with a Commitment Status of Market, Self or Reliability may be used

to satisfy this requirement.

(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

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 3 of 11

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

the JOU Individual Resource Option or the JOU Combined 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.

(B) A Market Participant’s compliance with the must-offer obligation for an Asset Owner is as

follows:

(1) A Market Participant that has offered all of its available Resources for an Asset Owner with

a Commitment Status of Market, Self, or Reliability for an hour of the Operating Day is

deemed to be compliant with the must-offer requirement for that Asset Owner for that hour

regardless of its maximum hourly Reported Load and/or Operating Reserve obligation.

(a) A Market Participant that does not have any registered Resources for an Asset Owner

has met the must-offer requirement for that Asset Owner because it does not have any

Resources with a Commitment Status of Not Participating for that Asset Owner.

(2) A Market Participant that does not meet the condition described in (B)(1) above for an

Asset Owner for an hour of the Operating Day, but has net resource capacity for that Asset

Owner for that hour greater than or equal to 90% of its load for that Asset Owner, as

described in (A)(1) above, is deemed to be compliant with the must-offer requirement for

that Asset Owner for that hour.

(3) To the extent a Market Participant does not meet the conditions for an Asset Owner

described in either Section (B)(1) and (2), the Market Participant shall be deemed

noncompliant with the must-offer requirement for that Asset Owner for that hour and will

be assessed a penalty for that Asset Owner for that hour as described in Section 4.2.1.1.1.

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 4 of 11

(4) Resources used as the source of a GFA Carve Out must be offered, if available, with a

sufficient capacity to cover the GFA Carve Out Schedule. GFA Carve Out treatment is

only available to the extent that the Resources are offered into the DA Market using a

Commitment Status of Market, Self or Reliability. To the extent the source is external, an

Import Interchange Transaction must be submitted in the DA Market with a sufficient

capacity to cover the GFA Carve Out Schedule.

(C)(A) The Market Monitor shall monitor a Market Participant’s load, Operating Reserve

obligation, offered Resources and net resource capacity, for an Asset Owner for each hour of the

Operating Day to determine whether the Market Participant has complied with the must offer

obligation for that Asset Owner set forth in Section 4.2.1.1 B.

4.2.1.1.1 Penalty Calculation

For each hour of the Operating Day that a Market Participant is found to be noncompliant as determined

by the conditions set forth in Sections 4.2.1.1 B, that Market Participant shall be assessed a penalty. The

penalty amount and the distribution of penalty revenues shall be determined as follows:

(1) An Asset Owner’s penalty amount in each hour is calculated by multiplying the Asset Owner’s

Must-Offer Penalty MW by the maximum of zero or the Asset Owner’s Must-Offer Penalty

LMP for that hour.

(a) Asset Owner Must-Offer Penalty MW is equal to the minimum of (i) the Asset Owner

Shortage MW or (ii) the Asset Owner Not Offered MW;

(i) Asset Owner Shortage MW is calculated as the difference between:

(1) 90% of the Market Participant’s load for an Asset Owner as described in

4.2.1.1A.(1); and

(2) The Market Participant’s net resource capacity for an Asset Owner as

described in 4.2.1.1 A(3).

(ii) Asset Owner Not Offered MW is calculated as the sum of the reference levels for

the Maximum Economic Capability Operating Limit, as determined by the

process in Section 8.2.2.7, less derate MW amounts approved and recorded in the

outage scheduler tool for the Market Participant’s Resources for that Asset Owner

with a Commitment Status of Not Participating.

(b) The Must-Offer Penalty LMP is calculated as the weighted average of the Day-Ahead

LMP for the Market Participant’s Resources for that Asset Owner with a Commitment

Status of Not Participating, where the weights for the calculation are the corresponding

Not Offered MWs.

(2) In any hour in which must-offer penalty revenues are collected, such revenues shall be

distributed to Market Participants for an Asset Owner on a pro-rata basis for that Asset Owner’s

Resources that were offered in compliance with the must-offer requirement in Section 4.2.1.1.

The pro-rata share shall be equal to the ratio of (i) each compliant Asset Owner load, as

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 5 of 11

described in 4.2.1.1 for that hour to (ii) the sum of all compliant Asset Owner loads for that

hour.

4.5.11 Miscellaneous Amount

(1) In certain circumstances, it may be necessary to recalculate or make changes to previously billed

charges that cannot be handled though a standard final settlement or resettlement execution for

that operating day. This is anticipated to occur only on an exception basis. SPP will manually

calculate the adjustment and post as a manual adjustment to the initial, final, and/or resettlement

statement, regardless of the Operating Day in question. A comment will be added to the Bill

Statement to alert the reader to the reason for the adjustment and the effective Operating Day(s).

SPP will post supporting documentation for the manual calculation of any miscellaneous charge

to the Portal no later than the time the Settlement Statement including the miscellaneous charge

has been posted. In some situations the charge or credit assessed must be excluded from

Revenue Neutrality Uplift calculations such that SPP is left with a net receivable or payable

amount for the settlement of the OD.

(2) In addition, through Balancing Authority Agreements with adjacent external Balancing

Authorities, SPP may supply Emergency Export Interchange Transactions when requested by the

applicable external Balancing Authority or SPP may request, under SPP Emergency conditions,

that applicable external Balancing Authorities supply Emergency Import Interchange

Transactions to SPP. To the extent that such transactions are confirmed, credits to SPP for

Emergency Export Interchange Transactions and charges to SPP for Emergency Import

Interchange Transactions are included in this charge type.

(3) In addition, a local transmission operator may require commitment, decommitment, or dispatch

instructions to be issued to one or more Resources in order to solve a reliability issue. Payments

to Resource Asset Owners as described under Sections 4.5.9.8, 4.5.9.9 and charges to Asset

Owners as described under Section 4.5.9.10 associated with such commitment, decommitment,

or dispatch instructions are included in this charge type.

(4) In addition, SPP may impose penalties for noncompliance with the Day-Ahead Market must-

offer requirement as described under Section 4.2.1.1.1. Any penalties assessed to noncompliant

Asset Owners, and the distribution of those penalties by load-ratio share, excluding the

noncompliant Asset Owners, are included in this charge type.

(5)(4) A miscellaneous charge type will be utilized for each distinct charge type and any other

charges and credits not specifically accounted for under a distinct charge type. Miscellaneous

charges and credits to the affected Asset Owners are represented for each Operating Day as

follows:

MiscDlyAmt a, ct, s, rnu, d

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 6 of 11

(6)(5) For each Asset Owner associated with Market Participant m, a daily amount is

calculated. The net daily amount is calculated as follows:

MiscAoAmt a, m, d = ∑ct

∑s∑rnu

MiscDlyAmt a, ct, s, rnu, d

(7)(6) 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:

MiscMpAmt m, d = ∑a

MiscAoAmt a, m, d

6.2.8 Load Transfers Relating to Bilateral Contracts

A Market Participant that is selling firm power to another Market Participant under a bilateral contract

may, with the agreement of the buyer, register all or a portion of the buyer’s load as its load asset as

described under Section 2.2(11) of Attachment AE to the Tariff. For the purposes of Section 4.2.1.1,

such registration of the buyer’s load by the seller shall be accounted for by including such load in the

seller’s Reported Load and not including such load in the buyer’s Reported Load, as described under

Section 4.2.1.1(A)(1), and such associated bilateral contracts shall not be included in either the buyer’s

or seller’s net resource capacity described under Section 4.2.1.1(A)(4).

8.2.7 Sanctions for Noncompliance with the Day-Ahead Market Must Offer Requirement

In the case that a Market Participant with registered load is found to be noncompliant for an Asset

Owner associated with that registered load as determined by the conditions set forth in Sections 4.2.1.1,

the Market Participant shall be assessed a penalty for that Asset Owner as described in 4.2.1.1.1 (1)(a).

The penalty amount shall be equal to the Day Ahead Market LMP associated with the withheld capacity

as described in Section 4.2.1.1.1(1)(b).

The Market Monitor will monitor for, and report to the Commission’s Office of Enforcement (“OE”),

manipulative behavior associated with Day Ahead Offers, including (but not limited to) monitoring

load-serving Market Participants who purposefully underestimate peak loads. The Market Monitor will

also report to OE any locational problems, such as deliverability issues, associated with load-serving

Market Participants’ offers in the Day Ahead market, any identified efforts by Market Participants to

raise prices in the real-time market by limiting Day Ahead offers, and the effects of any such efforts

upon make whole payments.

8.2.87 Maintenance and Implementation of the Mitigation Protocols

The Transmission Provider is responsible for implementing the market power mitigation measures as

approved by FERC. The Transmission Provider is also responsible for periodically reviewing and

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 7 of 11

recommending revisions to the mitigation protocols and supporting SPP Regulatory Staff in obtaining

approval from FERC for any such updates with input and support from the MWG.

Proposed Tariff Language Revision

Attachment AE

2.2 Application and Asset Registration

… (10) A wind-powered Variable Energy Resource with (1) an interconnection agreement

executed after May 21, 2011 or (2) an interconnection agreement executed on or prior to

May 21, 2011 and that commenced Commercial Operation on or after October 15, 2012

must register as a Dispatchable Variable Energy Resource. A wind-powered Variable

Energy Resource with an interconnection agreement executed on or prior to May 21,

2011 may register as a Dispatchable Variable Energy Resource if it is capable of being

incrementally dispatched by the Transmission Provider. Variable Energy Resources with

fuel sources other than wind may optionally register as a Dispatchable Variable Energy

Resource. Otherwise, Variable Energy Resources must register as Non-Dispatchable

Variable Energy Resources. A Qualifying Facility exercising its rights under PURPA to

deliver its net output to its host utility may register as a Non-Dispatchable Variable

Energy Resource or a Dispatchable Variable Energy Resource as described in the Market

Protocols. Any Resource that has previously registered as a Dispatchable Variable

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

Resource.

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

may, with the agreement of the buyer, register all or a portion of the buyer’s load as its

load asset. For purposes of this Section 2.2(11) of this Attachment AE, the sale of firm

power shall refer to power sales deliverable with firm transmission service, with the

supplier assuming the obligation to serve the buyer’s load with both capacity and energy.

For the purposes of Section 2.11.1 of this Attachment AE, such registration of the buyer’s

load by the seller shall be accounted for by including such load in the seller’s Reported

Load and not including such load in the buyer’s Reported Load, as described under

Section 2.11.A(1) of this Attachment AE, and such associated bilateral contracts shall not

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 8 of 11

be included in either the buyer’s or seller’s net resource capacity described under Section

2.11.A(4) of this Attachment AE.

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

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

designate the GFA Responsible Entity within the timeframe set forth in Section 2.2 (1) of

Attachment AE.

