Southwest Power Pool REGIONAL TARIFF WORKING … meeting minutes and... · include Part “358”...

Southwest Power Pool REGIONAL TARIFF WORKING GROUP

Renaissance Tower (AEP Offices) – Dallas, TX March 22, 2012 9:00 A.M. – 3:00 P.M.

-SUMMARY OF ACTIONS TAKEN-

1. The RTWG approved the meeting minutes from February 23, 2012. 2. The RTWG accepted PRR 241 as complying with the tariff language filed and

approved at FERC. 3. The RTWG accepted the tariff revisions included and modified in MPRR 47. 4. The RTWG accepted the tariff revisions included in MPRR 56. 5. The RTWG accepted the tariff revisions included in MPRR 63. 6. The RTWG accepted the tariff revisions included and modified in MPRR 65. 7. The RTWG accepted the tariff revisions included and modified in MPRR 68. 8. The RTWG accepted MPRRs 54, 66 and 67 as having no tariff implications. 9. The RTWG approved the proposed tariff language, as modified, in TRR 058. 10. The RTWG approved the proposed tariff language, as modified, for the Balanced

Portfolio Compliance Filing (Competitive Duties Language). 11. The RTWG approved BPR 018, as modified as, consistent with the Tariff.

Regional Tariff Working Group March 22, 2012

Southwest Power Pool REGIONAL TARIFF WORKING GROUP

Renaissance Tower (AEP Offices) – Dallas, TX March 22, 2012 9:00 A.M. – 3:00 P.M.

-MINUTES-

Agenda Item 1 – Call to Order, Introductions and Receipt of Proxies Chair Dennis Reed called the meeting to order at 9:00 A.M. on March 22, 2012 and asked for a round of introductions. There were 38 persons in attendance either in person or via phone (Attachment 1 – Attendance 03-22-12). Chair Dennis Reed recognized that there was one proxy, David Kays, OGE, held a proxy for Bernie Liu, Xcel Energy (Attachment 2 – Proxy). Chair Dennis Reed also recognized two new members to the RTWG and a new employee on the SPP staff, Keith Tynes, ETEC, Rich Andrysik, LES, and Alfred Busbee, SPP staff, respectively. Agenda Item 2 – Review of Agenda and Additional Agenda Items Chair Dennis Reed reviewed the agenda and asked if there was anything to be added or removed. No changes were requested. Dennis advised that he was considering adding an additional ½ day to the meetings starting in late May through the summer months in order to allow sufficient time to handle the volume of business that is forthcoming. Agenda Item 3 – Approval of Minutes Chair Dennis Reed asked if there were any additions or corrections to the minutes from the February 23, 2012 meeting. There were no changes.

Chair Dennis Reed, hearing no comments or questions, approved the minutes as posted.

Agenda Item 4 – Review of Action Items Heather Starnes, SPP, reviewed and gave updates to the Action Items (Attachment 3 – Action Items). She informed the group that proposed language to address Action Item #63 is set to be presented to the RTWG in late spring or early summer. Regarding Action Item #62, the FERC Order SPP received in January rejected the initial Order 745 compliance filing because FERC wants SPP to include a Net Benefits Test. SPP will not be requesting rehearing and plans on including a Net Benefits Test in its next compliance filing. Heather will send a status update to the RTWG exploder. Susan Polk, SPP, indicated that TRR 059 (Action Item #61) was sent to the Settlements Users Group (SUG) and MWG for review and comment after the February RTWG meeting. The SUG reviewed the TRR with no objections on March 14, 2012, and the MWG reviewed the TRR on March 14, 2012, and will be providing comments to the RTWG (Attachment 4 – TRR 059).

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Three additional Action Items were added. Action Item #64 pertains to revisions to the 10-year ATRR Forecast. Action Item #65 was created to update a reference in Section II (1) of Attachment AI (Criteria for Inclusion of Facilities) to correctly reflect the definition of the term “Base Plan Upgrades”. The provision currently references Section 1.3(h) of the Tariff, which no longer exists. Action Item #66 was created to update the definition of the term “Open Access Same-Time Information System (OASIS)” in the Tariff to include Part “358” of the Commission’s standards of conduct. Agenda Item 5 – Update on the Crediting Process Dena Giessmann, SPP, provided an update on the Crediting Process (Attachment 5 - RTWG Presentation). She reported that the Crediting Process Scope was being circulated for internal review and that requirements were being drafted. SPP has completed 13 long-term stack impact calculations for service upgrades, and are in the process of completing the 4 additional long-term stack impact calculations. There are 31 transmission service facilities and 27 generation interconnection facilities being tracked for credits. Agenda Item 6 – PRR and MPRR Review Marisa Choate, SPP, introduced 10 new MPRRs, 7 of which have tariff implications. She noted that MPRR 51 would not be presented to the RTWG at this time, as the MWG determined that additional work is needed on the MPRR. Carrie Simpson, SPP, presented PRR 241, which requires revisions to PRR 200 for approved tariff language per FERC order in Docket No. ER11-3627. This PRR is to incorporate into the Protocols language consistent with the tariff language approved in Docket No. ER11-3627.

Rob Janssen, Dogwood Energy, made a motion to accept PRR 241 as complying with the tariff language filed and approved at FERC. David Kays, OGE, seconded the motion. The motion passed unanimously. (Attachment 6 – PRR 241)

Marisa Choate, SPP, presented MPRR 44, which replaces the previous offer cap with resource cost-based offer mitigation that is contingent on presence of local market power and a price impact test. It also adds Operating Reserve Offer mitigation to the Market Power Mitigation and Monitoring section. The RTWG did not receive the most updated version of the MPRR, therefore, this MPRR will be discussed on a conference call the week of March 26, 2012. (The MPRR has been not included in the minutes as an attachment.) Marisa Choate, SPP, presented MPRR 47 which clarifies compensation for reliability commitment and dispatch in that Resources that are committed or dispatched out-of-merit or for other reliability reasons will be appropriately compensated. After some discussion, the RTWG made several minor revisions to the Tariff language.

David Kays, OGE on behalf of Bernie Liu, Xcel Energy, made a motion to

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accept the tariff revisions as modified in MPRR 47. Tom Littleton, OMPA, seconded the motion. The motion passed unanimously. (Attachment 7 – MPRR 47)

Marisa Choate, SPP, presented MPRR 56 which corrects the make-whole payment (MWP) cost allocation for load deviation during emergency. The tariff language currently does not contain the capability of exempting a deviation for Real-Time load which is reduced below its Day-Ahead Market cleared quantity during an Emergency.

Rob Janssen, Dogwood Energy, made a motion to accept the tariff revisions included in MPRR 56. Tom Hestermann, SECC, seconded the motion. The motion passed unanimously. (Attachment 8 - MPRR 56)

Marisa Choate, SPP, presented MPRR 63, which clarifies the emergency procedure within the operating hour. A clarification regarding treatment of firm versus non-firm fixed imports was added.

Rob Janssen, Dogwood Energy, made a motion to accept the tariff revisions included in MPRR 33. Llyod Kolb, GSEC, seconded the motion. The motion passed unanimously. (Attachment 9 - MPRR 63)

Marisa Choate, SPP, presented MPRR 65, which modifies the operating reserve qualification re-testing requirements. The proposed language eliminates the retesting requirement if the disqualification/reduction results from normal deployment events and only shuts out Resources for the remainder of the current Operating Day. After some discussion, the RTWG made several minor revisions to the Tariff language.

David Kays, OGE, made a motion to accept the tariff revisions as modified included in MPRR 65. Tom Littleton, OMPA, seconded the motion. The motion passed unanimously. (Attachment 10 – MPRR 65)

Marisa Choate, SPP, presented MPRR 68, which clarifies the excess generation emergency logic. Under capacity shortage conditions, Security Constrained Unit Commitment (SCUC) will rely on Emergency maximum limits and commit reliability Resources on the most economic basis to relieve the shortage while simultaneously attempting to maintain the Regulation-Up requirement. This same logic should also apply under excess generation conditions, where SCUC should make use of Emergency minimum limits to relieve the excess while simultaneously attempting to maintain the Regulation-Down requirement. After some discussion, the RTWG made several minor revisions to the Tariff language.

Charles Locke, KCPL, made a motion to accept the tariff revisions as modified included in MPRR 68. Keith Tynes, ETEC, seconded the motion. This motion passed with one abstention (EDE). (Attachment 11 – MPRR 68)

Marisa Choate, SPP, presented 3 MPRRs which contained no tariff implications. MPRR 54 modifies billing determinants anomalies. MPRR 66 clarifies and enhances the ramp rate logic. MPRR 67 requires wind forecast provisions.

Tom Hestermann, SECC, made a motion to accept the MPRRs as having no tariff implications or impacts. Lloyd Kolb, GSEC, seconded the motion.

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The motion passed unanimously. (Attachments 12, 13, and 14 – MPRR 54, 66, and 67, respectively)

Agenda Item 7 – Short-Term Monthly Service Timing Changes (TRR 058) Rob Janssen, Dogwood Energy, presented TRR 058 (Attachment 15 - TRR 058 Presentation to RTWG) and the proposed tariff revisions for changing the timing requirements for short-term monthly firm service requests. This change would allow service requests to be made farther in advance, potentially matching better with timing of power purchasing opportunities or generation construction. Rob’s presentation included results to issues raised by the RTWG during its February 2012 meeting. After some discussion, the RTWG made several minor revisions to the tariff language.

Tom Littleton, OMPA, made a motion to approve the tariff language as modified in TRR 058. Keith Tynes, ETEC, seconded the motion. The motion passed with two abstentions (Xcel Energy and EDE). (Attachment 16 – TRR 058)

Agenda Item 8 – Balanced Portfolio Compliance Filing (Competitive Duties Language) Susan Polk, SPP, presented the BP Compliance Filing ER08-1419 presentation (Attachment 17 - BP Compliance Filing ER08-1419). Susan discussed that the tariff language presented for the compliance filing narrows the definition of “Competitive Duties” (Attachment 18 - BP Compliance Filing Tariff Sheets 2-2-12_RL-1). Bill Dowling, MIDW, proposed to add new iii) to section VII., 7) d) to clarify that the term “Competitive Duties” does not pertain to an entity that has received a Commission-approved waiver of the Commission’s standards of conduct requirement. (Attachment 19 – BP Compliance Filing Tariff Sheets 2-2-12 – MIDW Modification). After discussion by the group, additional revisions were suggested to incorporate Mr. Dowling’s proposed modification into the compliance language (Attachment 20 - BP Compliance Filing Tariff Sheets 2-2-12_RL-1-Combined).

Robert Pennybaker, AEP, made a motion to approve the tariff language as modified. Tom Littleton, OMPA, seconded the motion. This motion passed with two abstentions (ITC Great Plains and Xcel Energy).

Agenda Item 9 – Withdrawal Obligations (TRR 060) Stacy Duckett, SPP Staff Secretary for the Corporate Governance Committee (CGC), provided a written report to theRTWG on the status for the Withdrawal Obligations (Attachment 21 – TRR 060 RTWG-Report). The report addresses feedback from the RTWG’s February meeting. The RTWG questioned whether applying the provisions to all Network customers under the Tariff, regardless of membership status, was appropriate and/or would be considered equitable at FERC. Following further consideration and given that non-member network load represents approximately 1% of total load (and is expected to decline), the CGC has directed that the draft be revised to

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apply only to member organizations. In addition, any potential mitigation measures to address the impact of non-member network customers will be researched and reported back to the RTWG.

The RTWG and NPPD separately raised concerns that there are no plans to provide credits for future service for any withdrawal fee assessed. Following discussion, the CGC determined to continue to move forward with the current draft providing no credits, but to present this issue at the MOPC and Board meetings in April for discussion and policy direction. In addition, any suggestions from the RTWG would be helpful. The CGC has asked SPP staff to plan to present a more detailed report at the MOPC and Board meetings in April regarding the current draft (revised as noted above) and noting policy considerations for feedback.

Agenda Item 10 - Generator Interconnection Procedures (BPR 018) Jim Hotovy, NPPD and Matt Harward, SPP, presented BPR 018 which provides guidelines for clarifying the application of the SPP Generator Interconnection procedures (Attachment 22 - BPR-018-Generator Interconnection Procedures_BPWG Approved_Feb_28_2012_CLEAN).

Neil Rowland, KMEA, made a motion to approve BPR 018, as modified, as consistent with the tariff. Lloyd Kolb, GSEC, seconded the motion. The motion passed with one abstention (Xcel Energy).

Agenda Item 11 – Task Force Reports

Billing Determinant Task Force - Charles Locke, Chair of the BDTF, review the TO Rate Options (Attachment 23 - TO Rate Options_031212). This file summarizes the calculation options and mitigation measures for Schedules 7, 8 and 11. Due to running short on time, Dennis Reed requested a call be scheduled for March 30, 2012, for the group to review the detailed support behind the calculation options and to allow RTWG to decide if there is a particular method it would like to recommend to MOPC in its April meeting.

Crediting Process Task Force - David Kays, Chair of the CPTF, made a presentation to the group regarding the CPTF recommendations (Attachment 24 - CPTF Recommendations to RTWG_FINAL). David, will be making this presentation to the Cost Allocation Working Group and to MOPC the April.

Rob Janssen, Dogwood Energy, made a motion to support the CPTF recommendations as presented by David Kays. Mitch Williams, WFEC, seconded the motion. The motion passed with one abstention (NPPD).

Agenda Item 13 – Future Meetings

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May 3, 2012 – Dallas, TX (9:00 A.M. – 3:00 P.M.) May 30, 2012 (1:00 P.M. – 5:00 P.M.) and May 31, 2012 (8:30 A.M. – 2:00

P.M.) - Dallas, TX June 27, 2012 (1:00 P.M. – 5:00 P.M.) and June 28, 2012 8:30 A.M. – 2:00

P.M.) - Dallas, TX Agenda Item 14 – Adjournment Chair Dennis Reed adjourned the meeting at 3:08 P.M. on March 22, 2012. Respectfully Submitted- Heather Starnes RTWG Secretary

Regional Tariff Working Group Meeting March 22, 2012

Last Name First Name Company Email Attend

Members

Andrysik

Richard

LES [email protected] X

Dowling

Bill

Midwest Energy, Inc. [email protected] X

Hestermann

Tom Sunflower Electric Power Corp. [email protected] X

Janssen Rob Dogwood Energy [email protected] XKays David Oklahoma Gas & Electric [email protected] X

Kolb

Lloyd Golden Spread Electric Cooperative [email protected] X

Leopold Brett ITC Great Plains [email protected] XLittleton Tom OMPA [email protected] XLiu Bernard Xcel Energy [email protected] X

Locke

Charles Kansas City Power & Light Company [email protected] X

Malone Paul NPPD [email protected] XMcKinnie Adam MoPSC [email protected] Pennybaker Robert American Electric Power [email protected] XReed Dennis Westar Energy [email protected] X Rowland

Neil Kansas Municipal

Energy Agency [email protected] X Shields

Robert Arkansas Electric

Cooperative Corporation [email protected] X Tynes Keith ETEC [email protected] X

Warren Bary Empire District [email protected] XWilliams Mitchell Western Farmers EC [email protected] X

Starnes

Heather

Southwest Power Pool, Inc. [email protected] X

Observers

Alexander Eric GRDA [email protected] Anderson Gene OMPA Andrysik Rich LES [email protected] Jason Kelson Energy [email protected] Ayers- Brasher

Jennifer

EON [email protected]

Bates Kevin Southwest Power Pool [email protected] Matt Wright & Talisman [email protected] XBlaylock Jeff Hilliard EnergyBrinker Kathleen Nemaha-Marshall [email protected] Brown Seth ETEC Brown Shari Southwest Power Pool [email protected] Jannsen KMEA [email protected] Carrie Wright & Talisman [email protected] X

Last Name First Name Company Email AttendBurns Kevin [email protected] Alfred Southwest Power Pool [email protected] XCamp Wayne Accenture [email protected] Campbell Trent OK Corp. Commission [email protected] XCates Charles Southwest Power Pool [email protected] Casey Southwest Power Pool [email protected] Walt MoPSC [email protected] XCharles David Basin Electric Power CoopChoate Marisa Southwest Power Pool [email protected] XCollins Doug OPPD [email protected] Jessica Xcel EnergyCripps Matthew Cleco Power, LLC [email protected] Crissup Phil OGE [email protected] Bruce Xcel Energy [email protected] Daney Neal KMEA D’Antuono Michelle Occidental [email protected] Davis Jason Southwest Power Pool [email protected] Steve Southwest Power Pool [email protected] XDeBaun Tom KCC [email protected] Patrick Southwest Power Pool [email protected] Alex OMPA XDunn Tom Southwest Power Pool [email protected] Justin Tenaska Emanuel Kelly Empire District [email protected] Emery Beth Sunflower / MKEC [email protected] Evans Les KepCo [email protected] Mark Tenaska [email protected] Jason LES [email protected] Kip AEP [email protected] John SPS [email protected] Gallup Terri AEP [email protected] Steve Wind Coalition [email protected] XGay Ryan Southwest Power Pool [email protected] Dena SPP XGhomsi Noumvi MoPSC [email protected] Gillespie Randy Kelson Energy [email protected] Grace Gene AWEA [email protected] Jim Southwest Power Pool [email protected] Don SECI [email protected] Gunesch John Retired OGE [email protected] David KEMA [email protected] Hadlind Harold NPPD [email protected] Sherry Southwest Power Pool [email protected] Ed GRDA [email protected] Harrigill Ryan Southwest Power Pool [email protected] Brenda Occidental [email protected] Hartman Dan [email protected] Harvey John John Deere Wind Energy [email protected] Harward Matt Southwest Power Pool [email protected] xHayes Alison Southwest Power Pool [email protected]

Last Name First Name Company Email AttendHendrix Charles Southwest Power Pool [email protected] Cynthia Xcel Energy [email protected] Helyer Scott Tenaska [email protected] Douglas KCPL [email protected] Holloway Larry Kansas Power Pool (KPP) [email protected] Holtan Archie C.H. Guernsey Engineers [email protected] Horak Frank Astek Windenergy [email protected] Shah Westar Energy, Inc [email protected] Hotovy Jim NPPD [email protected] XHulett Rachel Southwest Power Pool [email protected] John Southwest Power Pool [email protected] Mitch Southwest Power Pool [email protected] Debbie Southwest Power Pool [email protected] XJamieson Chris Duke Energy [email protected] Jones Chris Duke Energy [email protected] Jones Dan Southwest Power Pool [email protected] Virat EPE Consulting [email protected] Kelly George Accenture [email protected] Kelly Patti Southwest Power Pool [email protected] XKirby Joshua WFEC Krajecki Jim CES [email protected] Jon Southwest Power Pool [email protected] David ITC GP XLucas Antoine Southwest Power Pool [email protected] Paul INDN [email protected] Martino Omar Res Americas [email protected] McCord Rick Empire District [email protected] McCraw Phil Southwest Power Pool [email protected] Chris AECI [email protected] Nathan Midwest Energy, Inc. [email protected] Mena Hugo Electric Power Engineers [email protected] Miller Beth Accenture [email protected] XMiller Brittney Arkansas PSC [email protected] Mills John Southwest Power Pool [email protected] Carl Southwest Power Pool [email protected] Catherine Southwest Power Pool [email protected] XMoore Matt GSEC Mosier Pat APSC [email protected] XMushrush Mike OMPA Myers Alan ITC Great Plains [email protected] Newell Gary LAFA CounselNoailles Liam Xcel Energy [email protected] Ohmes Jerry BPU [email protected] Katy KCPL Osburn Dave OMPA [email protected] Purvi ITC Great Plains [email protected] Payton Tom Occidental [email protected] Pemberton Terri [email protected] Polk Susan Southwest Power Pool [email protected] X

Last Name First Name Company Email AttendPrewitt Katherine Southwest Power Pool [email protected] Steve Southwest Power Pool [email protected] XQuinn Susan Westar Energy [email protected] Redden Ronda Oklahoma Gas & Electric [email protected] Reed Wendy Wright and Talisman [email protected]

Resca

Michael Competitive Power Ventures

Ried David OPPD [email protected] Kristen Electric Power Engineers [email protected] Rome Aaron Midwest Energy [email protected] Ross Richard American Electric Power [email protected] Mark Accenture [email protected] Russell Joe OGE [email protected] Robert CES [email protected] Sailors Margaret OPPD [email protected] Samson Eric SPP XSavage Dave RES Americas [email protected] Clint Southwest Power Pool [email protected] XScott Ann Tenaska [email protected] John KMEA [email protected] Aaron Southwest Power Pool [email protected] Walt Shumate & Associates [email protected] Simpson Carrie Southwest Power Pool [email protected] XSmith Patrick Westar Energy [email protected] Richard Electric Power Engineers [email protected] Smith Roger Schiff HardinSpector Barry Wright and Talisman [email protected]

Sundman

Roy Training and Support Services, Inc. [email protected]

Suskie Paul Southwest Power Pool [email protected] Al ETEC [email protected] Thompson Ron NPPD Thumm Brian ITC Holdings [email protected] Tumilty Bob American Electric Power [email protected] Wagner Nicole Southwest Power Pool [email protected] X

Walker

Richard Sustainable Energy Strategies, Inc

Walker Robert Cargilll [email protected] Weatherford Jennifer GRDA [email protected] Wendelgass Paul CPV [email protected] Williams James Invenergy [email protected] Williams Mitchell WFEC [email protected] XWilliams Noman SECI [email protected] Wilson Bryn Oklahoma Gas & Electric [email protected] Gina ITC Transco [email protected] Womack Jimmy Southwest Power Pool [email protected] Thomas ITC Great Plains [email protected]

Southwest Power Pool, Inc. REGIONAL TARIFF WORKING GROUP

Pending Action Items Status Report March 22, 2012

Action Item Date Originated Priority Status Comments

22

What happens when a project has been

directly assigned when it is deferred or

displaced by a new project?

June 25-26, 2008 1 In Progress

Roy Sundman is reviewing the tariff and consulting with RTWG members to clarify the RTWG’s intent. (April 29-30, 2009) Initial discussion had. Expect a report at the August RTWG meeting. Roy Sundman gave a report at the September 2009 RTWG meeting. Progress is being made and SPP Staff from all relevant departments are helping with it. Roy hopes to bring defer and displace issues to discuss at the December RTWG meeting. Roy continues to work on this issue with RTWG members. He may have language to present at the January RTWG meeting. Roy presented his findings during the January 7, 2010 RTWG meeting. Roy is preparing to bring this discussion back to the RTWG at a later date.

36 Complete Schedule 13 Development

April 29-30, 2009 In Progress

The Generation Station Power Task Force will be addressing this issue. (April 29-30, 2009) September 30, 2010, Rob Janssen reviewed the FERC report on the decision with Cal-ISO. RTWG discussed next steps and it was decided that Rob and W&T will meet with FERC before filing anything.

Deleted: January 26


37 Review Crediting

Process of Attachment Z2


The Crediting Process Task Force will be addressing this issue. (April 29-30, 2009) The CPTF is directed to: (1) work with SPP staff (particularly Settlements and Engineering) to implement the Whitepaper, with the goal of submitting a report to the MOPC at each of its meetings up to the time the process goes into production; (2) work with SPP staff to calculate the credits and verify the list of Creditable Upgrades related to the Ag Study results; (3) determine ways of simplifying the Z2 process and provide those recommendations to the CAWG by the end of the year, e.g., A) Eliminate making subsequent uses upgrade sponsors by only assessing the cost of the Creditable Upgrade to match the subsequent customer's actual use of the upgrade. B) Create a de minimis cut-off so that you have to exceed some level of direct assigned costs prior to being eligible to receive credits; and (4) define when you "roll-in" the cost of an upgrade into rates. Additionally, pursuant to discussion at the July 26, 2011 Board of Directors meeting, the CPTF is directed to assess the potential for limiting or eliminating the crediting provision going forward.

43 Review through-and-out rate determination.


The Billing Determinant Task Force is addressing the issue. (April 29-30, 2009) TRR 056 (Rates for Through-and Out Transmission Service) will be presented at the December 8-9. 2011 RTWG meeting. The language was approved during the January 5, 2012 meeting. However, the MOPC remanded the TRR back to the RTWG for further work, giving four specific comments.


51

What to do about generators that have

only built out a portion of the generation facility as specified in the IA?

February 3, 2011 In Progress

Dennis Reed asked Charles Hendrix and SPP Staff to bring a recommendation to the RTWG regarding how to deal with these generators. Charles Hendrix to provide an update at the May 26, 2011 RTWG meeting. The Business Practices Working Group will be addressing this issue as part of their current Generation Interconnection improvement initiative.

54

Develop pre-screening process for Attachment

AR delivery point transfers

March 31, 2011 In Progress

Dennis Reed requested that Steve Purdy develop a possible pre-screening process for delivery point transfers in Attachment AR and to bring it back at a future meeting for the RTWG’s consideration. The Business Practices Working Group will be addressing this issue as part of their current Aggregate Study improvement initiative.

58 Non-Network Generation June 29, 2011 In Progress

Chair Dennis Reed directed the BDTF to: (1) add language requiring data from a NITS Customer (for both its Network Resources and its non-network resources) to be able to accurately calculate its coincident load for billing, and (2) include in NOA/NITS metering requirements for non-network resource generation of a NITS Customer. The BDTF is addressing the issue.

61 Limitation on billing corrections

November 2-4, 2011 In Progress

Add a provision to the Tariff to limit the length of time for billing corrections. (TRR-059)

Assigned to Susan Polk, SPP Staff. During the 2/23/2012 RTWG meeting the TRR was accepted. The TRR was sent to the Settlements Users Group (SUG) and MWG for review and comment. The SUG had no objections. MWG reviewed the TRR and would like additional time for review and provided additional comments.


62 Transmission Losses March 23, 2011 In Progress Roy Sundman and Patti Kelly are working on revising Attachment M. SPP staff is waiting on the Westar case to proceed before resuming any further action.

63 Order 745 February 22, 2012 In Progress Provide a recurring update on the status of SPP’s Order 745

compliance.

64 Revisions to the 10 Year ATRR Forecast March 22, 2012 In Progress

Bary Warren requested a discussion at the May 3, 2012, meeting pertaining to revising the forecast to remove revenue requirements associated with Base Plan Upgrades for those Transmission Owner’s that don’t have a Formula Rate Template.