…

2.11.1 Day-Ahead Market

(1) For the Day-Ahead Market, Market Participants must submit Resource Offers for all Designated

Resources except for Designated Resources that are:

(a) On an outage (e.g. on forced outage, planned outage, or Reserve Shutdown);

(i) The outage must be documented in the outage scheduler tool, and the Resource

must have a commitment status as described in Section 4.1(10)(d) of this

Attachment AE;

(b) Variable Energy Resources; or

(i) Designated Resources that are Variable Energy Resources are allowed, but are not

required, to be offered in the Day-Ahead Market;

(c) Not registered.

(2) Market Participants must include in their Resource Offers the full amount of physical capacity

available as reflected in the Resource’s submitted Maximum Normal Capacity Operating Limit

and Maximum Emergency Capacity Operating Limit to the extent that available amounts of

Resource capacity are not in excess of:

(a) The Designated Resource volume; or

(a)(b) The capacity that is required to serve the hourly load as described in the NITSA

from the Designated Resource that is external to the SPP BA.

(3) A Market Participant may satisfy this requirement by offering Resources with a commitment

status indicating either that the Market Participant is self-committing the Resource, the Resource

may be committed by the Transmission Provider, or the Resource may be committed by the

Transmission Provider only to alleviate an anticipated Emergency Condition or Local Reliability

Issue, as specified in Sections 4.1(10)(a) and 4.1(10)(b), and 4.1(10)(c) of this Attachment AE.

(4) A Market Participant that is offering a Designated Resource into another region’s market at a

higher price must undesignate the Resource for the period of time that the Resource is offered

into the other market. In addition, Market Participants will not be determined to have physically

withheld if they are selling into another market at a higher price.

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 9 of 11

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:

(1) A Market Participant’s load for an Asset Owner for purposes of this section shall be

equal to that Market Participant’s maximum hourly Reported Load for an Asset Owner

for the Operating Day. Such Asset Owner’s Reported Load shall include load registered

as described under Section 2.2(11) of this Attachment AE, where the buyer’s Reported

Load shall be reduced by the amount of the buyer’s load registered by the seller and the

seller’s Reported Load shall be increased by the amount of the buyer’s load registered by

the seller.

(2) A Market Participant’s daily Operating Reserve obligation for an Asset Owner shall be

equal to the sum of that Market Participant’s maximum daily Regulation-Up, Regulation-

Down and Contingency Reserve obligations for an Asset Owner as estimated by the

Transmission Provider in accordance with Section 3.1.4(3) of this Attachment AE.

(3) A Market Participant may satisfy this requirement by offering Resources for an Asset

Owner with a commitment status indicating either that the Market Participant is self-

committing the Resource, the Resource may be committed by the Transmission Provider,

or the Resource may be committed by the Transmission Provider only to alleviate an

anticipated Emergency Condition or Local Reliability Issue, as specified in Sections

4.1(10)(a) and 4.1(10)(b), and 4.1(10)(c) of the Attachment AE.

(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.

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 10 of 11

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 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

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.

B. A Market Participant’s compliance with the must offer obligation for an Asset Owner is as

follows:

(1) A Market Participant that has offered all of its available Resources for an Asset Owner,

with a commitment status described in Sections 4.1(10)(a), 4.1(10)(b), and/or 4.1(10)(c)

of this Attachment AE, for an hour of the Operating Day is deemed to be in compliance

with the must offer requirement for that Asset Owner for that hour regardless of its

maximum hourly Reported Load and/or, Operating Reserve obligation.

(2) A Market Participant that does not meet the condition described in Section 2.11.1(B)(1)

of this Attachment AE for an Asset Owner for an hour of the Operating Day, but has net

resource capacity for that Asset Owner for that hour greater than or equal to 90% of its

load for that Asset Owner as described in Section 2.11.1(A)(1) of this Attachment AE is

deemed to be in compliance for that Asset Owner with the must offer requirement for that

hour.

(3) To the extent that a Market Participant does not meet the conditions described in either

Section 2.11.1(B)(1) or (2) for an Asset Owner, the Market Participant shall be deemed

noncompliant with the must offer requirement for that Asset Owner for that hour and will

Attachment 7 - MPRR 169 SPP Comments 3-13-2014_MWG Page 11 of 11

be assessed a penalty for that hour as determined in Section 3.9 of Attachment AF of this

Tariff.

C. Market Monitor shall monitor a Market Participant’s Load, Operating Reserve obligation,

offered Resources and net resource capacity, for an Asset Owner for each hour of the Operating

Day to determine whether the Market Participant has complied with the must offer obligation set

forth in Section 2.11.1(B).

Attachment AF 3.9 Sanctions for Noncompliance with the Day-Ahead Market Must Offer Requirement

A. In the case that a Market Participant is found to be noncompliant for an Asset

Owner as determined by the conditions set forth in Section 2.11.1 of Attachment

AE, the Market Participant shall be assessed a penalty for that Asset Owner by the

Transmission Provider for each megawatt of withheld capacity below the 10%

tolerance band. The penalty amount shall be equal to the Day-Ahead Market

LMP associated with the withheld capacity.

B. The Market Monitor will monitor for, and report to the Commission’s Office of

Enforcement, or its successor organization, manipulative behavior associated with

Day-Ahead Offers, including (but not limited to) monitoring load-serving Market

Participants who do not offer enough net resource capacity to meet their

maximum hourly Reported Load. The Market Monitor will also report to the

Commission’s Office of Enforcement or its successor organization any locational

problems, such as deliverability issues, associated with load-serving Market

Participants’ offers in the Day-Ahead Market, any identified efforts by Market

Participants to raise prices in the RTBM by limiting Day-Ahead Offers, and the

effects of any such efforts upon make whole payments.

Revised Proposed Criteria Language Revision

N/A

MWG Strategic Plan Inputs

March 18‐19, 2014

Market Working Group

Three Foundational Strategies 

3

Develop Efficient Market Processes*

• Consider a Renewable Energy Credit (REC) Market

• Enhance Outage Coordination for Market Efficiency 

• Consider Implementing a Pre‐Ramp Operational Plan Based on a Pre‐RTBM Study

• Consider a new Ramp product in Marketplace 

* Listed in no particular order

4

Develop Efficient Market Processes• Consider further Cost Allocations for cost causers. 

– Enhance the Market Design to further allocate charges to the cost causers

• Consider further DC Ties Integration  

– Reduce operational and economic impediments to maximize the use of DC Ties

• Evaluate Demand Response in Marketplace

• Align Transmission Service Process with Marketplace

– Update transmission service reservations granted with firm with re‐dispatch Tariff language to better align with the Market dispatch rules

– Update the process for selling Transmission Service for short‐term and long‐term; align AFC and Aggregate Study Process with the Marketplace

– Update the PORs/PODs to capture the effects of implementing SPP consolidated Balancing Authority and the Marketplace

– Synchronize timing requirements for securing short‐term transmission service with Marketplace

5

Develop Efficient Market Processes

• Improve Generation Interconnection Agreements (GIA) to incorporate Marketplace requirements

• Evaluate Resource adequacy requirements to reflect the implementation of the Marketplace

• Improve Gas‐Electric Coordination

– Improve extreme weather event

– Improve alignment of gas nomination timeline to the Day‐Ahead Market close

–

6

Market Par t i c ipa nt Guide : SPP 2 014 Conges t ion

Hedg ing Published: January 31, 2014

Revised: March 11, 2014

Southwest Power Pool, Inc.

Table of Contents

Overview .......................................................................................................................................................2

Objectives ........................................................................................................................................2

2014 Schedule ...............................................................................................................................................2

Process Schedule ..............................................................................................................................2 Remaining Interim TCR Markets Schedule ............................................................................................. 2 First Annual Iteration Process .................................................................................................................. 2

Process Detail Calendar ...................................................................................................................3 Remaining Interim Process Detail Calendar ............................................................................................ 3 First Annual Process Detail Calendar ...................................................................................................... 4

Deadlines..........................................................................................................................................4 OASIS data............................................................................................................................................... 4 GFA data .................................................................................................................................................. 5 Historic Peak Load ................................................................................................................................... 5 Outages ..................................................................................................................................................... 5

Market Timing .................................................................................................................................5

Communications ..........................................................................................................................................6

General Information and Inquiries ...................................................................................................6

Issue Reporting ................................................................................................................................6

Public Posting ..................................................................................................................................6

Other Congestion Hedging Documents ......................................................................................................6

Congestion Hedging Modeling Practices ................................................................................................. 6 Congestion Hedging User Guides ............................................................................................................ 7 FAQ .......................................................................................................................................................... 7 Related SPP Tariff .................................................................................................................................... 7 Related Market Protocols ......................................................................................................................... 7 Integrated Marketplace Reference Guide for MPs ................................................................................... 7

SPP 2014 Congestion Hedging 1

Southwest Power Pool, Inc.

Overview

Objectives This document is intended for Southwest Power Pool (SPP) Market Participants and provides information for preparation of Integrated Marketplace’s 2014 Congestion Hedging (aka TCR) activities.

2014 Schedule

Process Schedule

Remaining Interim TCR Markets Schedule The remaining interim production schedule for March 1, 2014 through May 31, 2014 shall be as follows:

(1) March 2014 Monthly (a) ARR Allocation: 2.3.2014 – 2.7.2014 (b) TCR Auction: 2.10.2014 – 2.14.2014

(2) April 2014 Monthly (a) ARR Allocation: 3.17.2014 – 3.21.2014 (b) TCR Auction: 3.24.2014 – 3.28.2014

(3) May2014 Monthly (a) ARR Allocation: 4.7.2014 – 4.11.2014 (b) TCR Auction: 4.14.2014 – 4.18.2014

The Monthly ARR Allocation and Monthly TCR Auction processes shall include: (1) March, April, and May periods (2) On-peak and off-peak products (3) March, April, and May 1-round ARR Allocation: 100% system capacity (4) March, April, and May 1-round TCR Auction: 100% system capacity

First Annual Iteration Process The first iteration production schedule for June 1, 2014 through May 31, 2015 shall be as follows:

(1) Annual Candidate ARR Verification: 3.6.2014 – 3.19.2014 (2) Annual 3-round ARR Allocation: 4.7.2014 –4.25.2014 (3) Annual 1-Round TCR Auction: 5.5.2014 – 5.16.2014 (4) Incremental ARR Allocation and Monthly TCR Auction

(a) July: 6.9.2014 – 6.20.2014 (b) August: 7.14.2014 – 7.25.2014 (c) September: 8.11.2014 – 8.22.2014 (d) October: 9.8.2014 – 9.26.2014 (e) November: 10.6.2014 – 10.27.2014 (f) December: 11.3.2014 – 11.24.2014

SPP 2014 Congestion Hedging 2

Southwest Power Pool, Inc.

(g) January (15): 12.1.2014 – 12.19.2014 (h) February (15): 1.9.2015 – 1.30.2015 (i) March (15): 2.6.2015 – 2.27.2015 (j) April (15): 3.9.2015 – 3.27.2015 (k) May (15): 4.6.2015 – 4.24.2015

The first iteration Annual ARR Allocation and TCR Auction processes shall include: (1) June, July, August, September, Fall, Winter, and Spring periods (2) On-peak and off-peak products (3) All periods 3-round ARR: 100% system capacity (4) June 1-round TCR: 100% system capacity (5) July, August, and September 1-round TCR: 90% system capacity (6) Fall, Winter, and Spring 1-round TCR: 60% system capacity

The Monthly ARR Allocation and Monthly TCR Auction processes shall include: (1) Following Month, e.g. process executed in March offers April TCR’s (2) On-peak and off-peak products (3) Following Month 1-round ARR Allocation: 100% system capacity (4) July, August, and September 1-round TCR Auction: 100% system capacity (5) Fall, Winter, and Spring 2-round TCR Auction: +50% and 100% system capacity

Process Detail Calendar

Remaining Interim Process Detail Calendar

SPP 2014 Congestion Hedging 3

Southwest Power Pool, Inc.

First Annual Process Detail Calendar1

Deadlines

Credit Posting Financial Security needs to be received by the SPP Credit Department 5 business days before the start of the corresponding TCR Auction Bid Window to allow time for processing and to apply funds to Market Participants respective accounts. An email reminding Market Participants of this date will also be sent.

1 Previously posted schedule has changed to shift forward the annual candidate ARR verification window and to better accommodate holidays throughout the year.

SPP 2014 Congestion Hedging 4

Southwest Power Pool, Inc.

OASIS data Any transmission service that a Market Participant would like to be included as a Candidate ARR for the appropriate ARR allocation must be in OASIS by the day prior to start of the corresponding verification period.

GFA data Any Grandfathered Agreements a Market Participant would like to have included in an ARR Allocation must be submitted 5 business days before the start of the corresponding verification period. Any GFAs that have already been submitted will be maintained.

Historic Peak Load Market Participants with NITS transmission service should validate their historic peak load for the year 2013. This should be reported to SPP, as outline in the Communications section of this document, by February 28, 2014. SPP will use this information to verify network nomination caps and overall nomination caps.

Outages Transmission Owners that wish to have their outages included in a respective TCR market will need to have submitted the outage in CROW at least 10 business days before the corresponding model posting date. Any outages submitted less than 10 business days before the model posting date may not be included in the appropriate TCR market(s). For any additional details on outages taken in the SPP congestion hedging process, see the TCR Market Modeling Processes document2 posted on spp.org.

Market Timing Market Model Posting: 16:00; on designated model posting date Market Window Open: 09:00; first day of market window Market Window Close: 16:00; last day of market window Market Results Posting: 16:00; day of market posting

2 SPP.org > Integrated Marketplace > About the Program > TCR Project Folder

SPP 2014 Congestion Hedging 5

Southwest Power Pool, Inc.

Communications

General Information and Inquiries SPP will distribute information and general announcements related to the TCR Market to Market Participants through an optional Message 911 service. Those who opt-in to the Message 911 service can receive notices and announcements about the opening, closing and posting of data surrounding TCR Markets. To participant in the Message 911 service, please use the SPP Request Management System with a request to be added. The Request Management System is also the quickest way for inquiries and concerns to be addressed by the Congestion Hedging group.

Issue Reporting Any immediate issues that are discovered should be reported to your Customer Relations Representative, via phone, email, or the Request Management System. SPP staff will investigate the reported issue and respond with a resolution.

Public Posting SPP will post historical TCR market allocation and auction results on its Marketplace Portal3. SPP will post the following information for allocations: MW award with Source to Sink path and time of use and additionally binding constraints. SPP will post the following information for auctions: MW award with Market Participant name, Source to Sink path, time of use and nodal price and additionally binding constraints.

Other Congestion Hedging Documents

There are other important documents that provide detailed information on key Congestion Hedging topics. Below are the links to these documents4:

Congestion Hedging Modeling Practices For more details on SPP’s Congestion Hedging modeling practices, see the TCR Market Modeling Processes document.

3 SPP.org > Marketplace Portal > Public > TCR Market 4Several of these are found by navigating to SPP.org > Integrated Marketplace > About the Program > TCR Project Folder

SPP 2014 Congestion Hedging 6

Southwest Power Pool, Inc.

Congestion Hedging User Guides For help in using the TCR portion of the Marketplace Portal, look into the Market User Interface (MUI) User Guide. For help with the TCR MUI’s API, see the TCR API Specifications files for guidance.

FAQ To see the TCR-related frequently asked questions, filter this list Integrated Marketplace FAQs for TCR.

Related SPP Tariff For the Congestion Hedging portion of the SPP Tariff, see Attachment AE Section 7.

Related Market Protocols For the Congestion Hedging portion of the SPP Integrated Marketplace Protocols, see Section 5.

Integrated Marketplace Reference Guide for MPs For a reference guide on the entire Integrated Marketplace, see the Integrated Marketplace Reference Guide for MPs.

SPP 2014 Congestion Hedging 7

2014 March Monthly Auction Summary

March 19, 2014

Ty Mitchell

Lead Engineer, Congestion Hedging

Objectives

• Monthly Model Updates

• Monthly Participation

• Allocation Results

• Auction Results

• Monthly Constraints

• Auction Revenue

2

MONTHLY MODEL UPDATES

3

Outages Increased

4

104

35

0 10 20 30 40 50 60 70 80 90 100

Mar_14

Number of Outages

ANNUAL

MONTHLY

Expanded Limits

• Per SPP Tariff, limits must be expanded to allow for previously allocated ARRs 

o Caused primarily due to 100% Annual Allocation with limited outage knowledge

o As a result the grid may be overloaded and this may reduce the number of observed constraints

• Expanded Limts:

o March On‐Peak: 20 limits expanded

o March Off‐Peak: 25 limits expanded

5

MONTHLY PARTICIPATION

6

Participation

• Overall participation decreased from Annual to Monthly

• Financial Player participation increased

7

Participation Decreased

8

24 24

12 13

33 34

11 11

21 19

5

3

2824

14

14

Mar_14_OFF Mar_14_ON

0

5

10

15

20

25

30

35

40

451 2 3 4 5 6 7 8 9 10 11

Number of Asset Owners

Annual Allocation ‐ NITS Annual Allocation ‐ PTP OnlyAnnual Auction ‐ AO with TSRs Annual Auction ‐ Financial PlayerMonthly Allocation ‐ NITS Monthly Allocation ‐ PTP OnlyMonthly Auction ‐ AO with TSRs Monthly Auction ‐ Financial Player

ANNUAL MONTHLY ANNUAL MONTHLY

ALLOCATION RESULTS

9

Allocation Results

• 100% of grid was made available in Annual Allocation

o Depending on topological changes volumes should be expected to be low as compared to the Annual Allocation    

• Incremental Entitlements have become available since the last annual process

o Were not previously able to nominate

• Some leftover Entitlements also available from annual process

10

Allocation Results

11

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

MW

Baseloading ARRs Baseloading TCRsNominated cARR MW Allocated ARR MW

Mar_14_ON Mar_14_OFF

30% Allocated 29% Allocated

Annual Process

Annual Process

Incremental Service

12

164.1

150.4

326.2

392.1

1,317

1,317

0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400

Mar_14_O

NMar_14_O

FF

MW

CARR Requested Awarded

AUCTION RESULTS

13

Auction Results

• Self‐Converts attempted 

– About 95% (Annual and Monthly)

• Self‐Converts awarded

– About 96% (Annual and Monthly)

– No SC curtailment in Monthly

• Bid to Self‐Convert ratio remains high

– Average 9.5 to 1 in Annual

– Average 13 to 1 in Monthly

14

Substantial Self‐Converts

15

Mar_14_ON Mar_14_OFF

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

28,000

30,000

32,000

1 2 3 4 5 6 7 8 9

MW

Annual ARRs Monthly ARRs

Annual SC Attempted Monthly SC Attempted

Annual SC Awarded Monthly SC AwardedARRs

ARRs

Attempted Self‐Converts

Attempted Self‐Converts

Awarded Self‐Converts

Awarded Self‐Converts

Auction Results

16

0

400

800

1,200

1,600

2,000

2,400

2,800

Mar_14_ON Mar_14_OFF

Number of Bids/Self‐Converts

Annual Self‐Converts Monthly Self‐Converts

Annual Bids Monthly Bids

MONTHLY CONSTRAINTS

17

Monthly Binding Constraints

• Constraints result in price separation

• Constraints expected from increased system loading

o Bids can provide counterflow and relieve prevailing flow

18

Monthly Binding Constraints

19

98

11

910 10

26

2120

25

1110

30

28

0

5

10

15

20

25

30

Mar_14_ON Mar_14_OFF

Number of Constraints

Binding Constraints (Annual Allocation Rnd 1) Binding Constraints (Annual Allocation Rnd 2)

Binding Constraints (Annual Allocation Rnd 3) Binding Constraints (Annual Auction)

Monthly Expanded Limits Binding Constraints (Monthly Allocation)

Binding Constraints (Monthly Auction)

ANNUAL MONTHLY ANNUAL MONTHLY

AUCTION REVENUE

20

Auction Revenue

• Revenue Positive in On‐peak and Off‐peak

• No extremes in ACP prices

– Max hourly spread ~$16

21

Revenue Waterfall – March On‐Peak

22

$1,158,089

‐$2,400,000

‐$1,800,000

‐$1,200,000

‐$600,000

$0

$600,000

$1,200,000

$1,800,000

$2,400,000

ARR Credit SC Charge Pos Buy Bid Neg Buy Bid Pos Sell Bid Neg Sell Bid NET Revenue

Revenue Waterfall – March Off‐Peak

23

$286,312

‐$2,400,000

‐$1,800,000

‐$1,200,000

‐$600,000

$0

$600,000

$1,200,000

$1,800,000

$2,400,000

ARR Credit SC Charge Pos Buy Bid Neg Buy Bid Pos Sell Bid Neg Sell Bid NET Revenue

QUESTIONS?

24

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 1 of 37

PRR Recommendation Report

PRR No. 171 PRR

Title LTCR Clarifications

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 – If yes, estimated cost: No

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: 3.2; 5; 5.1.1; 5.1.2; 5.2.6; 5.3.3; 5.3.4; 5.4.1; 5.4.4; 5.5.2; 5.5.3; 5.6.3; Title: Transmission Congestion Rights Markets; Transmission Congestion Rights Markets Process; Transmission Service Verification; Candidate LTCRs/ARRs; LTCR Selections and Awards; Simultaneous Feasibility; Annual ARR Awards; TCR Bid and Offer Submittal; Annual TCR Awards; Monthly ARR Nominations; Simultaneous Feasibility; Monthly TCR Auction Clearing and Simultaneous Feasibility; Protocol Version: 19.1

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description

These changes preserve the original intent of the MPRR 138 design by directly converting awarded LTCRs into TCRs prior to the ARR Annual Allocation. These TCRs are then directly modeled as fixed injections and withdrawals as an input into both the Annual ARR Allocation and Annual TCR Auction. This change ensures that LTCRs holder receive their LTCRs at zero cost and allows the associated TCRs to be resold in the Annual TCR Auction. Changes are also included that clarify that total LTCR selection is limited to a maximum amount.