65

Update reference in Attachment AI , Section II. 1. to correctly reflect the Base Plan Upgrade

Definition

March 22, 2012 In Progress

Dennis Reed requested that the reference in Attachment AI Section II Criteria for Inclusion of Facilities, 1. be updated to correctly reflect the Base Plan Upgrade Definition. Currently, it references Section 1.3(h) of the Tariff, which no longer exists.

66 Update OASIS Definition March 22, 2012 In Progress

Dennis Reed requested that the OASIS definition in the Tariff be updated to include Part “358” of the Commissions standards of conduct.

Deleted: They plan to bring the proposed language to the February 2012 RTWG meeting.

Tariff Revision Request (TRR)

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TRR Number 059 TRR

Title Limitation on the Length of Time Allowed for Billing Corrections

Cross Reference # PRR BRR Other (Specify) _ _____________

Sponsor Name Susan E. Polk for the Regional Tariff Working Group E-mail Address [email protected] Company SPP Phone Number 501-614-3260 Date 2-2-12

Tariff Section(s) Requiring Revision

New Section 10.6 Limitation on Claims Tariff Version (1/31/2012)

Requested Resolution Normal Urgent (provided justification below for urgent

request)

Revision Description

In response to the Regional Tariff Working Group’s request that tariff language be added to limit the length of time allowed for billing corrections (Action Item 61), staff proposes to limit the time period within which parties may seek billing adjustments under the Tariff and also to limit when SPP may make billing adjustments to charges and/or credits assessed pursuant to the Tariff. The proposal consists of a new section 10.6, Limitation on Claims. (Note: This language will not apply to billings related to the implementation of the credit stacking process.)

Reason for Revision

The proposed tariff revisions are intended to provide certainty with respect to charges and credits assessed to Market Participants and Transmission Customers resulting from their participation in the SPP EIS Market pursuant to Attachment AE and/or receipt of transmission service under the Tariff.

Stakeholder Approval Required (specify date and record outcome of vote; n/a for those stakeholders not required)

MWG reviewed 3/14/12, with comments to the RTWG Settlement User Group reviewed the language with no objection 3/13/12 BPWG (n/a) TWG (n/a) ORWG (n/a) Other (specify) (n/a) RTWG approved 2/23/12, subject to review by the MWG and Settlement User Group MOPC Board of Directors

Deleted: (n/a)


Page 2 of 7

Legal Review Completed

Yes (Include any comments resulting from the review)

No

Market Protocol Implications or Changes

Yes (Include a summary of impact and/or specific changes & PRR #)

No

Business Practice Implications or Changes

Yes (Include a summary of impact and/or specific changes & BPR #)

No

Criteria Implications or Changes

Yes (Include a summary of impact and/or specific changes)

No Other Corporate Documents Implications (i.e., SPP By-Laws, Membership Agreement, etc.)

Yes (Include which corporate documents)

No

Credit Implications


No

Impact Analysis Required

Yes

No


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Proposed Tariff Language Revisions (Redlined)

10.6 Limitation on Claims:

Except as otherwise specified in Section 7.1 of this Tariff or Sections 7.1 or 7.3 of

Attachment AE to this Tariff:

(a) No claim seeking an adjustment in the billing for any service, transaction, or charge

under the Tariff may be asserted if more than two years has elapsed since the first

date upon which the billing for that week or month occurred. The Transmission

Provider may make no adjustment to billing with respect to any service,

transaction, or charge under this Tariff if more than two years has elapsed since the

first date upon which the billing for that week or month occurred, unless a claim

seeking such adjustment had been received by the Transmission Provider prior to

the end of the two-year period.

(b) For claims that arose prior to the effective date of Section 10.6 of the Tariff, the

claimant shall have two years from the effective date to assert such claims.

Current Tariff Provisions to be Reconciled:

7.1 Billing Procedure:

Within a reasonable time after the first day of each month, the Transmission

Provider shall submit an invoice to the Transmission Customer for the charges for all

services furnished under the Tariff during the preceding month. The invoice shall be paid

by the Transmission Customer within fifteen (15) days of receipt. All payments shall be

made in immediately available funds payable to the Transmission Provider, or by wire

transfer to a bank named by the Transmission Provider. Invoices may be issued using


Page 4 of 7

estimated data, to the extent actual data is not available by the fifth (5th) working day of

the month following service. Adjustments reflecting the difference in billing between the

estimated and actual data will be included on the next regular invoice, with such

adjustment being due when that invoice is due. Any other corrections found to be

necessary will be made on the next regular monthly invoice.

Bills will be adjusted to correct for all provable meter errors. Billing adjustments

for reasons other than (a) the replacement of estimated data with actual data for service

provided, or (b) provable meter error, shall be limited to those corrections and adjustments

found to be appropriate for such service within one year after rendition of the bill reflecting

the actual data for such service. Adjustments shall be made for any billing with a

monetary impact in excess of 2% of the billing for the relevant period for an individual

Transmission Customer or any aggregation thereof. At its sole discretion, the

Transmission Provider may make billing adjustments for lesser amounts.

Attachment AE 7.1 Settlement Statements

(a) The Transmission Provider shall issue a preliminary settlement statement for an Operating

Day no later than 7 Calendar Days following the applicable Operating Day unless the 7th

day following the applicable Operating Day is not a Business Day, in which case, the

preliminary settlement statement shall be issued on the first Business Day thereafter.

(b) The Transmission Provider shall issue a final settlement statement for an Operating Day no

later than 47 Calendar Days following the applicable Operating Day unless the 47th

Calendar Day following the applicable Operating Day is not a Business Day, in which

case, the final settlement statement shall be issued on the first Business Day thereafter.

(c) The Transmission Provider shall make corrections to the preliminary and final settlement

statements for an Operating Day for data errors and settlement statement disputes that have

been resolved. Settlement associated with a specific Operating Day shall be considered


Page 5 of 7

final at the end of the 365th Calendar Day following the applicable Operating Day.

(d) To the extent that a Market Participant, or its designated meter agent, does not submit

meter data representing that Market Participant’s actual hourly Resource output and load

consumption in accordance with the timelines specified in the Market Protocols, the

Transmission Provider shall use estimated data for that Market Participant that is equal to

that Market Participant’s Scheduled Generation and Scheduled Load for the applicable

hours for the purposes of calculating the preliminary statements specified under Sections

7.1(a). To the extent a Meter Agent does not submit data representing the Net Actual

Interchange, the Transmission Provider will substitute hourly integrated Adjusted Net

Scheduled Interchange. In the event that actual meter data is not submitted prior to the

issuance of a final settlement statement, the Transmission Provider shall use the best

available data, which may include estimated meter data as developed by the Transmission

Provider, for the purposes of calculating final settlement statements.

7.3 Invoice Disputes

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

concerning any initial, final or Resettlement settlement statements contained within an invoice that cannot

be resolved to the Market Participant’s satisfaction, such disputes shall be resolved as follows:

a) In the case of a dispute relating to an initial or final settlement statement, the Market

Participant must notify the Transmission Provider within 90 Calendar Days following the

issue date of the applicable invoice of the items that the Market Participant wishes to

dispute. In the case of Resettlement statements, the Market Participant must notify the

Transmission Provider within 30 Calendar Days following the issue date of the applicable

invoice of the items contained in that statement that the Market Participant wishes to

dispute, which issues must relate to incremental changes in data that occurred between

issuance of the final settlement statement and the first Resettlement statement or between

Resettlement statements.

The notice of dispute must contain the following minimum information:

• Statement type (initial, final, resettlement 1-11, ad hoc resettlement)


Page 6 of 7

• Charge type

• Estimated dispute amount in dollars

• Operating Day

• Start interval

• End interval

• Statement ID

• Transmission Customer

• Settlement Location

• Long description

• Short description.

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

a submitted notice of dispute, the Transmission Provider shall notify the Market Participant

no later than 30 days following the date the notice of dispute was submitted to the

Transmission Provider. The Market Participant must then submit additional information to

the Transmission Provider within 30 days in order to have the notice of dispute considered

valid.

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

approval or denial of the submitted notice of dispute within 20 Business Days following

the close of the applicable 90 day or 30 day window specified under subsection 7.3(a) or

subsection 7.3(b). If the Transmission Provider estimates that it will take longer than the

20 Business Day window to analyze a specific billing dispute, the Transmission Provider

shall notify the Market Participant and provide an estimate of the amount of time required

to complete the analysis.

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

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

Market Participant may initiate the dispute resolution procedures specified under Section

12 of this Tariff. Deleted:


Page 7 of 7

Proposed Market Protocol Language Revision (Redlined) n/a

Proposed Business Practices Language Revision (Redlined)

n/a

Proposed Criteria Language Revision (Redlined)

n/a

Revisions to Other Corporate Documents (Redlined)

n/a

Crediting Process Update

March 22, 2012

Dena Giessmann, Lead Project [email protected]∙ 501.614.3238


• Scope in internal review

• Requirements being drafted

• Next steps

– Complete requirements

– Internal review and approval of requirements

– Engage Vendors

Financial Upgrade Cost Tracking

Short Term TSR Impact Calculator

Settlements enhancement2


• There have been 13 stacks created for Creditable Facilities.

– There are 31 transmission service facilities and 27 generation interconnection facilities being tracked for credits.

• There are 4 additional stack creations in progress

– TDF Calculations are being performed to bridge the gap in data that may exist.

• Depending on the need for N‐1 scans for Sponsored Projects, 10 more stacks could be completed by next update.

3


• Potential Obstacles:

– Determination of timeframe for tracking credits on projects associated service that rolled over from PTP to NITS.

– Possible addition of trackable facilities due to the completion of 2010‐AGP1.

This adds another layer to already created stacks.

– Verification of appropriateness of input files needed for TDF calculations.

4

Attachment 06 - PRR 241 Recommendation Report 3/28/2012 Page 1 of 4

PRR Recommendation Report

PRR No. PRR241 PRR

Title Revisions to PRR 200 Approved Language per FERC Order

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.: 9.2.2 Title: Out of Merit Energy (OOME) Protocol Version: 30.0

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change


The proposed revisions to the Protocols are to ensure that the Tariff language approved by FERC in compliance with the October 20, 2011 order in ER11-3627-000 as filed by SPP on November 21, 2011 and approved by order from FERC on February 8, 2012 is incorporated into the Protocols consistent with the Tariff. The October 2011 order approved the language as proposed in PRR 200 (Keep Whole Payments for Out of Merit Energy Dispatch) but the Commission determined that SPP’s proposed OOME compensation mechanism may compensate resources “for more than the amount of the under-recovery,” and therefore directed SPP to “make a compliance filing with the Commission that caps the compensation under the proposal to the amount of the under-recovery caused by the OOME directive.” The language proposed below for the Protocols is verbatim to what was approved by FERC in February 2012. In addition to the language approved in the February order, there is a reference that was incorporated inadvertently from the original tariff language approved that references “Section 5.6 of this Attachment AE”. This is recommended to be changed to “Section 5.6(a)(viii) of SPP OATT Attachment AE” both places it appears in the Protocol language currently – see below.

Tariff Implications or Changes

Yes – Section No: (Include a summary of impact and/or specific changes) Tariff language has already been accepted by FERC on February 8, 2012 in Docket No. ER11-3627-001.

No

MWG Review PRR Recommendation

Date of Vote: 3-13-2012—Unanimously approved with modifications All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A

EIS Market

Integrated Marketplace


RTWG Review

ORWG Review

MOPC Recommendation

Board Review

Date 2/24/2012

SponsorName Patti Kelly E-mail Address [email protected] Company SPP Regulatory Staff Phone Number 501.614.3381

Comments ReceivedComment Author MWG Date 3/13/2012 Comment Description Clarification

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

Proposed Protocol Language Revision

9.2.2 Out of Merit Energy (OOME) a. SPP may issue reliability directives to any on-line Resource to resolve Emergency conditions

(referred to in the system as “OOME,” or out of merit energy). A Resource will receive OOME instructions for the duration of the reliability directive. SPP will issue manual OOME instructions at the MW level the Resource is expected to produce until such time as the constraint can be resolved by SCED through the EIS market. SPP will make every effort to define and activate the appropriate constraints in MOS and the IDC within one hour of the manual reconfiguration. SPP shall coordinate resolution of the Emergency condition with the appropriate Balancing Authority (ies). When an OOME is created notifications will immediately be issued for all future intervals for which an EIS Dispatch Instruction has already been sent. The OOME notification for future intervals not yet dispatched will be sent directly following the EIS Dispatch Instruction for those intervals. So Market Participants will receive an OOME Dispatch Instruction for each interval that supersedes the EIS Dispatch instruction for the same interval.

b. More than one OOME may be initiated for the same Resource within a given interval. In such a case the OOME instruction indicating the latest timestamp will be utilized.

c. SPP will notify the Market Participant when the OOME event has ended.

Uninstructed Deviation will be automatically waived and Uninstructed Deviation Charges will not be assessed for a Resource for each interval it receives an OOME instruction consistent with Section 8.5.6. For the duration of the reliability directive:


a. Each Resource with an OOME instruction that results in an increase in Resource output that creates a sale or an increase in a sale to the EIS market will be paid, for its additional output attributable to its response to the OOME Dispatch Instruction, at the higher of the LIP determined by the security constrained economic dispatch for the Resource Settlement Location or the Resource offer curve price at the OOME dispatch point (“OOME Sale Compensation”). If such offer price exceeds the LIP, the difference between the two prices will be multiplied by the minimum of OOME Dispatch Instruction and actual output minus the Resource scheduled quantity in order to calculate the credit that is recoverable through the revenue neutrality uplift process (Section 5.6(a)(viii) of SPP OATT Attachment AE). The OOME Sale Compensation shall be limited to the amount necessary to compensate the resource for any under-recovery resulting from its response to the OOME dispatch instruction.

b. Each Resource with an OOME instruction that results in a decrease in generation that creates a purchase or an increase in a purchase from the EIS market will pay, for its EIS market purchase attributable to its response to the OOME Dispatch Instruction, at the lower of the LIP determined by the security constrained economic dispatch for the Resource at the Settlement Location or the Resource offer curve price at the OOME dispatch point (“OOME Purchase Compensation”). If the LIP exceeds such offer price, the difference between the two prices will be multiplied by the Resource scheduled quantity minus the maximum of the OOME Dispatch Instruction and the actual output in order to calculate the credit that is recoverable through the revenue neutrality uplift process (Section 5.6(a)(viii) of SPP OATT Attachment AE). The OOME Purchase Compensation shall be limited to the amount necessary to compensate the resource for any under-recovery resulting from its response to the OOME dispatch instruction.

c. Settlement calculations for any partial hour OOME instructions will be scaled by the number of intervals so that each 5-minute dispatch interval is settled for 1/12th of the value indicated by the appropriate price.

Proposed Tariff Language Revision

Note: This language is for informational purposes only – it was filed by SPP on November 21, 2011 and accepted by FERC in compliance with order dated October 20, 2011 in Docket No. ER11-3627 related to original PRR 200. These revisions to this language as redlined below were approved by FERC in the same docket on February 8, 2012. Sections 4.4(c)(i) and (ii) of the SPP OATT:

(c) When SPP issues a reliability directive to any on-line Resource to resolve an Emergency

Condition (referred to in the system as “OOME” or out of merit energy) and for the

duration of the reliability directive, SPP will determine the appropriate credit for the

OOME dispatch as follows:

(i) Each Resource with an OOME instruction that results in an increase in Resource

output that creates a sale or an increase in a sale to the EIS Market will be paid,

additional output attributable to its response to the OOME dispatch instruction, at

the higher of the LIP determined by the security constrained economic dispatch

for the Resource Settlement Location or the Resource offer curve price at the

Deleted: for its EIS Market sale up

Deleted: this

Comment [p1]: This was in the PRR report but was apparently copied from the Tariff language portion. This needs to be modified to reflect the proper reference to either the Tariff or the Protocols or both. I have suggested the redlines. I did not find similar language in the Protocols. (Whatever is decided, the same will need to be done to next section.)

Deleted: above

Deleted: this

Deleted: for its EIS Market sale up


OOME dispatch point (“OOME Sale Compensation”). If such offer price exceeds

the LIP, the difference between the two prices will be multiplied by the minimum

of the OOME dispatch instruction and actual output minus the Resource schedule

quantity in order to calculate the credit that is recoverable through the revenue

neutrality uplift process (Section 5.6 of this Attachment AE). The OOME Sale

Compensation shall be limited to the amount necessary to compensate the

resource for any under-recovery resulting from its response to the OOME

dispatch instruction.

(ii)Each Resource with an OOME instruction that results in a decrease in Resource output that creates a purchase or an increase in a purchase from the EIS Market will pay, for its EIS Market purchase

attributable to its response to the OOME Dispatch Instruction, at the lower of the LIP determined by the security constrained economic dispatch for the Resource at the Settlement Location or the Resource

offer curve price at the OOME dispatch point (“OOME Purchase Compensation”). If the LIP exceeds such offer price, the difference between the two prices will be multiplied by the Resource scheduled

quantity minus the maximum of the OOME Dispatch Instruction and the actual output in order to calculate the credit that is recoverable through the revenue neutrality uplift process (Section 5.6 of this

Attachment AE). The OOME Purchase Compensation shall be limited to the amount necessary to compensate the resource for any under-recovery resulting from its response to the OOME dispatch

instruction. Proposed Criteria Language Revision

N/A

Deleted: above

Deleted: ¶

Attachment 07 - MPRR 47 Recommendation Report1-1 3/14/2012 Page 1 of 14


PRR No. Marketplace-PRR47 PRR

Title Clarification of Compensation for Reliability Commitment and Dispatch

Timeline

Normal Expedited Urgent Action Provide explanation if Expedited and/or Urgent Action is selected: This issue was raised during the 12/6/2011 MOPC review of the Integrated Marketplace Attachment AE. The tariff language was approved but an action item was assigned to the MWG to clarify the compensation for resources that are committed or dispatched out of merit or for other reliability reasons. This PRR is marked for expedited to ensure the change is included in the February 2012 FERC filing of the Marketplace tariff language.


Approve Reject


Defer Refer




Section No.: 1., 4.4.1.2, 4.4.2.4, 4.5.9.9 Title: Glossary, Intra-Day RUC Execution, Out-of-Merit Energy (OOME) Dispatch, Real-Time Out-Of-Merit Amount Protocol Version: 6.0



Revision Description Clarifies that Resources that are committed or dispatched out of merit or for other reliability reasons will be appropriately compensated.


Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE: 6.1.2 Intra-Day Reliability Unit Commitment Execution; 6.2.4 Out-of-Merit Energy Dispatch

No


Date of Vote: 3/14/2012 All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: Opposed—Westar

RTWG Review

ORWG Review

MOPC Recommendation

Board Review

EIS Market



Date 12/20/2011

SponsorName Jessica Collins E-mail Address [email protected] Company Xcel Energy/SPS Phone Number 303.571.7740

Reasons for Opposing Dissenter Westar Date 3/14/2012

Reason

Westar Energy, Inc. supports that a resource should receive make-whole payment for instances where the resource is being committed or de-committed, and/or redispatched by its host Transmission (TOP) to mitigate a local problem. MPRR 47 enables the cost recovery of such make-whole payments through an uplift. We raised the following concerns - (i) is it appropriate for the entire market to bear the costs of mitigation of a local area problem that may only benefit the local TOP area? and (ii) if entire market continues to pays for those costs indefinitely, does such a policy create the appropriate long run economic incentive for the TOP to develop a permanent solution of the local area problem(s)? Westar had advocated the following: (i) an after-the-fact SPP analysis of TOP actions to determine whether only the load in that TOP area benefitted from the TOP action or if the TOP action resulted in pro-active avoidance of region-wide reliability problems, and (ii) recovery of the costs from those who benefitted from the TOP actions, e.g., if TOP action resulted in pro-active avoidance of region-wide reliability problems, then use of the uplift would be appropriate; otherwise, the costs would be allocated to the loads in the local TOP area.

Comments ReceivedComment Author Westar Date 12/21/2011

Comment Description

We support make-whole payment for the resource(s) being committed or de-committed, and/or redispatched by its host TOP, for cost incurred for adhering to its host TOP’s instructions to mitigate local reliability and/or local emergency. We suggest the following criteria to determine “local” event - the event is occurring in facilities that SPP does not monitor, and/or is embedded in distribution systems, or is an event SPP had failed to monitor and react despite having visibility.

However, for recovery of appropriate make-whole payments in these situations should not be automatic through OOME and OOMC mechanisms. We suggest that recovery of these make-whole payments should be allocated to loads resident in that TOP area; Attachment H of the OATT should be used to determine the appropriate load.

We also suggest that the Market Participants having load obligation in that TOP area should be given the opportunity to pursue an alternative method to recover any charges mentioned above. If so, we recommend the following procedure:

• Affected load-serving MP(s) should make an explicit request to SPP no later than 30 [or tbd] calendar days following the local event.

• SPP Staff (Operations, Reliability Coordinator, Market Operator, Balancing Authority Operator, etc) should perform an after the fact analysis. The focus of this analysis should be to determine

o Absent the TOP’s actions, whether the local disturbance would


have propagated to a larger disturbance affecting the bulk power system outside that TOP area, and

o If the TOP’s actions benefitted only the local TOP area or the entire RTO.

• Staff should complete this analysis within [tbd] weeks of the date of the request.

• Staff would present this analysis to the ORWG. ORWG’s role would be review the Staff analysis and determine accuracy of Staff’s conclusion.

• Provided that Staff analysis and ORWG review conclude that (i) absent TOP actions, the local disturbance would have propagated to the Bulk Power System outside the TOP area, and (ii) those actions benefitted all Market Participants - staff would perform additional study to determine appropriate compensation to the affected Resource(s) according to OOME and/or OOMC mechanisms.

• MWG’s role would be to review and recommend compensation and cost recovery to MOPC. MOPC’s role would be to act on MWG’s recommendation.

We also support after the fact analysis to generate “lessons learnt” and “best practices.”

Comment Status Comments were taken into consideration. The approved language is reflected in this recommendation report.

Comments Received

Comment Author Xcel Date 2/22/2012

Comment Description These comments are being submitted to address items discussed during the 1/4/2012 and 1/24/2012 MWG meetings.


Comments Received

Comment Author OMPA Date 2/24/2012

Comment Description These comments are predominantly editorial. However, it is not clear why the TOP should be issuing manual instructions in the Day Ahead Market. In addition the procedure to be followed by SPP in the event of an OOME described in 4.4.2.4 didn't seem to cover the TOP initiated OOME.


Comments Received

Comment Author SPP Date 3/6/2012

Comment Description There comments are being submitted in effort to ensure that MPRRs 47 and 52 are not in conflict. The only area that had any overlap of content changes was section 4.4.2.4 (b) and is marked with a comment to indicate the minor change.


Comments Received

Comment Author OMPA Date 3/8/2012

Comment Description I have made some additional changes to Section 4.4.2.4 of the protocols and the corresponding tariff language to try to make what happens in an OOME clearer. I


also deleted some of my earlier comment boxes.


Comments Received


Comment Description In 4.4.2.4, changes to (a) thru (e) were struck and redline changes were inserted to match the redline changes proposed in MPRR 52. Additionally, changes to the Glossary and to the paragraph leading into the actions (a) thru (e) were made based on discussion at the MWG March 13-14, 2012 meeting.


Comments Received

Comment Author MWG Date 3/14/2012 Comment Description Clarification



1. Glossary Commit Time

The time specified by SPP or a local Transmission Operator in a commit order at which a Resource should be synchronized and at or above Minimum Economic Capacity Operating Limit. Transmission Operator

De-Commit Time

The time specified by SPP or a local Transmission Operator in a de-commit order at which a Resource should begin de-synchronization procedures. Transmission Operator

4.3.2.2 Day‐Ahead RUC Execution

Using the inputs described above, SPP performs a capacity adequacy analysis for the upcoming Operating Day using the SCUC algorithm. The capacity adequacy analysis provides advisory information to the SPP Operators.

(1) The objective of the SCUC is to commit Resources to meet the SPP Mid-Term Load Forecast and Operating Reserve requirements over the Operating Day such that commitment costs are minimized while adhering to transmission system security constraints and the resource operating parameter constraints submitted as part of the RTBM Offers;

(2) Commitment costs are defined as Start-Up Offer, No-Load Offer and incremental cost to operate at minimum output as defined in the submitted Energy Offer Curve. Incremental Energy costs

Deleted: with a commit status of “Market” or “Reliability” that was committed by SPP in the DA Market or any Reliability Unit Commitment process

Deleted: or the time specified by a local

Deleted: in a commit order issued within an Operating Day at which an available off-line Resource should be synchronized and at or above Minimum Economic Capacity Operating Limit.

Deleted: with a Commitment Status of “Market” or “Reliability” that was committed by SPP in the DA Market or any Reliability Unit Commitment process

Deleted: or the time specified by a local

Deleted: in a de-commit order issued with an Operating Day at which a Resource committed by a local

Deleted: Transmission Operator

Deleted: should begin de-synchronization procedures.


above minimum output and Operating Reserve Offers are not considered by the RUC SCUC in making commitment decisions;

(3) The SCUC algorithm will initially consider commitment of Resources with a Commit Status of Market or Self only including capacity up to the Resources’ Maximum Economic Capacity Operating Limit (or Maximum Regulation Capacity Operating Limit if selected for Regulation-Up) and down to the Resources Minimum Economic Capacity Operating Limit (or Minimum Regulation Capacity Operating Limit if selected for Regulation-Down).

(a) If this capacity is not sufficient to meet the system-wide SPP Mid-Term Load Forecast plus Operating Reserve requirements, the SCUC algorithm study will, in priority order: (1) curtail non-firm Export Interchange Transactions until the capacity shortage is eliminated; (2) incorporate capacity up to Resources’ Maximum Emergency Capacity Operating Limit and/or commit Resources’ with a Commit Status of Reliability on an economic basis until the capacity shortage is eliminated while attempting to maintain the Regulation-Up requirement to the extent possible.

(b) If the sum of Self-Committed capacity at minimum output, fixed Import Interchange Transaction Offers and the system-wide Regulation-Down requirement is in excess of the sum of the SPP system-wide Mid-Term Load Forecast and fixed Export Interchange Transactions, the RUC SCUC algorithm study will, in priority order: (1) curtail non-firm fixed Import Interchange Transactions until the capacity surplus is eliminated; (2) reduce Resource capacity down to the Resources’ Minimum Emergency Capacity Operating Limit for Resources not selected for Regulation-Down until the capacity surplus is eliminated; (3) de-commit Resources that were committed in the DA Market with a Commit Status of Market until the capacity surplus in eliminated; and (4) de-commit Self-Committed Resources until the capacity surplus in eliminated.