Tariff Implications or Changes

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

Attachment AE Section 1.1 Definitions; 7.0 Transmission Congestion Rights Markets; 7.1.1 Transmission Service Verification; 7.1.2 Candidate Long-Term Congestion Rights/Auction Revenue Rights; 7.1.3 Auction Revenue Right Nomination Cap; 7.2 Annual Long-Term Congestion Right Allocation; 7.2.4 LTCR Selection and Awards; 7.3.3 Annual Auction Revenue Right Awards; 7.4 Annual Transmission Congestion Right Auction; 7.4.3 Annual Transmission Congestion Right Auction Clearing and Simultaneous Feasibility; 7.6.3 Monthly Auction Revenue Right Nominations;

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 2 of 37

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: 3/18/2014 Vote: Unanimously Approved

Opposed: N/A

Abstained: N/A

RTWG Review Date of Vote: Vote:

ORWG Review Date of Vote: Vote:

CAWG Review Date of Vote: Vote: RSC Review Date of Vote: Vote:

MOPC Recommendation Date of Vote: Vote:

Board Review Date of Vote: Vote:

Date 3/12/2014

Sponsor Name Debbie James E-mail Address djames@spp.org Company Southwest Power Pool Phone Number 501.614.3577

Comments Received Comment Author Micha Bailey on behalf of MWG Date 3/18/2014

Comment Description Language was added to Section 5.3.3(2). This new language helps clarify what happens to TCRs associated with LTCRs that have not been surrendered. Language was added to Section 5.5.2 for Monthly ARR Nominations. This new language clarifies how the nomination process is currently working now.

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 171 Recommendation Report 3/18/2014 Page 3 of 37

3.2 Transmission Congestion Rights Markets

The structure of the TCR Markets includes allocation of Long-Term Congestion Rights (LTCRs)

to Eligible Entities 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. Load Serving

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

Entities that are not LSEs. Candidate LTCRs are only associated with eligible long-term

firm transmission service with rollover rights;

(2) All Candidate LTCRs are modeled in order to determine simultaneous feasibility of the

Candidate LTCRs. LTCRs are only awarded up to the selected amount of simultaneously

feasible Candidate LTCRs;

a. Candidate LTCRs are evaluated for simultaneous feasibility for flows in the

prevailing direction only with no simultaneous consideration of LTCR 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;

(3) Awarded LTCRs 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;

Comment [MPRR138.1]: MPRR138 Awaiting FERC filing

Comment [MPRR138.2]: MPRR138 Awaiting FERC filing

Comment [MPRR138.3]: MPRR138 Awaiting FERC filing

Comment [MPRR138.4]: MPRR138 Awaiting FERC filing

Comment [MPRR138.5]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 4 of 37

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. Awarded LTCRs may be surrendered in subsequent years at the Market

Participant's request;

(4) Awarded LTCRs are initially ARRs which will automatically be self-directly converted

to TCRs prior to the annual ARR allocation for the current allocation year. in the annual

ARR allocation process.

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. Awarded LTCRs are

converted to ARRs and included in the total ARR awards for settlement purposes;

(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. ARRs

associated with LTCRs are automatically self-converted into TCRs for settlement

purposes. 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

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

Comment [MPRR138.6]: MPRR138 Awaiting FERC filing

Comment [MPRR138.7]: MPRR138 Awaiting FERC filing

Comment [MPRR138.8]: MPRR138 Awaiting FERC filing

Comment [MPRR138.9]: MPRR138 Awaiting FERC filing

Comment [MPRR138.10]: MPRR138 Awaiting FERC filing

Comment [MPRR138.11]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 5 of 37

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;

(a) ARRs resulting from LTCRs are automatically self-converted into TCRs prior

to auction clearing and are modeled as fixed injections/withdrawals. These

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 [MPRR138.12]: MPRR138 Awaiting FERC filing

Comment [MPRR138.13]: MPRR138 Awaiting FERC filing

Comment [MPRR138.14]: MPRR138 Awaiting FERC filing

Comment [MPRR138.15]: MPRR138 Awaiting FERC filing

Comment [MPRR138.16]: MPRR138 Awaiting FERC filing

Comment [MPRR138.17]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 6 of 37

(6) Market Participants holding ARRs not associated with LTCRs may self-convert their

ARRs into TCRs for the applicable period subject to simultaneous feasibility. TCRs

from self-converted ARRs, including TCRs self-converted from ARRs associated with

LTCRs, 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 [MPRR138.18]: MPRR138 Awaiting FERC filing

Comment [MPRR138.19]: MPRR138 Awaiting FERC filing

Comment [MPRR138.20]: MPRR138 Awaiting FERC filing

Comment [MPRR138.21]: MPRR138 Awaiting FERC filing

Comment [MPRR138.22]: MPRR138 Awaiting FERC filing

Comment [MPRR138.23]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 7 of 37

(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 [MPRR138.24]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 8 of 37

Exhibit 3-1: 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 11 - MPRR 171 Recommendation Report 3/18/2014 Page 9 of 37

Exhibit 3-2: LTCR/ARR Allocation/TCR Auction Processes 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

And TCR Auction Awards

by MonthOn-Peak and Off-Peak

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

10/1 - 5/31Annual ARR Awards

And TCR Auction Awards

by SeasonOn-Peak and Off-Peak

7/1 - 5/31

Monthly TCRAuction AwardsMonth to Month

On-Peak and Off-Peak

5/3 - 5/23Annual

TCR Auction4/5 - 4/23

Annual ARR Allocation

2/14 - 3/15

MP Verification of Transmission Entitlements

6/8 - 6/18

TCR Monthly Auction for July

Repeats forEachMonth

5/25 - 6/5Incremental ARR

Allocation andAwards. Repeats

Each Month asNeeded

The Energy and Operating Reserve Markets processes are described in detail in Section 4 and the

TCR Markets processes are described in detail in Section 5.

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

Comment [MPRR138.25]: MPRR138 Awaiting FERC filing

Comment [MPRR138.26]: MPRR138 Awaiting FERC filing

Comment [MPRR138.27]: MPRR138 Awaiting FERC filing

Comment [MPRR138.28]: MPRR138 Awaiting FERC filing

Comment [MPRR138.29]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 10 of 37

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 and/or monthly ARR allocation process. LTCRs are automatically converted

into ARRs and TCRs for modeling and settlement purposes. 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. ARRs

associated with LTCRs are automatically converted into TCRs which may be sold in the annual

and Monthly TCR auctions.

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;

(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.

Comment [MPRR138.30]: MPRR138 Awaiting FERC filing

Comment [MPRR138.31]: MPRR138 Awaiting FERC filing

Comment [MPRR138.32]: MPRR138 Awaiting FERC filing

Comment [MPRR138.33]: MPRR138 Awaiting FERC filing

Comment [MPRR138.34]: MPRR138 Awaiting FERC filing

Comment [MPRR138.35]: MPRR138 Awaiting FERC filing

Comment [MPRR138.36]: MPRR138 Awaiting FERC filing

Comment [MPRR138.37]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 11 of 37

Exhibit 5-1: LTCR/ARR Allocation and TCR Auction Processes 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

And TCR Auction Awards

by MonthOn-Peak and Off-Peak

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

10/1 - 5/31Annual ARR Awards

And TCR Auction Awards

by SeasonOn-Peak and Off-Peak

7/1 - 5/31

Monthly TCRAuction AwardsMonth to Month

On-Peak and Off-Peak

5/3 - 5/23Annual

TCR Auction4/5 - 4/23

Annual ARR Allocation

2/14 - 3/15

MP Verification of Transmission Entitlements

6/8 - 6/18

TCR Monthly Auction for July

Repeats forEachMonth

5/25 - 6/5Incremental ARR

Allocation andAwards. Repeats

Each Month asNeeded

Comment [MPRR138.38]: MPRR138 Awaiting FERC filing

Comment [MPRR138.39]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 12 of 37

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 (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 11 - MPRR 171 Recommendation Report 3/18/2014 Page 13 of 37

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

following sub-sections.

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 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 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

Comment [MPRR138.40]: MPRR138 Awaiting FERC filing

Comment [MPRR138.41]: MPRR138 Awaiting FERC filing

Comment [MPRR138.42]: MPRR138 Awaiting FERC filing

Comment [MPRR138.43]: MPRR138 Awaiting FERC filing

Comment [MPRR138.44]: MPRR138 Awaiting FERC filing

Comment [MPRR138.45]: MPRR138 Awaiting FERC filing

Comment [MPRR138.46]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 14 of 37

and/or ARRs. Eligible Entities may create Resource specific TSRs that represent

their current TSRs using the process described under Section 5.1.1.1;

(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 source 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:

(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;

Comment [MPRR138.47]: MPRR138 Awaiting FERC filing

Comment [MPRR138.48]: MPRR138 Awaiting FERC filing

Comment [MPRR138.49]: MPRR138 Awaiting FERC filing

Comment [MPRR138.50]: MPRR138 Awaiting FERC filing

Comment [MPRR138.51]: MPRR138 Awaiting FERC filing

Comment [MPRR138.52]: MPRR138 Awaiting FERC filing

Comment [MPRR138.53]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 15 of 37

(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 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, candidate LTCRs and ARRs

associated with such transmission service 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 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 does not exceed the lesser of the sum of NITS Candidate LTCRs or the

limit described under Section 5.1.3(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

Comment [MPRR138.54]: MPRR138 Awaiting FERC filing

Comment [MPRR138.55]: MPRR138 Awaiting FERC filing

Comment [MPRR138.56]: MPRR138 Awaiting FERC filing

Comment [MPRR138.57]: MPRR138 Awaiting FERC filing

Comment [MPRR138.58]: MPRR138 Awaiting FERC filing

Comment [MPRR138.59]: MPRR138 Awaiting FERC filing

Comment [MPRR138.60]: MPRR138 Awaiting FERC filing

Comment [MPRR138.61]: MPRR138 Awaiting FERC filing

Comment [MPRR138.62]: MPRR138 Awaiting FERC filing

Comment [MPRR138.63]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 16 of 37

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 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 does not exceed the

total FPTP Candidate LTCRs available for that Eligible Entity.

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) 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 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 LTCRs such that the total of such selections does

not exceed the lesser of the sum of GFA NITS Candidate LTCRs or the limit

described under Section 5.1.3(3)(b) for that Eligible Entity;

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;

(4) 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 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 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

Comment [MPRR138.64]: MPRR138 Awaiting FERC filing

Comment [MPRR138.65]: MPRR138 Awaiting FERC filing

Comment [MPRR138.66]: MPRR138 Awaiting FERC filing

Comment [MPRR138.67]: MPRR138 Awaiting FERC filing

Comment [MPRR138.68]: MPRR138 Awaiting FERC filing

Comment [MPRR138.69]: MPRR138 Awaiting FERC filing

Comment [MPRR138.70]: MPRR138 Awaiting FERC filing

Comment [MPRR138.71]: MPRR138 Awaiting FERC filing

Comment [MPRR138.72]: MPRR138 Awaiting FERC filing

Comment [MPRR138.73]: MPRR138 Awaiting FERC filing

Comment [MPRR138.74]: MPRR138 Awaiting FERC filing

Comment [MPRR138.75]: MPRR138 Awaiting FERC filing

Comment [MPRR138.76]: MPRR138 Awaiting FERC filing

Comment [MPRR138.77]: MPRR138 Awaiting FERC filing

Comment [MPRR138.78]: MPRR138 Awaiting FERC filing

Comment [MPRR138.79]: MPRR138 Awaiting FERC filing

Comment [MPRR138.80]: MPRR138 Awaiting FERC filing

Comment [MPRR138.81]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 17 of 37

Candidate ARRs subject to the total nomination limit described under Section

5.1.3.

5.2.6 LTCR 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 for the current allocation year.

(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:

(a) Source (valid candidate LTCR source Settlement Location);

(b) Sink (valid candidate LTCR sink Settlement Location);

(c) 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.

Comment [MPRR138.82]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 18 of 37

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 5.2.2.

(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.

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

Comment [MPRR138.83]: MPRR138 Awaiting FERC filing

Comment [MPRR138.84]: MPRR138 Awaiting FERC filing

Comment [MPRR138.85]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 19 of 37

of June in the annual auction of the normal and emergency ratings of all flowgates and monitored

transmission system elements in (2) above.

5.3.4 Annual ARR Awards All LTCR awards are automatically converted to ARR awards which are then automatically self-

converted to TCRs in the Annual TCR Auction. If all of the nominated candidate ARRs are

confirmed feasible, all nominated candidate ARRs are awarded. 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 least

squares deviation from the nominated candidate ARR MW weighted by the reciprocal of the

nominations resulting 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.

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. All ARRs associated with LTCRs are automatically

converted to TCRs prior to the start of the Annual TCR Auction and these TCRs will be

considered Self-Converted ARRs for the purposes of settlement. These Directly

converted TCRs from LTCRs can then 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);

Comment [MPRR138.86]: MPRR138 Awaiting FERC filing

Comment [MPRR138.87]: MPRR138 Awaiting FERC filing

Comment [MPRR138.88]: MPRR138 Awaiting FERC filing

Comment [MPRR138.89]: MPRR138 Awaiting FERC filing

Comment [MPRR138.90]: MPRR138 Awaiting FERC filing

Comment [MPRR138.91]: MPRR138 Awaiting FERC filing

Comment [MPRR138.92]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 20 of 37

(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.

5.4.4 Annual TCR Awards Simultaneously feasible TCRs are awarded based upon the TCR Bid prices such that the total

TCR auction value is maximized. TCRs associated with LTCRs result from ARRs that

automatically become Self-Converted TCRs for settlement purposes. Self-Converted TCRs not

associated with LTCRs 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 )).

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)

Comment [MPRR138.93]: MPRR138 Awaiting FERC filing

Comment [MPRR138.94]: MPRR138 Awaiting FERC filing

Comment [MPRR138.95]: MPRR138 Awaiting FERC filing

Comment [MPRR138.96]: MPRR138 Awaiting FERC filing

Comment [MPRR138.97]: MPRR138 Awaiting FERC filing

Comment [MPRR138.98]: MPRR138 Awaiting FERC filing

Comment [MPRR138.99]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 21 of 37

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. 5.5.2 Monthly ARR Nominations

Five (5) days prior to the start of each applicable Monthly TCR Auction Process, Eligible

Entities may nominate in a single round process (i) NITS Candidate ARRs in 0.1 MW

increments along specific source to sink paths that total to no more than the difference between

(1) their NITS Nomination Cap and (2) the sum of (a) awarded ARRs associated with NITS

Candidate ARRs and (b) directly converted TCRs from awarded LTCRs associated with NITS

Candidate LTCRs awarded in the Annual annual ARR Allocation allocation processes; (ii) FPTP

Candidate ARRs in 0.1 MW increments along specific source to sink paths that total to no more

than the difference between (1) their FPTP Nomination Cap and (2) the sum of (a) awarded

ARRs associated with FPTP Candidate ARRs and (b) directly converted TCRs from awarded

LTCRs associated with FPTP Candidate LTCRs awarded in the Annual annual ARR Allocation

allocation processes; (iii) GFA NITS Candidate ARRs in .1 MW increments along specific

source to sink paths that total to no more than the difference between (1) their GFA NITS

Nomination Cap and (2) the sum of (a) awarded ARRs associated with GFA NITS Candidate

ARRs and (b) directly converted TCRs from awarded LTCRs associated with GFA NITS

Candidate LTCRs awarded in the Annual annual ARR Allocation allocation processes; and/or

(iv) GFA FPTP Candidate ARRs in 0.1 MW increments along specific source to sink paths that

total to no more than the difference between (1) their GFA FPTP Nomination Cap and (2) the

sum of (a) awarded ARRs associated with GFA FPTP Candidate ARRs and (b) directly

converted TCRs from awarded LTCRs associated with GFA FPTP Candidate LTCRs awarded in

the Annual annual ARR Allocation allocation processes. Nominations occur separately for On-

Peak and Off-Peak periods. Eligible Entities submit the following information:

(1) Source (valid candidate ARR source Settlement Location);

(2) Sink (valid candidate ARR sink Settlement Location);

(3) Class (on-peak or off-peak);

(4) ARR MW.

(a) The total ARR MW nominated from a source Settlement Location cannot exceed

the source candidate ARRs less previously awarded source ARRs.

Comment [MPRR138.100]: MPRR138 Awaiting FERC filing

Comment [MPRR138.101]: MPRR138 Awaiting FERC filing

Comment [MPRR138.102]: MPRR138 Awaiting FERC filing

Comment [MPRR138.103]: MPRR138 Awaiting FERC filing

Comment [MPRR138.104]: MPRR138 Awaiting FERC filing

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 22 of 37

5.5.3 Simultaneous Feasibility

The SFT to assess feasibility of nominated monthly candidate ARRs is performed as described

under Section 5.3.3 with the following adjustments:

(1) The SPP Transmission System model used in the SFT will be the same model to be used

in the upcoming Monthly TCR Auction Process which will include the most up-to-date

Network Model, including planned maintenance outages, and updated Parallel Flow

assumptions;

(a) For withdrawals at sink 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 for the month of July). These load distribution

percentages are calculated using the methodology described under Section

4.1.2.1.6.

(2) LTCRs awarded in the Annual LTCR Allocation process are not modeled as fixed

injections/withdrawals as they have already been accounted for as part of the Annual

TCR Auction process and are included as TCRs as described under (4) below;

(3)(2) 100% of the Residual SPP Transmission System Capability is made

available; and

(4)(3) All TCRs previously awarded in the Annual TCR Auction Process,

directly converted TCRs fromassociated with LTCRs that were awarded, and all

remaining ARRs not accounted for in the Annual TCR Auction Process (as defined under

Section 5.4), and for the applicable month 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 will increase the ratings of the applicable

transmission lines to ensure feasibility prior to assessing monthly ARR feasibility. SPP

will report back to the MWG on a quarterly basis regarding the number of times that

transmission line ratings had to be adjusted to ensure feasibility.

5.6.3 Monthly TCR Auction Clearing and Simultaneous Feasibility

The Auction is performed using a Linear Program algorithm to maximize the total TCR auction

value while ensuring that the cleared TCRs are also simultaneously feasible:

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

Network Model, including planned maintenance outages, for the auction month;

Comment [MPRR138.105]: MPRR138 Awaiting FERC filing

Comment [MPRR138.106]: MPRR138 Awaiting FERC filing

Comment [MPRR138.107]: MPRR138 Awaiting FERC filing

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Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 23 of 37

(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 for the month of July). 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) The SFT is performed as described under Section 5.5.3 except that LTCRs awarded in the

Annual LTCR Allocation process are not modeled as fixed injections/withdrawals since

they have already been awarded as self-converted TCRs. TCR Bid MWs are modeled as

an injection at the source and a corresponding withdrawal at the sink. TCR Offers

associated with the sale of existing TCRs are modeled as injections at the sink and

withdrawals at the source. Residual SPP Transmission System Capability includes the

most up to date Parallel Flow assumptions.

(a) For Round 1, all TCRs awarded in the Annual TCR Auction for the month are

modeled as fixed injections and withdrawals. To the extent that the fixed

injections and withdrawals representing TCRs awarded in the Annual TCR

Auction are not feasible, SPP will increase the ratings of the applicable

transmission lines to ensure feasibility prior to the Round 1 auction. SPP will

report back to the MWG on a quarterly basis regarding the number of times that

that transmission line ratings had to be adjusted to ensure feasibility;

(b) For Round 2, all TCRs previously awarded for the month are modeled as fixed

injections and withdrawals prior to clearing the TCR Bids and Offers.

Proposed Tariff Language Revision

Attachment AE 1.1 Definitions A

Auction Revenue Right (“ARR”)

A right, awarded during the annual Auction Revenue Right allocation process and the monthly

Auction Revenue Right allocation process, which entitles the holder to a share of the auction

revenues generated in the applicable Transmission Congestion Rights auction(s), except for

Comment [MPRR138.109]: MPRR138 Awaiting FERC filing

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Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 24 of 37

rights associated with LTCRs which are automatically converted to TCRs, and entitles the

holder to self-convert the Auction Revenue Right to a Transmission Congestion Right.

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;

(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 7.3.2 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.

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 25 of 37

(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) Ccandidate 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 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.

7.1.1 Transmission Service 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. 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

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 26 of 37

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.

(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.

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 27 of 37

(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 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 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.

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 28 of 37

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 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

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 29 of 37

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, candidate

LTCRs and/or ARRs associated with such transmission service 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 Ccandidate ARRs from a specific source is equal to the source

Reservation Capacity.

(a) An Eligible Entity may select 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 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 11 - MPRR 171 Recommendation Report 3/18/2014 Page 30 of 37

(a) An Eligible Entity may select 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 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) 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 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 does not exceed the lesser of the sum of Grandfathered

Agreement Network Integration Transmission Service Candidate LTCRs

or the limit described under Section 7.1.3(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.

(4) For each Eligible Entity with equivalent Firm Point-To-Point GFA service, the

Eligible Entity’s Grandfathered Agreement Firm Point-To-Point Candidate

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 31 of 37

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

Capacity associated with that source and sink.

(a) An Eligible Entity may select 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 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.