(i) If there is a transmission constraint within a Reserve Zone occurring simultaneously with a Reserve Zone excess capacity event, SCUC may commit additional Resources and/or de-commit Resources to relieve the constraints provided that any commitment changes do not aggravate the excess capacity situation.

(c) To the extent that a particular reliability issue cannot be directly addressed within the SCUC algorithm as described under subsection (a) and (b) above, SPP may manually commit Resources with a Commit Status of Reliability and de-commit Resources with a Commit Status of Self to alleviate such reliability issues in accordance with its authority as Reliability Coordinator.

(i) An emergency condition may arise within the operating area of a local Transmission Operator that may involve elements not monitored by SPP. Such emergencies may require out of merit commitment, decommitment or dispatch instructions to be issued to

Deleted: is either on its distribution system or


one or more Resources to resolve the emergency. In such cases, the local Transmission Operator shall request SPP to issue such instructions.

Any curtailment of schedules, use of Reliability Status Resources or use of Emergency operating limits by the RUC algorithms will only be advisory information to the SPP RUC Operators. Day-Ahead RUC and Intra-Day RUC Operators will determine which of these options should be acted on and when as described in the Day-Ahead and Intra-Day RUC Results sections.

4.4.1.2 Intra‐Day RUC Execution

Using the inputs described above, SPP performs a capacity adequacy analysis for the upcoming Operating Day and throughout the Operating Day using a SCUC algorithm. The capacity adequacy analysis provides advisory information to the SPP Operators.


(2) Commitment costs are defined as Start-Up Offer, No-Load Offer and incremental cost to operate at minimum output as defined on the submitted Energy Offer Curve. Incremental Energy costs above minimum output and Operating Reserve Offers are not considered by the RUC SCUC in making commitment decisions;



(b) If the sum of Self-Committed capacity at minimum output, fixed Import Interchange Transaction Offers and the system-wide Regulation-Down requirement is in excess of the sum of the SPP system-wide Mid-Term Load Forecast and fixed Export Interchange Transactions, the SCUC algorithm study will, in priority order: (1) curtail non-firm fixed Import Interchange Transactions until the capacity surplus is eliminated; (2) reduce capacity down to the Resources’ Minimum Emergency Capacity Operating Limit for

Comment [GA1]: Should this be happening in the DA period?


Resources not selected for Regulation-Down until the capacity surplus is eliminated; (3) de-commit Resources that were committed in the DA Market with a Commit Status of Market until the capacity surplus is eliminated; and (4) de-commit Self-Committed Resources that were committed following the Day-Ahead RUC process until the capacity surplus is eliminated.

(i) If there is a transmission constraint within a Reserve Zone occurring simultaneously with a Reserve Zone excess capacity event, RUC may commit additional Resources to relieve the constraints provided that the additional commitment does not aggravate the excess capacity situation.

(d) To the extent that a particular reliability issue cannot be directly addressed within the SCUC algorithm as described under subsection (a) and (b) above, SPP may manually commit Resources with a Commit Status of Reliability and de-commit Resources with a Commit Status of Self to alleviate such reliability issues in accordance with its authority as Reliability Coordinator.

(e) An emergency condition may arise within the operating area of a local Transmission Operator that may involve elements not monitored by SPP. Such emergencies may require out of merit commitment, decommitment or dispatch instructions to be issued to one or more Resources to resolve the emergency. Time permitting, the local Transmission Operator shall request SPP to issue such instructions. To the extent time does not permit, the local Transmission Operator may issue such instructions to the Resource in accordance with its authorities as a reliability entity. In such cases, the following shall take place:

(i) If initial instructions are issued by a local Transmission Operator, the Transmission

Operator shall notify SPP of the instructions given to the Resource.

(ii) The Transmission Operator and SPP will coordinate to ensure subsequent

instructions are provided by SPP.

(iii) SPP shall log such instructions as manual commitment, decommitment or Out-of-

Merit Dispatch instruction, as appropriate, as if it gave such instruction to the

Resource.

(iv) The Resource shall be eligible to receive the compensation for such instructions

whether issued by SPP or the local Transmission Operator.

(v) In the event of a Transmission Operator directive, the Transmission Operator and

SPP shall collaborate to provide a report with an after-the-fact analysis of the event.

All such reports shall be made available to the appropriate stakeholder groups for


Deleted: ORWG


review on a quarterly basis in the month following the end of the quarter in which

the event occurred and will be used to determine the best practice for addressing this

type of emergency situation in the future.

4.4.2.4 Out‐of‐Merit Energy (OOME) Dispatch

SPP or a local Transmission Operator may issue reliability directives via a Manual Dispatch Instruction to any on-line Resource to resolve a reliability issue (referred to in the system as OOME, or out-of-merit energy). In such an event, A Resource will receive Setpoint Instructions from SPP that include a Manual Dispatch Instruction for the duration of the reliability directive or may receive a Manual Dispatch Instruction directly from a local Transmission Operator. The Manual Dispatch Instructions will specify the MW level the Resource is expected to produce until such time as the constraint can be resolved by SCED through the RTBM. Such MW levels may include (i) dispatch below a Resource’s Minimum Economic Capacity Operating Limit down to Minimum Normal Capacity Operating Limit or Minimum Emergency Capacity Operating Limit as system conditions warrant or (ii) dispatch above a Resource’s Maximum Economic Capacity Operating Limit up to Maximum Normal Capacity Operating Limit or Maximum Emergency Capacity Operating Limit as system conditions warrant. SPP will make every effort to define and activate the appropriate constraint.

When an OOME event occurs, the Transmission Operator may, when necessary, issue Manual Dispatch instructions directly to the affected Resource(s) and will notify SPP that it has done so and SPP will ensure that the following occurs:

(a) Notifications are immediately issued that an OOME has been initiated and the MW level the resource is supposed to produce;

(b) Setpoint Instructions and Economic/Emergency Minimum and Economic/Emergency Maximum Limits for the current dispatch interval are immediately adjusted to the OOME MW level that has been issued;

(c) Setpoint Instructions for future intervals and Economic/Emergency Minimum and Economic/Emergency Maximum limits not yet dispatched will be set to the OOME MW level that has been issued;

(d) SPP notifies the Market Participant when the OOME event had ended;

(e) Asset Owners are compensated for OOME events in accordance with Section 4.5.9.9.

4.5.9.9 Real‐Time Out‐Of‐Merit Amount

(1) A RTBM credit or charge1 will be made to each Market Participant with a Resource that receives a Manual Dispatch Instruction from SPP or a local Transmission Operator that creates a cost to the

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

Deleted: r

Deleted: or may receive the Manual Dispatch Instruction directly from a local


Deleted: .

Deleted: SPP will issue

Deleted: Resource will receive

Deleted: at

Comment [GA2]: I think this process is spelled out more clearly in the proposed tariff language.

Deleted: takes the following actions

Deleted: <#>Notifications are immediately issued Manual Dispatch Instrutions overriding for all future intervals for which a SCED Dispatch Instructions which hasve already been calculated and included in the Resource Setpoint Instruction; <#>Setpoint Instructions for future intervals not yet dispatched will include the Manual Dispatch Instruction whether issued by SPP or the

Comment [c3]: Undeleted on Gene’s comments to account for changes in MPRR 52

Deleted: <#>Transmission Operator

Deleted: <#> in Setpoint Instructions for future intervals not yet dispatched instead of the SCED Dispatch Instruction for thosee same intervals; ¶<#>SPP notifyies the affected Market Participant when the OOME event hasd ended; ¶<#>Asset Owners are compensated Asset Owners for OOME events, including OOME events issued directly by a local

Deleted: <#>Transmission Operator

Deleted: <#> in accordance with Section 4.5.9.9.¶

Deleted: for all future intervals for which a SCED Dispatch Instruction has already been calculated and included in the Resource Setpoint Instruction;

Deleted: for future intervals not yet dispatched will include the Manual Dispatch Instruction instead of the SCED Dispatch Instruction for the same interval;

Deleted: after which ¶Limits are reset to the Market Participant submitted limits are used and Energy, Regulation, Spinning Reserve, and Supplemental Reserve products are cleared based on the member submitted offer;

Comment [MBC4]: This language is consistent with the changes proposed in MPRR 52.

Deleted: SPP

Deleted: a Manual Dispatch Instruction issued by


Asset Owner or that adversely impacts the Asset Owner’s DA Market position and/or if a Market Participant must buy back its DA Market position for any Operating Reserve product at a RTBM MCP that is greater than that product’s DA Market MCP. The amount will be calculated on a Dispatch Interval basis under the following conditions:


1.1 Definitions and Acronyms

Commitment Instruction

An instruction issued by the Transmission Provider or a local transmission operator to a Market

Participant to either start up or shut down a specified Resource in the Day-Ahead Market or any

Reliability Unit Commitment process transmission operator

Commit Time

The time specified by the Transmission Provider or a local transmission operator in a Commitment

Instruction at which a Resource is to be synchronized and operating at or above its Minimum Economic

Capacity Operating Limit.

De-Commit Time

The time specified by the Transmission Provider or a local transmission operator in a Commitment

Instruction at which a Resource is to begin de-synchronization procedures.

5.2.2 Day‐Ahead Reliability Unit Commitment Execution [Protocols Section 4.3.2.2]

The Transmission Provider will perform a capacity adequacy analysis for the upcoming

Operating Day using the SCUC algorithm with the objective of committing Resources to meet

the Transmission Provider load forecast and Operating Reserve requirements over the Operating

Deleted: T

Deleted: O

Deleted: or an instruction issued by a local


Deleted: to a Market Participant to either start up or shut down a specified Resource within the Operating Day.¶

Deleted: T

Deleted: O

Deleted: T

Deleted: O


Day such that commitment costs are minimized while adhering to Transmission System security

constraints and the Resource operating parameter constraints submitted as part of the RTBM

Offers.

(1) Commitment costs used in the SCUC are defined as Start-Up Offer, No-Load Offer and

incremental cost to operate at minimum output as defined in the submitted Energy Offer

Curve.

(2) The SCUC algorithm will initially consider commitment of Resources not specified for

reliability only use as described in Section 4.1(10)(b) of this Attachment AE, up to the

Resources’ Maximum Economic Capacity Operating Limit or Maximum Regulation

Capacity Operating Limit if selected for Regulation-Up, and down to the Resources’

Minimum Economic Capacity Operating Limit or Minimum Regulation Capacity

Operating Limit if selected for Regulation-Down.

(a) If this capacity is not sufficient on a system-wide basis to meet the Transmission

Provider load forecast plus Operating Reserve requirements, the SCUC algorithm

will, in priority order: (1) Curtail non-firm fixed Export Interchange Transaction

Bids until the capacity shortage is eliminated; and (2) Incorporate capacity up to

Resources’ Maximum Emergency Capacity Operating Limits and/or commit

Resources designated as reliability only use, as described in Section 4.1(10)(b) of

this Attachment AE, on an economic basis until the capacity shortage is

eliminated while attempting to maintain the Regulation-Up requirement, to the

extent possible.

(b) If there is a capacity surplus on a system-wide basis calculated as the sum of self-

committed capacity at minimum output, fixed Import Interchange Transaction

Offers and the Regulation-Down requirement that is in excess of the sum of the

Transmission Provider load forecast and fixed Export Interchange Transaction

Bids, the SCUC algorithm will, in priority order: (1) curtail non-firm fixed Import

Interchange Transaction Offers until the capacity surplus is eliminated; (2)

incorporate capacity down to Resources’ Minimum Emergency Capacity

Operating Limits for Resources not selected for Regulation-Down until the

capacity surplus is eliminated; (3) de-commit Resources that were committed by

the Transmission Provider in the Day-Ahead Market that were not self-committed


until the capacity surplus is eliminated; and (4) de-commit self-committed

Resources until the capacity surplus is eliminated.

(3) To the extent that a particular Transmission System security constraint cannot be directly

addressed within the SCUC algorithm, the Transmission Provider may manually commit

Resources and/or decommit self-committed Resources to alleviate such a Transmission

System security constraint in accordance with its authority as Reliability Coordinator.

(a) An emergency condition may arise within the operating area of a local

transmission operator that may involve elements not monitored by the

Transmission Provider. Such emergencies may require out of merit commitment,

decommitment or dispatch instructions to be issued to one or more Resources to

resolve the emergency. In such cases, the local transmission operator shall request

the Transmission Provider to issue such instructions.

6.1.2 Intra‐Day Reliability Unit Commitment Execution [Protocols Section 4.4.1.2]

Using the inputs described in Section 6.1.1, the Transmission Provider will perform a

capacity adequacy analysis using the SCUC algorithm with the objective of committing

Resources to meet the Transmission Provider’s load forecast and Operating Reserve

requirements over the Operating Day such that commitment costs are minimized while adhering

to Transmission System security constraints and the resource operating parameter constraints

submitted as part of the RTBM Offers.


incremental cost to operate at minimum output as defined on the submitted Energy Offer

Curve. Incremental Energy costs above minimum output and Operating Reserve Offers

are not considered by the SCUC in making commitment decisions.


reliability only use as described in Section 4.1(10)(b) of this Attachment AE, only

including capacity up to the Resources’ Maximum Economic Capacity Operating Limits

(or Maximum Regulation Capacity Operating Limits if selected for Regulation-Up) and

down to the Resources’ Minimum Economic Capacity Operating Limits (or Minimum

Regulation Capacity Operating Limits if selected for Regulation-Down).

Deleted: T

Deleted: O


Deleted: T

Deleted: O



Provider’s load forecast plus Operating Reserve requirements, the SCUC

algorithm will, in priority order: (1) Curtail non-firm fixed Export Interchange

Transaction Bids until the capacity shortage is eliminated; and (2) Incorporate

capacity up to Resources’ Maximum Emergency Capacity Operating Limits

and/or commit Resources designated as reliability only use, as described in

Section 4.1(10)(b) of this Attachment AE, on an economic basis until the capacity

shortage is eliminated while attempting to maintain the Regulation-Up

requirement to the extent possible.

(b) If there is a system-wide capacity surplus calculated as the sum of self-committed

capacity at minimum output, fixed Import Interchange Transaction Offers and the

Regulation-Down requirement that is in excess of the sum of the Transmission

Provider load forecast and fixed Export Interchange Transaction Bids, the Day-

Ahead Market SCUC algorithm will, in priority order: (1) Curtail non-firm fixed

Import Interchange Transaction Offers until the capacity surplus is eliminated; (2)

Incorporate capacity down to Resources’ Minimum Emergency Capacity

Operating Limits for Resources not selected for Regulation-Down until the

capacity surplus is eliminated; (3) De-commit Resources that were committed by

the Transmission Provider in the Day-Ahead Market that were not self-committed

until the capacity surplus is eliminated; and (4) De-commit self-committed

Resources until the capacity surplus is eliminated.

(3) To the extent that a particular reliability issue cannot be directly addressed within the

SCUC algorithm as described under subsections (a) and (b) above, the Transmission

Provider or local transmission operator may manually commit Resources and/or

decommit self-committed Resources to alleviate such reliability issues.

(4) An emergency condition may arise within the operating area of a local transmission operator that may involve elements not monitored by the Transmission Provider. Such emergencies may require out of merit commitment, decommitment or dispatch instructions to be issued to one or more Resources to resolve the emergency. Time permitting, the local transmission operator shall request the Transmission Provider to issue such instructions. To the extent time does not permit, the local transmission operator may issue such instructions to the Resource. In such cases, the following shall take place:

Deleted: T

Deleted: O

Deleted: in accordance with its authority as Reliability Coordinator

Deleted: T

Deleted: O

Deleted: is

Deleted: either on its distribution system or

Deleted: T

Deleted: O

Deleted: T

Deleted: O

Deleted: in accordance with its authorities as a Reliability Entity.


(a) If initial instructions are issued by a local transmission operator, the transmission

operator shall notify the Transmission Provider of the instructions given to the

Resource.

(b) The transmission operator and Transmission Provider will coordinate to ensure

subsequent instructions are provided by the Transmission Provider.

(c) The transmission operator shall log such instructions, and shall notify the

Transmission Provider of such action. The Transmission Provider shall log such

instructions as manual commitment, decommitment or Out-of-Merit Dispatch

instruction, as appropriate, as if it gave such instruction to the Resource.

(d) The Resource shall be eligible to receive the compensation for such instructions

whether issued by the Transmission Provider or the local transmission operator.

6.2.4 Out‐of‐Merit Energy Dispatch [Protocols Section 4.4.2.4]

The Transmission Provider or local transmission operator may issue OOME dispatch

directives to any on-line Resource to resolve Emergency Conditions. Time permitting, OOME

dispatch directives will be issued by the Transmission Provider. The Transmission Provider will

make every effort to define and activate the appropriate constraints in RTBM SCED within one

(1) hour of the manual reconfiguration. If initial instructions are issued by the local

transmission operator, the transmission operator shall coordinate with the Transmission Provider

to ensure subsequent instructions are provided by the Transmission Provider

When an OOME event occurs, the ransmission operator may, when necessary, issue Manual

Dispatch Instructions directly to the affected Resources and notify the Transmission Provider

that it has done so and the Transmission Provider will take the following actions:

(1) Notifications are immediately issued that an OOME has been initiated and the

Transmission Provider will issue Manual Dispatch Instructions at the MW level the

Resource is expected to produce until such time as the constraint can be resolved by

SCED through the RTBM;

Deleted: T

Deleted: O

Deleted: T

Deleted: O

Deleted: T

Deleted: O

Deleted: SPP

Deleted: SPP

Deleted: T

Deleted: Provider

Deleted: s

Deleted: T

Deleted: O

Deleted: T

Deleted: O

Deleted:




Deleted: SPP

Deleted:

Deleted: (1) A Resource will receive Issue Setpoint Instructions that include a Manual Dispatch Instruction for the duration of the reliability directive;¶(2) The Transmission Provider will iIssue Manual Dispatch Instructions at the MW level the Resource is expected to produce until such time as the constraint can be resolved by SCED through the RTBM;¶(3) Notifyications are immediately issuedthe Resource of for all future intervals for which a SCED Dispatch Instruction has already been calculated and included in the Resource Setpoint Instruction;¶(4) Include the Manual Dispatch Instruction in Setpoint Instructions for future intervals not yet dispatched will include the Manual Dispatch Instruction instead of the SCED Dispatch Instruction for the same interval;¶(5) The Transmission Provider will nNotify the Market Participant when the OOME event has ended; and¶(6) If initial instructions are issued by the local


Deleted: , the


Deleted: shall coordinate with the Transmission Provider to ensure subsequent instructions are provided by the Transmission Provider. Market Participants are ... [1]

Deleted: (1) A Resource will receive ... [2]

Deleted: 2

Deleted: T


(2) For the current dispatch interval and all future dispatch intervals not yet dispatched by the

SCED, a Resource will receive Setpoint Instructions that are equal to the Manual

Dispatch MW Instruction for the duration of the OOME;

(3) The Transmission Provider will notify the Market Participant when the OOME event has

ended; and

(4) Market Participants are compensated for OOME events in accordance with Section 8.6.6

of this Attachment AE.

Proposed Criteria Language Revision N/A

Deleted: A

Deleted: for the current Dispatch Interval and all future Dispatch Intervals not yet dispatched by SCED

Deleted: reliability directive

Deleted: (3) Notifications are immediately issued for all future intervals for which a SCED Dispatch Instruction has already been calculated and included in the Resource Setpoint Instruction;¶

Deleted: (4) Setpoint Instructions for future intervals not yet dispatched will include the Manual Dispatch Instruction instead of the SCED Dispatch Instruction for the same interval;¶

Deleted: 5

Deleted: 6

Comment [MBC5]: This language is consistent with the changes proposed in MPRR 52.

[1] Deleted Marisa Choate 3/14/2012 8:19:00 AM

shall coordinate with the Transmission Provider to ensure subsequent instructions are provided

by the Transmission Provider. Market Participants are cCompensated Market Participants for

OOME events in accordance with Section 8.6.6 of this Attachment AE.

Page 13: [2] Deleted accenture1 2/1/2012 11:06:00 AM

(1) A Resource will receive Setpoint Instructions that include a Manual Dispatch

Instruction for the duration of the reliability directive;

Attachment 08 - MPRR 56 Recommendation Report 3/6/2012 Page 1 of 6



Title Correction of MWP Cost Allocation for Load Deviation During Emergency

Timeline

Normal Expedited Urgent Action Provide explanation if Expedited and/or Urgent Action is selected: Expedited has been chosen to properly inform all parties of the software design and business process changes that may impact their products.


Approve Reject


Defer Refer




Section No.: 4.5.9, 4.5.9.10 & 4.4.4.1.2 (new sub-section) Title: Real-Time Balancing Market Settlement, RUC Make-Whole-Payment Distribution Amount & Load Deviation Exemptions Protocol Version: 2.0



Revision Description Protocols currently do not contain the capability of exempting a deviation for Real-Time load which is reduced below its Day-Ahead Market cleared quantity during an Emergency.


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

No


Date of Vote: 2/22/2012—Unanimously approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A

RTWG Review

ORWG Review

MOPC Recommendation

Board Review

EIS Market



Date 2/9/2012

SponsorName Tony Alexander E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3303

Comments ReceivedComment Author SPP Date 2/16/2012

Comment Description Some clarification of the criteria in which a load is exempt from deviation calculations is necessary. If the emergency condition is a generation excess no exemptions should be granted.


Comments Received


Comment Description Additional clarification of the criteria in which a load is exempt from deviation calculations is necessary. If the emergency condition is a generation excess no exemptions should be granted.



4.5.9.10 RUC Make-Whole-Payment Distribution Amount

(1) A RTBM charge or credit1 will be calculated at each Settlement Location for each Asset Owner for each hour in order to fund the payments made under Section 4.5.9.8. The amount will be determined by multiplying the Asset Owner deviations by a daily RTBM MWP rate.

The hourly amount is calculated as follows:

(a.1) An Asset Owner’s Settlement Location deviation is calculated as the Absolute Value of the sum of (1) (RTBM actual load MWh - DA Market cleared load MWh) – excluding deviations resulting from actual load consumption that is less than DA Market cleared load MWh during capacity shortage condition Emergencies, (2) (RTBM actual Export Interchange Transactions – DA Market cleared Export Interchange Transactions), (3) (RTBM actual Import Interchange Transactions – DA Market cleared Import Interchange Transactions), (4) (RTBM actual Through Interchange Transactions (sink only) – DA Market cleared Through Interchange Transactions (sink only)), (5) DA Market cleared Virtual

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

Deleted: excepting

Deleted: reduction


Energy Bids * (-1), and (6) DA Market cleared Virtual Energy Offers * (-1). An Asset Owner’s Settlement Location deviation is calculated as follows.

#RtNetSlDev5minQty a, s, i =

{ [ IF XmptDev5minFlg a, s, i = 0 THEN 1 ELSE 0 ] * [Max ( 0, RtBillMtr5minQty a, s, i ) – Max ( 0, DaClrdHrlyQty a, s, h )]

+ [∑t

Max ( 0, RtImpExp5minQty a, s, i, t, dir )

- ∑t

Max ( 0, DaImpExp5minQty a, s, i, t, dir )

+ [ IF DIR <> “THROUGH”, THEN

∑t

Min ( 0, RtImpExp5minQty a, s, i, t, dir )

- ∑t

Min ( 0, DaImpExp5minQty a, s, i, t, dir ), ELSE 0 ] ]

* (1 – RsgCrdFlgt ) - ∑t

DaClrdVHrlyQty a, s, h, t } / 12

4.5.9 Real-Time Balancing Market Settlement

(8) Make-Whole payments for SPP committed Resources as described in (7) above are collected on a daily basis from Market Participants based upon their pro-rata share of the sum of following quantities for the Operating Day as described in detail under Section 4.5.9.10:

(a) The absolute value of the net Settlement Location deviations from DA Market cleared amounts for load, virtual transactions and interchange transactions – excluding deviations resulting from actual load consumption that is less than DA Market cleared load MWh during capacity shortage condition Emergencies;

4.4.4.1.1 URD Exemptions

A Resource’s URD in a Dispatch Interval shall be considered equal to zero (0) under the following situations:

(1) The Resource is deployed for Contingency Reserve;

Deleted: excepting load reduction during shortage condition Emergencies


(2) The Resource trips or is derated after receiving Dispatch Instructions;

(3) There is missing or bad Resource SCADA data in the Dispatch Interval;

(4) During a system Emergency if the URD is above the Resource’s Setpoint Instruction in a shortage condition or if the URD is below the Resource’s Setpoint Instruction during an excess generation condition;

(5) If a Dispatch Instruction is issued to a Resource beyond the reported capabilities due to the application of a VRL;

(6) If the Resource is part of a Common Bus and the URD calculated at the Common Bus is less than the Operating Tolerance calculated at the Common Bus;

(7) SPP may set Uninstructed Resource Deviation to zero (0) to the extent a Market Participant can demonstrate such deviation was caused solely by events or conditions beyond its control, and without the fault or negligence of the Market Participant. The Market Participant must provide SPP with adequate documentation through the invoice dispute process in order for the Market Participant to be eligible to avoid such Uninstructed Resource Deviation. SPP shall determine through the dispute process whether such Uninstructed Resource Deviation should be waived.

4.4.4.1.2 Load Deviation Exemptions

A load is exempt from deviation based charges for cost allocation of RUC MWP under the following situations:

(1) The load Real-Time Billing Meter Quantity is less than it’s Day-Ahead Market cleared quantity during a capacity shortage condition Emergency;


6.4.1.1 Uninstructed Resource Deviation Exemptions [Protocols Section 4.4.4.1.1]

A Resource’s URD in a Dispatch Interval will be considered equal to zero (0) under the

following situations:

(1) The Resource is deployed for Contingency Reserve; or

(2) The Resource trips off-line or is derated after receiving Dispatch Instructions; or

(3) There is missing or bad Resource SCADA data in the Dispatch Interval; or

(4) If during Emergency Conditions the URD is above the Resource’s Setpoint Instruction in

a shortage condition or the URD is below the Resource’s Setpoint Instruction during an

excess generation condition; or

Deleted: billable metering

Deleted: m

Deleted: n


(5) If a Dispatch Instruction is issued to a Resource beyond the reported capabilities due to

the application of a VRL; or

(6) If the Resource is part of a Common Bus and the URD calculated at the Common Bus is

less than the Operating Tolerance calculated at the Common Bus; or

(7) A Market Participant can demonstrate such deviation was caused solely by events or

conditions beyond its control, and without the fault or negligence of the Market

Participant. The Market Participant must provide the Transmission Provider with

adequate documentation through the invoice dispute process in order for the Market

Participant to be eligible to avoid such URD. The Transmission Provider will determine

through the dispute process whether such URD should be waived.