7.1.3 Auction Revenue Right Nomination Cap

An Eligible Entity’s ARR Nomination Cap will be as follows:

(1) For Network Integration Transmission Customers, the Network Integration

Transmission Service ARR Nomination Cap for a particular month or season is

equal to the lesser of (a) the sum of Network Integration Transmission Service

Candidate ARRs and Network Integration Transmission Service Candidate

LTCRs for that particular month or season as calculated in Section 7.1.2 of this

Attachment AE and any additional Network Integration Transmission Service

Candidate ARRs for that particular month or season as calculated in Section 7.5.1

of this Attachment AE or (b) One hundred and three percent (103%) of the

average of that customer’s three most recent annual peak Network Loads. This

value will be adjusted by the Transmission Provider as required to account for

wholesale load shifts between Transmission Customers. In addition, candidate

LTCRs and awarded LTCRs shall be transferred by the Transmission

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 32 of 37

Provider as applicable to account for wholesale load shifts between

Transmission Customers.

(2) For Firm Point-To-Point Transmission Customers, the Firm Point-To-Point ARR

Nomination Cap is equal to the sum of Firm Point-To-Point Candidate ARRs and

Firm Point-To-Point Candidate LTCRs as calculated in Section 7.1.2 of this

Attachment AE and any additional Firm Point-To-Point Candidate ARRs as

calculated in Section 7.5.1 of this Attachment AE.

(3) For GFA customers taking the equivalent of SPP Network Integration

Transmission Service, the Grandfathered Agreement Network Integration

Transmission Service ARR Nomination Cap for that particular month or season is

equal to the lesser of (a) the sum of Grandfathered Agreement Network

Integration Transmission Service Candidate ARRs and Grandfathered

Agreement Network Integration Transmission Service Candidate LTCRs for

that particular month or season as calculated in Section 7.1.2 of this Attachment

AE and any additional Grandfathered Agreement Network Integration

Transmission Service Candidate ARRs for that particular month or season as

calculated in Section 7.5.1 of this Attachment AE or (b) One hundred and three

percent (103%) of the average of that GFA customer’s three most recent annual

peak Network Loads.

(4) For GFA customers taking the equivalent of SPP Firm Point-To-Point, the

Grandfathered Agreement Firm Point-To-Point ARR Nomination Cap is equal to

the sum of Grandfathered Agreement Firm Point-To-Point Candidate ARRs and

Grandfathered Agreement Firm Point-To-Point Candidate LTCRs as

calculated in Section 7.1.2 of this Attachment AE and any additional

Grandfathered Agreement Firm Point-To-Point Candidate ARRs as calculated in

Section 7.5.1 of this Attachment AE.

(5) An Eligible Entity’s ARR Nomination Cap is equal the sum of its Network

Integration Transmission Service ARR Nomination Cap, Firm Point-To-Point

ARR Nomination Cap, Grandfathered Agreement Network Integration

Transmission Service ARR Nomination Cap and Grandfathered Agreement Firm

Point-To-Point ARR Nomination Cap.

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 33 of 37

7.2 Annual Long-Term Congestion Right Allocation

Eligible Entities may select the candidate LTCRs that they wish to receive up to

their available LTCRs. The portion of the selected candidate ARRs are awarded to each

Eligible Entity during the LTCR annual allocation. Available Ccandidate LTCRs are

evaluated on an annual basis in a two-step process; (i) Ccandidate LTCRs associated with

Eligible Entities that are Load Serving Entities are evaluated in accordance with Section

7.2.2 and (ii) remaining Ccandidate LTCRs associated with Eligible Entities that are not

Load Serving Entities 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 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.

7.2.4 LTCR Selection and Awards

(1) All previously awarded LTCRs are automatically awarded as LTCRs for the

current allocation year; provided that such LTCRs 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 LTCRs are selected and awarded in a single-round process. Eligible

Entities may select:

(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;

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 34 of 37

(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. 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 for the current allocation year.

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 are modeled as

fixed injections and withdrawals and are aoutmatically awarded as ARRs.

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

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 35 of 37

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.

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.

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. LTCRs awarded as ARRs as described under

Section 7.3.3 are automatically converted to TCRs which the holder may offer for sale in

the auction. 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 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.

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:

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 36 of 37

(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 ARRs associated with LTCRs are automatically

converted into awarded TCRs, are modeled as fixed injections and

withdrawals, and such TCRs are treated as self-converted TCRs for

settlement purposes.

7.6.3 Monthly Auction Revenue Right Nominations

Five (5) days prior to the start of the monthly TCR auction, Eligible Entities may

nominate in a single round: (i) Network Integration Transmission Service Candidate ARRs in 0.1

MW increments along specific source to sink paths that totals no more than the difference

between (1) their Network Integration Transmission Service ARR Nomination Cap and (2) the

sum of (a) awarded ARRs associated with Network Integration Transmission Service Candidate

ARRs and (b) directly converted TCRs from awarded LTCRs associated with Network

Integration Transmission Service Candidate LTCRs awarded in the annual ARR allocation

processes; (ii) Firm Point-To-Point Candidate ARRs in 0.1 MW increments along specific source

to sink paths that totals no more than the difference between (1) their Firm Point-To-Point ARR

Nomination Cap and (2) the sum of (a) awarded ARRs associated with Firm Point-To-Point

Candidate ARRs and (b) directly converted TCRs from awarded LTCRs associated with Firm

Point-To-Point Candidate LTCRs awarded in the annual ARR allocation processes; (iii)

Grandfathered Agreement Network Integration Transmission Service Candidate ARRs in 0.1

MW increments along specific source to sink paths that totals no more than the difference

between (1) their Grandfathered Agreement Network Integration Transmission Service ARR

Nomination Cap and (2) the sum of (a) awarded ARRs associated with Grandfathered

Agreement Network Integration Transmission Service Candidate ARRs and (b) directly

converted TCRs from awarded LTCRs associated with Grandfathered Agreement Network

Integration Transmission Service Candidate LTCRs awarded in the annual ARR allocation

processes; and (iv) Grandfathered Agreement Firm Point-To-Point Candidate ARRs in 0.1 MW

increments along specific source to sink paths that totals no more than the difference between (1)

their Grandfathered Agreement Firm Point-To-Point ARR Nomination Cap and (2) the sum of

Attachment 11 - MPRR 171 Recommendation Report 3/18/2014 Page 37 of 37

(a) awarded ARRs associated with Grandfathered Agreement Firm Point-To-Point Candidate

ARRs and (b) directly converted TCRs from awarded LTCRs associated with Grandfathered

Agreement Firm Point-To-Point Candidate LTCRs awarded in the annual ARR allocation

processes. Nominations occur separately for On-Peak and Off-Peak periods. Eligible Entities

submit the following information:

(1) Source: valid candidate ARR source Settlement Location;

(2) Sink: valid candidate ARR sink Settlement Location;

(3) Class: On-Peak or Off-Peak; and

(4) ARR MW:

(a) The total ARR MW nominated from a source Settlement Location cannot

exceed the source candidate ARRs less previously awarded source

ARRs.

Proposed Criteria Language Revision N/A

Attachment 12 - MPRR 170 Recommendation Report 3/18/2014 Page 1 of 3

PRR Recommendation Report PRR No. 170 PRR

Title OOME Process Clarification

Timeline

Normal Expedited Urgent Action

Provide explanation if Expedited and/or Urgent Action is selected: This MPRR is Expedited to go the April’s MOPC

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 – If yes, estimated cost: No

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: 4.4.3.3 Title: Non-Dispatchable Variable Energy Resource Deployment Protocol Version: 19.1

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description This MPRR is to clarify language that was erroneously added during MPRR155. The added language told SPP to call NDVERs at all times when there was an issue. This MPRR allows SPP to call the NDVERs only when there is an Emergency Condition.

Tariff Implications or Changes

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

Attachment AE; Section 4.1.2.5 Non-Dispatchable Variable Energy Resource

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: 3/18/2014 Vote: Approved with modifications

Opposed: Midwest Energy, NPPD, CUS, Edison Mission

Abstained: AEP, TNSK, GSEC, Xcel, OGE

RTWG Review Date of Vote: Vote:

ORWG Review Date of Vote: Vote:

MOPC Recommendation Date of Vote: Vote:

Board Review Date of Vote: Vote:

Attachment 12 - MPRR 170 Recommendation Report 3/18/2014 Page 2 of 3

Date 3/11/2014

Sponsor Name Terry Oxandale E-mail Address toxandale@spp.org Company Southwest Power Pool Phone Number 501.614.3552

Comments Received Comment Author Micha Bailey on behalf of MWG Date 3/18/2014

Comment Description

The MWG rejected some of the proposed changes at this time. The MWG felt that another clarification MPRR needs to be written to help clarify the OOME process. The only change approved was in the Non-Dispatchable Variable Energy Resource Deployment Section. This change allows SPP to call the NDVERs only when there is an Emergency Condition.

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

Proposed Protocol Language Revision

4.4.3.3 Non-Dispatchable Variable Energy Resource Deployment Non-Dispatchable Variable Energy Resources (NDVERs) will be deployed the echo of actual SCADA

output via ICCP (and XML as backup). During times when it is necessary to issue an OOME to a Non-

Dispatchable Variable Energy Resource to resolve or prevent an Emergency Condition, SPP will

manually direct the Resource via telephone to a specified MW output in accordance with 4.4.2.5(1). If

SPP needs to issue manual instructions to an NDVER to resolve or prevent an Emergency Condition,

manual dispatch instructions will be issued in accordance with the rules specified in 4.4.2.5

Proposed Tariff Language Revision Attachment AE

4.1.2.5 Non-Dispatchable Variable Energy Resource

Each Market Participant may submit Resource Offers for Non-Dispatchable

Variable Energy Resources using the same Offer parameters available to any other

Resource, except that

(1) For the RTBM, the Resource’s Energy Offer Curve shall not apply;

Comment [MPRR155.1]: MPRR155 awaiting FERC filing

Comment [MPRR155.2]: MPRR155 awaiting FERC filing

Comment [MPRR155.3]: MPRR155 awaiting FERC filing

Comment [MPRR155.4]: MPRR155 awaiting FERC filing

Attachment 12 - MPRR 170 Recommendation Report 3/18/2014 Page 3 of 3

(2) For the RTBM, the Resource’s Dispatch Instruction shall be equal to the

Resource’s actual output at the start of the Dispatch Interval and the Resources

must operate as non-dispatchable;

(3) Resource Energy Offer Curve prices shall be assumed equal to zero (0) for the

purposes of calculating production costs relating to RUC make whole payments

and cost allocation thereof under Sections 8.6.5 and 8.6.7 of this Attachment AE;

(4) For the RTBM, during times when it is necessary to issue a Manual Dispatch

Instruction to a Non-Dispatchable Variable Energy Resource to resolve or

prevent an Emergency Condition, the Transmission Provider will direct the

Resource to a specified MW output in accordance with Section 6.2.4.1 of this

Attachment AE. If the Transmission Provider needs to issue a Manual

Dispatch to a Non-Dispatchable Variable Energy Resource to resolve or

prevent an Emergency Condition, the Manual Dispatch instructions will be

issued in accordance with the rules specified in 6.2.4 of this Attachment AE;

and

(5) The maximum operating limits for use in the Day-Ahead RUC and the Intra-Day

RUC shall be calculated by the Transmission Provider as equal to the lesser of the

maximum operating limits submitted in the Resource Offer or the Transmission

Provider’s output forecast for that Resource to the extent that such output forecast

is available, otherwise the maximum operating limits shall be equal to those

submitted in the Resource Offer;

(a) Non-Dispatchable Variable Energy Resources for which the Transmission

Provider is calculating an output forecast are not eligible to receive RUC

make whole payments as described under Section 8.6.5 of this Attachment

AE.