6.4.1.2 Load Deviation Exemptions [Protocols Section 4.4.4.1.2]

A load is exempt from deviation based charges for cost allocation under Section 8.6.7

under the following situations:

(1) The RTBM billable metering for load is less than that load’s Day-Ahead Market cleared

quantity during a capacity shortage condition Emergency.

8.6.7 Reliability Unit Commitment Make Whole Payment Distribution Amount [Protocols

Section 4.5.9.10]

An RTBM charge will be calculated at each Settlement Location for each Asset Owner

for each hour in order to fund the payments made under Section 8.6.5. The amount will be

determined by multiplying An Asset Owners distribution volume by a daily RUC make whole

payment rate as follows:

RUC Make Whole Payment Distribution Amount =

[(RUC SPP Make Whole Payment Distribution Rate) * (RUC Make Whole Payment Distribution Volume)]

(1) The RUC SPP Make Whole Payment Distribution Rate is the sum of all make whole

payments for the Operating Day as calculated under Section 8.6.5, divided by the sum of

Asset Owners’ RUC Make Whole Payment Distribution Volumes for all Settlement

Locations for the entire Operating Day.

Deleted: of RUC MWP

Deleted: actual Metered

Deleted: load

Deleted: it’s


(2) An Asset Owner’s RUC Make Whole Payment Distribution Volume at a Settlement

Location for an hour is equal to the sum of following values that are calculated for each

Dispatch Interval within the hour:

(a) The absolute value of the sum of actual Real-Time Settlement Location deviations

from Day-Ahead Market cleared amounts for load, virtual transactions and

interchange transactions except that, during any Dispatch Interval in which the

Transmission Provider has declared an Emergency Condition due to a capacity

shortage, Real-Time actual load deviations from Day-Ahead Market cleared

amounts shall be limited to deviations associated with actual Real-Time load in

excess of amounts cleared in the Day-Ahead Market;

Proposed Criteria Language Revision

N/A

Deleted: generation




Title Clarification to Emergency Procedure within the Operating Hour

Timeline



Approve Reject


Defer Refer




Section No.: 4.4.2.2.2 Title: Emergency Operations – Excess Generation Protocol Version: 6.0




Current wording is unclear as to whether the specified steps should be taken in a priority order of actions to be taken by SPP operators to alleviate excess generation conditions within the Operating Hour. This MPRR clarifies that SPP can should take these actions as needed. Additionally, a correction is needed to remove an invalid reference to Fixed Dispatch Status for Energy, as this status does not exist. Additionally, a clarification regarding treatment of firm versus non-firm fixed imports was added.


Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE: 6.2.2.2 Emergency Operations – Excess Generation

No


Date of Vote: 2/22/2012—Approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: Opposed—Westar

RTWG Review

ORWG Review

MOPC Recommendation

Board Review

EIS Market



Date 2/10/2012

SponsorName Jim Gonzalez E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.1636

Reasons for Opposing Dissenter Westar Date Reason No comments received

Comments ReceivedComment Author Date Comment Description None Comment Status


4.4.2.2.2 Emergency Operations – Excess Generation

(1) SPP operators may take any or all of the following actions, as time permits, within the Operating Hour to address excess generation conditions on either a system-wide or Reserve Zone basis, that were not alleviated through actions taken prior to the Operating Hour:

(a) Notify any remaining Resources not cleared for Regulation-Down that were not notified prior to the Operating Hour that those Resources will be dispatched down to their Minimum Emergency Capacity Operating Limits;

(b) De-commit any remaining Resources that were Self-Committed following the Day-Ahead RUC process;

(c) Curtail any remaining non-firm fixed Import Interchange Schedules pro-rata;

(d) Curtail fixed firm Import Interchange Schedules pro-rata;

(e) Reduce Resources with cleared Regulation-Down economically, as needed, down to Minimum Emergency Capacity Operating Limit;

(f) Coordinate with Generation Operators, SPP BA Operator and SPP Reliability Coordinator to de-commit generation to meet power balance.

(2) If actions taken under (1) above are not sufficient to relieve the excess generation condition in any Dispatch Interval either on a system-wide basis or Reserve Zone basis, LMPs will be set by the Offers prices associated with Energy down to the Minimum Emergency Capacity Operating Limit or zero, whichever is less, to the extent that the Regulation-Down requirement can be maintained. If the actions under (1) above create a Regulation-Down shortage during any

Deleted: that do not have a Dispatch Status of Fixed

Deleted: that were submitted and approved following the Day-Ahead RUC process

Deleted: <#>Reduce Resources with a Dispatch Status of Fixed and Variable Energy Resources pro-rata down to Minimum Emergency Capacity Operating Limits;¶

Deleted: any remaining

Deleted: 9


Dispatch Interval either on a system-wide basis or Reserve Zone basis, the MCPs for Regulation-Down will reflect Scarcity Prices and LMPs will reflect negative Scarcity Prices as described under Section 4.1.5;

(3) In parallel with the actions under (1) above, if there is a transmission constraint within a Reserve Zone occurring simultaneously with a Reserve Zone excess capacity event, SPP operators may take the following additional actions:

(a) Identify and communicate with owners of Resources with greater than a 5% Generation Shift Factor (“GSF”) on the constraint and fixed Import Interchange Transactions with greater than a 3% transfer distribution factor on constraint;

(b) Issue TLR to curtail any Interchange Transactions that may be contributing to the loading;

(c) Commit Quick Start Resources in the constrained area if they can be re-dispatched with other Resources in constrained area to relieve constraint without contributing to the excess capacity situation.


6.2.2.2 Emergency Operations – Excess Generation

(1) The Transmission Provider will take any or all of the following actions, as time permits,

within the Operating Hour to address excess generation conditions on either a system-

wide or Reserve Zone basis:

(a) Notify any remaining Resources not cleared for Regulation-Down and not

notified prior to the Operating Hour that they will be dispatched down to their

Minimum Emergency Capacity Operating Limits;

(b) De-commit any remaining Resources that were self-committed following the

Day-Ahead RUC;

(c) Pro-rata curtail, on a MW basis, any remaining fixed non-firm Import Interchange

Transactions;

(d) Pro-rata curtail, on a per MW basis, any fixed firm Import Interchange

Transactions;

(e) Reduce Resources with cleared Regulation-Down economically, as needed, down

to Minimum Emergency Capacity Operating Limit; and

Deleted: C

Deleted:

Deleted: that were submitted and approved following the Day-Ahead RUC

Deleted: remaining


(f) Coordinate with generation Operators, SPP Balancing Authority Operator and

SPP Reliability Coordinator to de-commit generation to meet power balance.

(2) If actions taken under (1) above are not sufficient to relieve the excess generation

condition in any Dispatch Interval either on a system-wide or Reserve Zone basis, LMPs

will be set to the lesser of zero (0) or the Offer prices associated with Energy down to the

Minimum Emergency Capacity Operating Limit, to the extent that the Regulation-Down

requirement can be maintained. If the actions under (1) above create a Regulation-Down

shortage during any Dispatch Interval either on a system-wide or Reserve Zone basis, the

MCPs for Regulation-Down will reflect Scarcity Prices and LMPs will reflect negative

Scarcity Prices.

(3) In parallel with the actions under (1) above, if there is a transmission constraint within a

Reserve Zone occurring simultaneously with a Reserve Zone excess capacity event, the

Transmission Provider may take any or all of the following additional actions:

(a) Identify and communicate with the Market Participant concerning Resources with

greater than a five percent (5%) generation shift factor on the constraint and fixed

Import Interchange Transactions with greater than a three percent (3%) transfer

distribution factor on constraint;

(b) Issue Transmission Loading Relief (“TLR”) provisions, in accordance with

Attachment R, to curtail any Interchange Transactions that may be contributing to

the loading;

(c) Commit Quick Start Resources in the constrained area if they can be re-

dispatched with other Resources in the constrained area to relieve constraint

without contributing to the excess capacity situation.


N/A




Title Changes to Operating Reserve Qualification Re-Testing Requirements

Timeline



Approve Reject


Defer Refer




Section No.: 4.4.3.3, 4,4,3,4, 6.1.11.1, 6.1.11.2 Title: Regulation Deployment, Contingency Reserve Deployment, Spin Qualified Resources, Supplemental Qualified Resources Protocol Version: 8.0




This MPRR addresses the concern that requiring a retest for partial failures and/or short term inability to respond to regulation deployment signals would be burdensome on both SPP and MPs and are not necessary, given that most failures of this nature are due to short-term physical problems that can be corrected by the next Operating Day. The language proposed eliminates the retesting requirement if the disqualification/reduction results from normal deployment events and only shuts out Resources for the remainder of the current Operating Day. SPP retains the ability to perform random deployment tests and retesting requirements for random test failure still apply relaxes the requirements for passing a retest



Attachment AE: 2.10.1 – Spin Qualified Resource, 2.10.2 – Supplemental Qualified Resources, 6.3.2 – Contingency Reserve Deployment.

No



RTWG Review

ORWG Review

MOPC Recommendation

Board Review

EIS Market



Date 2/10/2012

SponsorName Jim Gonzalez E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3200



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 on a pro-rata basis based upon Regulation-Up and/or Regulation-Down cleared MW, adjusted as needed to ensure deliverability. 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 4-10. 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 4-10 shows the all of the available Resource Control Statuses in the AGC system.

Deleted: wil

Deleted: l

Deleted: disqualify that Resource as a Regulation Qualified Resource, Regulation-Up Qualified Resource or Regulation-Down Qualified Resource and that Resource must pass a re-test as described under Section 6.1.11.3 in order to be re-certified.


4.4.3.4 Contingency Reserve Deployment

Contingency Reserve procured in the RTBM will be deployed through a Contingency Reserve Deployment Instruction, via both Inter-Control Center Communications Protocol (ICCP) and Extensible Markup Language (XML) instruction except in the case of a Block Demand Response Resource which only receives an XML instruction, following a system event, normally following the sudden loss of a Resource. The following rules apply to the deployment of Contingency Reserve for both internal SPP BA contingencies and for providing assistance to a Reserve Sharing Group member. Scheduling procedures for provision of assistance to/from Resource Sharing Group members are described under Section Error! Reference source not found.:

(1) Contingency Reserve is deployed on Resources with cleared Contingency Reserve and Export Interchange Transactions providing Supplemental Reserve in the Dispatch Interval immediately following the system event;

(2) Spinning Reserve and on-line Supplemental Reserve is deployed ahead of off-line Supplemental Reserve;

(3) A Resource with deployed Spinning Reserve and/or on-line Supplemental Reserve that moves into “Manual” Control Status will continue to be issued a Setpoint Instruction that includes the amount of Spinning Reserve and/or Supplemental Reserve deployed on that Resource as described under Exhibit 4-10;

(4) If the amount of Spinning Reserve and on-line Supplemental Reserve cleared is greater than or equal to the Contingency Reserve amount required in response to a contingency, no off-line Supplemental Reserve is deployed;

(5) Spinning Reserve and on-line Supplemental Reserve is deployed in proportion to the amount of Spinning Reserve and on-line Supplemental Reserve cleared on each Resource, adjusted as needed to ensure deliverability;

(6) Supplemental Reserve from off-line Quick-Start Resources is deployed on Resources in merit order based on economics of Start-Up Offer, No-Load Offer, Energy Offer Curves and Minimum Run Time, adjusted as needed to ensure deliverability. For the purposes of deploying Supplemental Reserve supplied from Export Interchange Transactions, as described under Section Error! Reference source not found., the merit order cost will be equal to zero;

If a Resource fails all four of the tests described under Section 4.4.4.3 and the Resource’s individual smallest positive Shortfall Quantity is greater than 25% of the Contingency Reserve Deployment Instruction, the amount of Contingency Reserve available to be cleared on Resource will be reduced by that percentage based on the current Contingency Reserve Ramp Rate, for online deployment, or Maximum Quick-Start Response Limit for offline deployments, for the remainder of the Operating Day. 6.1.11 Operating Reserve Certification

Asset Owners of registered Resource must meet the following certification requirements in order to be eligible to submit Operating Reserve Offers for use in the SPP Integrated Marketplace.

Deleted: .

Deleted:

Deleted: ¶


6.1.11.1 Spin Qualified Resources

There are no specific testing requirements for a Resource to become a Spin Qualified Resource. An Asset Owner will self-certify that its Resource is capable of deploying Spinning Reserve or on-line Supplemental Reserve during the registration process. In such case, that Resource will become a Spin Qualified Resource. However, in order to verify that any cleared Spinning Reserve or on-line Supplemental Reserve is capable of being deployed, SPP may perform on-line Contingency Reserve deployment tests as follows:

(1) SPP will issue an Out-Of-Merit-Energy instruction to the Resource to get a stable dispatch prior to the start of the test;

(2) SPP will modify the Out-Of-Merit-Energy instruction to the Resource being tested as follows:

(i) If this is a random on-line Contingency Reserve deployment test, SPP will issue a Out-Of-Merit-Energy instruction equal to the amount of online Contingency Reserve cleared on the Resource.