Proposed Criteria Language Revision

N/A

Attachment 13 - MPRR 172 Recommendation Report 3/20/2014 Page 1 of 2

PRR Recommendation Report

MPRR No. 172 PRR

Title Dispute Clarification

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

N/A – N/A 3 – Member Request 4 – Other

Impact Analysis Required Yes – If yes, estimated cost: No

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: 4.5.15.1 Title: Dispute Submission Timeline Protocol Version: 19.1

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description

The Tariff and Protocols do not match on the amount of time to file a dispute on a final or resettlement. This MPRR changes the start time of the 90 calendar days for a final from the posting of the final Settlement Statement to the posting of the applicable invoice for that Operating Day. This MPRR is needed to let Market Participants know that the amount of time to file a dispute on a resettlement is 30 days after the posting of the invoice of that resettlement and not 14 days.

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

MWG Review PRR Recommendation

Date of Vote: 3/18/2014 Vote: Unanimously approved with modifications

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:

Attachment 13 - MPRR 172 Recommendation Report 3/20/2014 Page 2 of 2

Date 3/13/2014

Sponsor Name Micha Bailey E-mail Address mcbailey@spp.org Company Southwest Power Pool Phone Number 501.688.2522

Comments Received Comment Author Jared Greenwalt on behalf of MWG Date 3/18/2014 Comment Description The new language in 4.5.15.1 was modified for clarification.

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

Proposed Protocol Language Revision

4.5.15.1 Dispute Submission Timeline A Market Participant may dispute settlement of any Operating Day as soon as the initial Settlement

Statement for that Operating Day is issued, and up to 90 calendar days after the invoice date for the

applicable final Settlement Statement that the Market Participant wishes to dispute for that Operating

Day is issued. In the case of resettlement Settlement Statements, a Market Participant may only dispute

incremental changes in settlement data that occur between issuance of the final Settlement Statement

and the first resettlement Settlement Statement or between issuance of resettlement Settlement

Statements. A dispute relating to a resettlement Settlement Statement must be filed within 3014

calendar days following the issue date of the applicable invoice of the items contained in that

resettlement Settlement Statement that the Market Participant wishes to dispute. of issuance of the

resettlement Settlement Statement.

In the event that the Portal is unavailable on the day prior to the deadline for submission of a dispute due

to technical or other reasons, SPP shall extend the dispute submittal deadline by the number of Business

Days equal to the sequential number of Business Days on which the Portal was unavailable.

Proposed Tariff Language Revision N/A

Proposed Criteria Language Revision N/A

Attachment 14 - MPRR 168 Recommendation Report 3/20/2014 Page 1 of 3

PRR Recommendation Report PRR No. 168 PRR

Title Regulation Deployment Priority Group Update

Timeline Normal Expedited Urgent Action

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

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Impact Analysis Required Yes – If yes, estimated cost: No

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: 4.4.3.3 Title: Regulation Deployment Protocol Version: 19.1

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Timeline Go-Live Post Go-Live

Revision Description

Regulation is deployed in priority groups. The system allows SPP to change the number of priority groups. SPP has tested one priority group versus six priority groups, and setting the number of priority groups to six gave a faster and smoother ACE response with fewer Resources cleared for Regulation. Based on those test results, SPP is changing the number of priority groups from ‘1’ to ‘6’.

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

MWG Review PRR Recommendation

Date of Vote: 3/19/2014 Vote: Unanimously approved

Opposed: N/A

Abstained: N/A

RTWG Review Date of Vote: Vote:

ORWG Review Date of Vote: 3/6/2014 Vote: Approved

MOPC Recommendation Date of Vote: Vote:

Board Review Date of Vote: Vote:

Attachment 14 - MPRR 168 Recommendation Report 3/20/2014 Page 2 of 3

Date 2/28/2014

Sponsor Name Jared Greenwalt E-mail Address jgreenwalt@spp.org Company Southwest Power Pool Phone Number 501.688.8314

Comments Received Comment Author Jason Smith on behalf of the ORWG Date 3/6/2014

Comment Description ORWG has concerns about the implementation of this change prior to the approval of the change of the protocols language. SPP should have obtained approval prior to implementation.

Comment Status These comments were taken into consideration by the MWG. MWG did not make any language changes based on these comments at this time.

Proposed Protocol Language Revision

4.4.3.3 Regulation Deployment

Regulation Deployment is limited to Resources that have cleared Regulation-Up and/or Regulation-

Down with a Control Status of “Regulating”. Regulation-Up and/or Regulation-Down is deployed on

specific Resources through Setpoint Instructions via the AGC system. The deployment is on a pro-rata

basis, based upon Regulation-Up and/or Regulation-Down cleared MW and RTBM assigned priority

group order. As the RTBM is run, it will populate the priority groups for each interval. Each of the

Regulation-Up and Regulation-Down cleared Resources will be assigned to a Regulation-Up and/or

Regulation-Down priority group. The AGC system deploys starting with lowest priority group to

highest group in the respective direction when regulation is needed in that direction. The number of

priority groups is a configurable parameter that may be adjusted from time to time. SPP will analyze the

market operations and will recommend to the MWG, ORWG and MOPC the number of priority groups

it believes will produce the best operational results.

Resources are assigned to priority groups based on the three criteria below which are independent of

each other:

(1) Reserve Zone in which the resource is located

(2) The effective Ramp Rate of the resource

(3) The number of priority groups

The first two criteria are made configurable to be switched ON or OFF independently or in conjunction

with each other as deemed necessary for operational purposes. In the event that more than one priority

group is designated for Regulation-Up or Regulation-Down, the third criterion is always in effect. The

initial current configuration will beis (1) off, (2) off, (3) = 16. If SPP's analysis shows that a change to

the current configuration needs to occur, SPP will make a recommendation for such change to the

Attachment 14 - MPRR 168 Recommendation Report 3/20/2014 Page 3 of 3

MWG, ORWG and MOPC, including the appropriate compensation and the effective date of the change.

The active configuration will be posted on SPP OASIS. No Regulation Deployment will occur on

Resources that have not cleared Regulation-Up and/or Regulation-Down even if their Control Statuses

are set to “Regulating”.

Market Participants providing Regulation-Up and/or Regulation-Down service during the Operating

Hour have an obligation to report to SPP when their Resources are no longer capable of providing the

service due to physical problems with the associated Resources through submission of the applicable

Resource Control Status via ICCP as described under Exhibit 4-14. If the problem persists into the next

Operating Hour, that Market Participant must update its Resource Offer by submitting a Regulation-Up

and Regulation-Down Dispatch Status as “Not-Qualified”. If a Market Participant fails to follow this

procedure and SPP observes that a particular Resource is failing to provide the Regulation-Up or

Regulation-Down service for 3 or more consecutive Dispatch Intervals, SPP may change the Resource’s

regulation Dispatch Status to “Not-Qualified” and will contact the Market Participant to ascertain the

nature of the problem. If the physical limitation is expected to be corrected within that Operating Hour,

SPP will return the Resource’s Dispatch Status to “Market” or “Fixed”, as applicable when notified by

the Market Participant. If the Market Participant fails to notify SPP within that Operating Hour and then

fails to submit an updated Resource Offer indicating a Regulation-Up and/or Regulation Down Dispatch

Status of “Not-Qualified”, SPP will change the Resource’s regulation Dispatch Status to “Not-

Qualified” for the remainder of the Operating Day or the Market Participant notifies SPP that the

physical limitation is corrected, whichever is shorter. Exhibit 4-15 shows the all of the available

Resource Control Statuses in the AGC system.

Proposed Tariff Language Revision N/A

Proposed Criteria Language Revision N/A

TCR Market –Transmission Service with Rollover Rights

MWG ‐ 3/18/2014

Market Design

• …transmission customers with rollover rights between March 15 and June 1 will be able to obtain ARRs in the annual allocation process without being required to notice more than one year in advance.

• …customer with rollover rights between March 15 and June 1 that chooses not to exercise rollover rights, any ARRs associated with that contract will revert to SPP effective on the date the contract terminates.

2

FERC Directives

• SPP will grant candidate ARRs for paths that have rollover rights and have not yet been renewed.

– Allows MP to receive candidate ARRs and without being required to give rollover notice more than a year out.

• On or before June 2014, SPP will determine if these reservations were renewed by the applicable deadline.

• Any reservations not renewed will have their associated ARR products, TCR products, and settlement thereof removed for those product periods in full.

– If the TCRs were traded to another entity, the consequence of the removal is between those parties.

3

Granting and Removing Rights

Action Items Related to Winter  2014 Gas Price Spikes

March 19, 2014

Background

• SPP experienced a spike in the price of natural gas on February 6th

– Index Prices exceeded $30/MMBTU on the 6th

– Index Prices were below $10/MMBTU on the 7th

– Due to Gas‐Electric day mismatch, Offer Caps for first 9 hours of March 7th did not reflect the $30/MMBTU Price

• PJM Experienced $120/MMBTU gas prices in January 2014

– Cost‐based Offers capped at $1000/MWH impacted  approximately 5000 MW of capacity

3

Two Action Items

• SPP Re‐pricing decision for February 7th

• Provide information on two filings made by PJM in response to the January gas price spikes

4

Re‐Pricing

• SPP will not re‐price the EIS Market for February 7th

• Re‐pricing prerequisites as established in Section 13.3 (EIS Protocols)  were not met

• The EIS Market Offer Cap is specified in the tariff and protocols as a daily value; no system capability for intra‐day offer cap changes

5

PJM Regulatory Response

• January 23rd – PJM filed two requests for waiver

– Docket ER14‐1144‐000:  Requests that Generators be made whole to their true costs rather than the limited cost reflected in the Cost‐Based Offers

– Docket ER14‐1145‐000:  Requests the $1000/MWH Offer Cap be lifted for Resources whose cost exceed the $1000/MWH.  

January 24th – Commission grants the waiver for Docket ER14‐1144‐000, Effective until March 31, 2014

February 11th – Commission grants the waiver for Docket ER14‐1145‐000, Effective until March 31, 2014

6

7

Integrated Marketplace Phase II Update for MWG

March 19, 2014

Alice Wright, 

Manager‐ Project Management Office

Topics

2

• Governance Structure

• Project Update‐ Combined Cycle Enhancements

• Phase 1 Deferrals 

• Question & Answer Session

Governance Model

3

Governance Structure (cont’d.):Projects

4

PROJECTS: A temporary activity designed to produce a unique product, service or result with a defined beginning and end.

Deferrals and Compliance Items

Market to Market

Long‐Term Congestion 

Rights

Pseudo‐Tie Out

Enhanced Combined 

Cycle

Environment Build‐Out

Regulation Compensation

Governance Structure (cont’d.):Products

Markets and Operations

Information Technology 

(IT)Financial 

StakeholderOther

5

PRODUCT GROUPS: Represents the end‐to‐end market functions and are managed by respective product owners.

• Project’s Highest risk:  Performance

– ECC is expected to add significant processing time which risks creating a longer (and unacceptable) solution time

– SPP will work closely with vendor to identify methods to limit processing time while preserving Market Design requirements

• Accomplishments to date: 

– High Level Requirements complete

– Began gathering Detailed Requirements in mid‐March 

– Working with vendor on prototype requirements and intent 

– Working with MPs on Combined Cycle model and offers for test bed (15 MPs, approximately 27 resources)

– Schedule to mid‐June defined

6

ECC Project Update

• Currently March 1, 2015 is not considered feasible due to higher priority projects requiring SPP staff and Vendor time:

– FERC required projects 

– Operations Production support

– Phase 1 Required Deferrals

• Current Project Timeline (subject to potential resource reassignments)

– March 2014:  SPP reaching out to 15 MPs with CC for configuration and test data.  

– March – April 2014:  Vendor building prototype engine using CC configurations and data SPP is providing.  

– May 2014:  Vendor to deliver Prototype to SPP

– May‐June 2014:  SPP tests functionality, but focus on performance testing of the engine

– July 2014:  Based on results of testing, SPP determines options and direction for the project, including  key milestone and implementation dates

7

Next Steps for ECC

Phase 1 Deferrals‐ Overview• Phase 1 Deferrals addresses defects and/or enhancements 

carried over from Go Live release

• SPP has merged the Prioritization Process with Severity definitions in order to better assess Participant impact as well as benefit for making the change

• SPP reviews and prioritizes new and backlog defects/enhancements by functional area on a recurring /scheduled basis 

• Close collaboration occurs with Vendors/development teams to plan vendor releases/patches according to SPP and Participant needs

8

Phase1 Deferrals ‐Defect/Enhancement Severity Levels

• Severity 1: Critical ‐ Significant environment or system outage/instability and/or compliance risk, impact to key Participant milestones, where no manual workaround exists

• Severity 2: High ‐ One or more key functions within a system are non‐operational, or a severe error exists in its processing, impacts broad set of Participants, where only a short‐term workaround may exist 

• Severity 3: Medium ‐ An error with manageable impact on system functionality, impacts minimal set of Participants, benefit from making the change significantly outweighs the relative cost,  with options for a manual/sustainable workaround

• Severity 4: Low – No reliability or operations impact,  item is considered “nice to have”, error/impact to documentation/training, benefits from making change are minimal compared to the relative cost, typically do not require a manual workaround

9

Phase1 Deferrals –Known Issues Log• The Known Issues Log was published throughout Market Trials as mechanism 

to communicate known Market Participant facing system issues during testing

• The final Known Issues Log has been posted, communicating SPP’s inventory of Market Participant facing Phase I Deferrals, both system defects and enhancements

• A Severity for each system issue is included in the final/published list 

• System impacts that require MP system changes follow established communication standards using the Marketplace Change Tracker and CWG communication processes

10

Questions

8

12

SPP PMO Mission Statement

To ensure the successful deployment of SPP Enterprise Projects by promoting, implementing, and supporting project management methodologies and business process improvements that result in the efficient and cost‐effective delivery of superior quality products and services that are aligned with SPP’s strategic objectives.

Regulatory Report to MWG for March 2014

PRR Description FERC Docket Current Activity Upcoming Activity IM Tariff filing ER12-1179-000

(2/29/2012 filing) ER12-1179-001 (5/16/2012 filing) ER12-1179-003 (2/15/2013 filing) ER12-1179-005 (4/19/2013 filing) ER12-1179-012 (11/11/2013 filing)

Order received on October 18, 2012 conditionally accepting the Marketplace filing with several compliance requirements outlined in the order. Request for rehearing and clarification was filed on November 19, 2012. Compliance filing made on February 15, 2013. Comments were due by March 8, 2013. Four sets of comments/protests were filed by March 8, 2013 and one set filed on March 13, 2013. SPP filed responses on April 19, 2013. ER12-1179-005—Filed pursuant to the March 21, 2013 Order on Rehearing and Clarification (Attachment AG Section 4.4 modifications). Order received on September 20, 2013 accepting in part and rejecting in part SPP’s proposed Tariff revisions filed 2/15/2013, 3/28/2013 and 4/19/2013. Compliance filing made on November 11, 2013. Comments were due by December 3, 2013. Seven sets of comments/protests were filed (one in support of the filing). SPP filed responses on December 23, 2013. Order received on January 29, 2014 conditionally accepting the filing with compliance requirements outlined in the order. Compliance filing made on February 26, 2014.

Awaiting order.

Multiple MPRRs and a TRR

IM Second Supplemental Filing

ER13-1173 Filing of MPRRs and TRR081M that have passed the Board. Filing made on March 28, 2013. Comments were due by April 18, 2013. Four interventions were filed and no comments were received. Order received on September 20, 2013 accepting in part and rejecting in part SPP’s

Awaiting order.

proposed Tariff revisions filed 2/15/2013, 3/28/2013 and 4/19/2013. Compliance filing made on November 12, 2013. Comments were due by December 3, 2013. Seven sets of comments/protests were filed (one in support of the filing). SPP filed responses on December 23, 2013. Order received on January 29, 2014 conditionally accepting the filing with compliance requirements outlined in the order. Compliance filing made on February 26, 2014.

Multiple MPRRs and a TRR

IM Third Supplemental Filing

ER14-416 Filing of MPRRs and TRR 078M that have passed the Board and are necessary for go-live. Filing made on November 15, 2013. Comments were due by December 7, 2013. Four interventions were filed and no comments were received. Order received on January 29, 2014 conditionally accepting the Marketplace filing with one compliance requirement outlined in the order. Compliance filing made on February 25, 2014.

Awaiting order.

Order No. 764 – Integration of Variable Energy Resources (VER)

RM10-11 ER13-1292

NOPR issued on November 18, 2010. SPP joined IRC Council in comments on March 2, 2011. Order No. 764 was issued by FERC on June 22, 2012. Effective date of Order is Sep 11, 2012. Order No. 764-A was issued on December 20, 2012. Extended deadline for compliance. Filing made on April 16, 2103 asking for an effective date of June 16, 2013. (MPRR 105) Comments were due May 7, 2013. Two interventions were filed and no comments were received. Order issued by FERC on June 27, 2013 accepting SPP’s filing to adopt the data requirement aspects, conditional on SPP submitting an additional compliance filing to address the remaining Order No. 764 requirements before the November 12, 2013

Awaiting order.

deadline. Compliance filing made on November 12, 2013. Comments are due by December 3, 2013. Two interventions were filed and no comments were received.

MPRR 77

Order No. 745 – Demand Response Compensation

ER12-1179-016 MPRR 77 only covers the cost allocation part of Order 745. (Cost allocation will be handled differently in the Marketplace than in EIS). Filing made on January 22, 2014.

Awaiting order.

MPRR 89

Order No. 745 – DR Compensation (Net Benefits Test)

ER12-1179-016 This MPRR only covers incorporation of the tariff language for Order No. 745 requirements for a net benefits test. Filing made on January 22, 2014.

Awaiting order.

MPRR 102

Order No. 755 – Frequency Response Compensation

ER13-1748 Filing made on June 21, 2013. Deficiency letter issued by FERC on March 7, 2014.

SPP response to be filed on or before April 7, 2014.

Item Meeting Action Item

202 03/13/13MPRR113 – CRD Timeframe: Post the presentation from SPP Operations

203 03/13/13MPRR113 – CRD Timeframe: SPP Operations to deliver a presentation at May MWG meeting

214 05/21/13

Regarding the Qualifying Facilities who were required to register already as DVERS, SPP Staff to determine how to "un-do" that existing registration and get them re-registered as NDVERS.

216 05/29/03

SPP Staff will research the possible need for an MPRR to remove a potential “circular reference” in which the Protocols reference the Tariff definition of Supplemental Reserve, then the Tariff definition of Supplemental Reserve includes the term “Contingency Reserve Deployment Period” and references the Protocols for the definition of that term.

223 08/21/13

Regarding MPRRxx-Demand Response Resource Clarification: rewrite the proposed language so that it is less convoluted and more easily readable and understood.

229 10/22/13

GFA Carve Out entities to report back to MWG the results and decisions from their current research regarding collections of losses in their GFA contracts.

232 11/13/13

Regarding MPRR155-Modification of OOME Rules: MWG directs SPP Staff to clarify in time for the MOPC meeting in January 2014 how the reasons for OOME instructions will be communicated to Market Participants and what information will be included with those reasons.

235 01/21/14

Regarding Section 8.2.2.6 of Marketplace Protocols, which mentions posting of data about mitigated resources, transmission constraints, and RLDF values: SPP Market Design Staff will research with SPP Compliance and others on what of the data listed in this section can be posted, and bring an MPRR back to MWG if needed to reflect the results of the research.

239 02/12/14

SPP Staff will research the possibility of re-pricing in the EIS Market for the hours of 0000-0900 on February 7-12, 2014 when EIS Offer Cap adjustments were made due to spikes in gas prices and the coverage provided by those adjustments was inadvertently disrupted due to the EIS Offer Cap process being based on the electric day versus the gas price day (0900-0900).

CommentTarget Resolution

DateActual Resolution

DateStatus

3/11/14: The info for this presentation ended up being rolled into the Marketplace Clinic training materials and was not developed for the MWG. 5/25/2013

Pending Closure

3/11/14: The info for this presentation ended up being rolled into the Marketplace Clinic training materials and was not developed for the MWG. 5/25/2013

Pending Closure

3/11/14: SPP Customer Relations facilitated the contact of the affected MPs and communicated their options. 6/15/2013

Pending Closure

3/11/14: SPP Staff researched this and determined that no circular reference exists. 7/31/2013

Pending Closure

3/11/14: MPRR144 approved by MWG on 1/21/14; scheduled for April 2014 MOPC.1/13/14: MPRR144 scheduled for discussion at January 2014 meeting 9/30/2013

Pending Closure

3/11/14: NPPD reported at the MWG January meeting that they would not be collecting losses in their GFA contracts. 1/31/2014

Pending Closure

3/11/14: SPP Staff reported at the January 2014 MOPC meeting that reasons for OOMEs would be contained in a curtailment report that is posted on spp.org. 1/15/2014

Pending Closure

3/11/14: The research by SPP Staff led to guidance from SPP Legal and SPP Operations to not post the resource/constraint data or the RLDF data. MPRR167 - approved by MWG on 2/11/14 - removed the Protocol language about the posting of that data. 3/31/2014

Pending Closure

3/11/14: SPP Staff reports that re-pricing was not possible for the dates and hours in question here in this action item. 3/31/2014

Pending Closure