(ii) If this is a retest requested by an Asset Owner, SPP will issue an Out-Of-Merit-Energy instruction equal to the amount of online Contingency Reserve available to be cleared on the Resource without the cap enforced as a result of the previously failed test.

(3) Simultaneously with the beginning and end of the on-line Contingency Reserve deployment test (which will span a period equivalent to the Contingency Reserve Deployment Period), SPP will take a snapshot of the Resource MW output. The difference between the Resource MW output at the end of the test and the Resource MW output at the beginning of the test will be equal to the Resource response.

(a) SPP will communicate the results of the test to the affected Asset Owner no later than 60 minutes following the end of the test.

(b) If the Resource response is greater than or equal to 75% of the MW specified in the deployment instruction, the Resource has passed the test and the Out-Of-Merit-Energy instruction and any previous online Contingency Reserve caps will be released.

(i) For settlement purposes, this instruction shall be considered a Manual Dispatch Instruction and the Resource will be eligible for compensation for Out-Of-Merit-Energy as described under Section Error! Reference source not found..

(ii) If this test was a retest requested by the Asset Owner as described under (c) below, the Resource will not be eligible for compensation for Out-Of-Merit-Energy as described under Section Error! Reference source not found..

(c) If the Resource response is less than 75% of the MW specified in the deployment instruction, the Resource has failed the test and the following actions will be taken:

Deleted: random

Deleted: <#>Random deployment tests may include Spinning Reserve deployment in response to actual Contingency Reserve deployment events as described under Section 4.4.3.2¶

Deleted: only perform a Spinning Reserve or on-line Supplemental Reserve deployment test on a Resource that

Deleted: <#> has cleared for Spinning Reserve or Supplemental Reserve in Real-Time (and not Regulation-Up and Regulation-Down) and that has not had a change in Dispatch Instruction between the last Dispatch Interval and the current Dispatch Interval; ¶

Deleted: issue

Deleted: a

Deleted: Contingency Reserve D

Deleted: deployment Iinstruction

Deleted: that is equal to the amount of on-line SpinningContingency Reserve cleared on the Resource

Deleted: ;

Deleted:

Deleted: Spinning Reserve or

Deleted: Supplemental


Deleted: I

Deleted: no further action is required


Deleted: I


(i) The Resource will not be eligible for compensation for Out-Of-Merit-Energy as described under Section Error! Reference source not found.;

(ii) SPP will cap the amount on-line Contingency Reserve available to be cleared on that Resource to the Resource response observed in the test or zero, whichever is larger, until such time that the Resource requests and passes a retest;

(iii) The Asset Owner of the Resource must obtain SPP approval regarding the timing of the retest.

(iv) The Out-Of-Merit-Energy instruction will be released.

6.1.11.2 Supplemental Qualified Resources

There are no specific testing requirements for an off-line Resource to become a Supplemental Qualified Resource. An Asset Owner will self-certify that its off-line Resource is capable of deploying Supplemental Reserve during the registration process. In such case, that Resource will become a Supplemental Qualified Resource. However, in order to verify that any cleared Supplemental Reserve is capable of being deployed, SPP may perform Supplemental Reserve deployment tests as follows:

(1) SPP will only perform a Supplemental Reserve deployment test on an off-line Quick-Start Resource that has cleared Real-Time Supplemental Reserve;

(2) SPP will issue an Out-Of-Merit-Energy instruction to the Resource being tested as follows:

(i) If this is a random Supplemental Reserve deployment test, SPP will issue an Out-Of-Merit-Energy instruction equal to the amount of off-line Supplemental Reserve cleared on the Resource.

(ii) If this is a retest requested by an Asset Owner, SPP will issue an Out-Of-Merit-Energy instruction equal to the amount of off-line Supplemental Reserve available to be cleared on the Resource without the cap enforced as a result of the previously failed test.

(3) Simultaneously with the end of the Supplemental Reserve deployment test (which will span a period equivalent to the Contingency Reserve Deployment Period), SPP will take a snapshot of the Resource MW output. The Resource MW output at the end of the test will be equal to the Resource response.

(a) SPP will communicate the results of the test to the affected Asset Owner no later than 60 minutes following the end of the test.

(b) If the Resource response is greater than or equal to 75% of the MW specified in the deployment instruction, the Resource has passed the test and the Out-Of-Merit-Energy instruction will be released and any previous Contingency Reserve caps will be released.

Deleted: by multiplying the deployed MW amount by Resources submitted Ramp-Rate-Up and Ramp Rate by the Resource response percentage

Deleted: random Contingency

Deleted: <#>Random deployment tests may include Supplemental Reserve deployment in response to actual Contingecy Reserve deployment events as described under Section 4.4.3.2.¶

Deleted: Contingency Reserve

Deleted: Ddeployment Iinstruction

Deleted: that is equal to the amount of Supplemental Reserve cleared on the Resource;

Deleted: difference between the


Deleted: I

Deleted: no further action is required.


(i) For settlement purposes, this instruction will be considered as an SPP commitment and the Resource will be eligible for RUC Make-Whole-Payment compensation as described under Section Error! Reference source not found..

(ii) If this test was a retest requested by the Asset Owner as described under (c) below, the Resource will not be eligible for RUC Make-Whole-Payment compensation as described under Section Error! Reference source not found..

(c) If the Resource response is less than 75% of the MW specified in the deployment instruction, the Resource has failed test and the following actions will be taken:

(i) The Resource will not be eligible for compensation for RUC Make-Whole-Payment compensation as described under Section Error! Reference source not found.;

(ii) SPP will cap the amount off-line Supplemental Reserve available to be cleared on that Resource to the Resource response observed in the test until such time that the Resource requests and passes a retest.

(iii) The Asset Owner of the Resource must obtain SPP approval regarding the timing of the retest.

(iv) The Out-Of-Merit-Energy instruction will be released.


2.10.1 Spin Qualified Resources

There are no specific testing requirements for a Resource to become a Spin Qualified

Resource. A Market Participant will self-certify that its Resource is capable of deploying

Spinning Reserve or on-line Supplemental Reserve during the registration process. In such case,

that Resource will become a Spin Qualified Resource. The Transmission Provider may perform,

at its discretion, Contingency Reserve deployment tests, as described in the Market Protocols, in

order to verify that any cleared Spinning Reserve or on-line Supplemental Reserve is capable of

being deployed.

If the Resource deploys less than seventy-five percent (75%) of the MW deployment

instruction, the Resource has failed the test and the Resource will not be eligible for

compensation for out-of-merit Energy (“OOME”) and the maximum online Contingency

Reserve available for sale in the Integrated Marketplace shall be limited to the actual MW

deployed during the test. Such restriction shall continue to apply until the Resource passes a

retest. The Market Participant representing the Resource must obtain Transmission Provider


Deleted: I

Deleted: multiply the Resource’s submitted Maximum Off-Line Response Limit by the Resource response percentage

Deleted: Such Contingency Reserve deployment tests may also test deployment of Spinning Reserve or on-line Supplemental Reserve resulting from a Reserve Sharing Event.


approval regarding the timing of a retest and the Resource will not be eligible for compensation

for OOME as a result of the retest.

2.10.2 Supplemental Qualified Resources

There are no specific testing requirements for an off-line Resource to become a

Supplemental Qualified Resource. A Market Participant will self-certify that its off-line

Resource is capable of deploying Supplemental Reserve during the registration process. In such

case, that Resource will become a Supplemental Qualified Resource. The Transmission Provider

may perform, at its discretion, Contingency Reserve deployment tests, as described in the Market

Protocols, in order to verify that any cleared Supplemental Reserve is capable of being deployed.

If the Resource deploys less than seventy-five percent (75%) of the MW deployment

instruction, the Resource has failed the test and the Resource will not be eligible for Reliability

Unit Commitment (“RUC”) make whole payment compensation and the maximum off-line

Supplemental Reserve available for sale in the Integrated Marketplace shall be limited to the

actual MW deployed during the test. Such restriction shall continue to apply until the Resource

passes a retest. The Market Participant representing the Resource must obtain Transmission

Provider approval regarding the timing of a retest and the Resource will not be eligible for RUC

make whole payment compensation as a result of the retest.

6.3.2 Contingency Reserve Deployment [Protocols Section 4.4.3.2]

Contingency Reserve procured in the RTBM will be deployed through a Contingency

Reserve Deployment Instruction following a Reserve Sharing Event in accordance with the

following rules:

(1) Contingency Reserve is deployed on Resources with cleared Contingency Reserve and

Export Interchange Transactions providing Supplemental Reserve in the Dispatch

Interval immediately following system events;

(2) Spinning Reserve and on-line Supplemental Reserve is deployed ahead of off-line

Supplemental Reserve;

(3) If the amount of Spinning Reserve and on-line Supplemental Reserve cleared is greater

than or equal to the Contingency Reserve amount required in response to a contingency,

no off-line Supplemental Reserve is deployed;

Deleted: Such Contingency Reserve deployment tests may also test deployment of off-line Supplemental Reserve resulting from a Reserve Sharing Event


(4) Spinning Reserve and on-line Supplemental Reserve is deployed in proportion to the

amount of Spinning Reserve and on-line Supplemental Reserve cleared on each

Resource, adjusted as needed to ensure deliverability; and

(5) Supplemental Reserve from off-line Quick-Start Resources is deployed on Resources in

merit order of Start-Up Offer, No-Load Offer, Energy Offer Curves and Minimum Run

Time, adjusted as needed to ensure deliverability. For the purposes of deploying

Supplemental Reserve supplied from Export Interchange Transactions, the merit order

cost will be equal to zero (0).

(6) If a Resource fails all four of the tests described under Section 6.4.3 and the smallest Shortfall Quantity is greater than 25% of the Contingency Reserve Deployment Instruction, the amount of Contingency Reserve available to be cleared on that Resource will be reduced based on the current Contingency Reserve Ramp Rate, for online deployment, or Maximum Quick-Start Response Limit for offline deployments, for the remainder of the Operating Day.


N/A

Deleted: to the Deployment Instruction minus the smallest positive Shortfall Quantity by that percentage




Title Clarification to Excess Generation Emergency Logic


Provide explanation if Expedited and/or Urgent Action is selected: This MPRR is Tariff impacting and needs to be expedited to meet filing deadlines.


Approve Reject


Defer Refer




Section No.: 4.3.1.2, 4.3.2.2, 4.4.1.2 Title: DA Market Execution, Day-Ahead RUC Execution, Intra-Day RUC Execution Protocol Version: 8.0




This MPRR clarifies language describing the steps taken by SCUC to alleviate an Excess Generation condition. Under capacity shortage conditions, SCUC will rely on Emergency Maximum Limits and commit Reliability Resources on the most economic basis to relieve the shortage while simultaneously attempting to maintain the Regulation-Up Requirement. This same logic should also apply under Excess Generation conditions, where SCUC should make use of Emergency Minimum Limits to relieve the excess while simultaneously attempting to maintain the Regulation-Down Requirement.


Yes – Section No.: (Include a summary of impact and/or specific changes) 5.1.2 – Day-Ahead Market Execution, 5.2.2 – Day-Ahead RUC Execution, 6.1.2 – Intra-Day RUC Execution.

No



RTWG Review

ORWG Review

MOPC Recommendation

Board Review

EIS Market



Date 3/7/2012

SponsorName Carrie Simpson E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.1757



4.3.1.2 DA Market Execution

SPP clears the Day-Ahead Market for each hour of the upcoming Operating Day based on the inputs described above. A simultaneous co-optimization methodology, utilizing the SCUC and SCED algorithms is employed to simultaneously perform the following tasks:

(1) Commit offered Resources, Import Interchange Transaction Offers and Virtual Energy Offers using the SCUC algorithm to meet the Demand Bids, Virtual Energy Bids, Export Interchange Transactions Bids and Operating Reserve requirements at least cost throughout the projected upcoming Operating Day while respecting Resource operating constraints and transmission constraints;

(a) The DA Market SCUC algorithm will initially consider commitment of Resources with a Commit Status of Market and Self, including Resources committed in the Multi-Day Reliability Assessment process, only including capacity up to the Resources’ Maximum Economic Capacity Operating Limit (or Maximum Regulation Capacity Operating Limit if selected for Regulation-Up) and down to the Resources Minimum Economic Capacity Operating Limit (or Minimum Regulation Capacity Operating Limit if selected for Regulation-Down).

(i) If this capacity is not sufficient to meet the fixed Demand Bids and fixed Export Interchange Transaction Bids plus Operating Reserve requirements on a system-wide basis, the DA Market SCUC algorithm will, in priority order: (1) curtail non-firm fixed Export Interchange Transaction Bids until the capacity shortage is eliminated; (2) incorporate capacity up to Resources’ Maximum Emergency Capacity Operating Limit and/or commit Resources’ with a Commit Status of Reliability on an economic basis until the capacity shortage is eliminated while attempting to maintain the Regulation-Up requirement to the extent possible.


(ii) If there is a capacity surplus on a system-wide basis calculated as the sum of Self-Committed capacity at minimum output, fixed Import Interchange Transaction Offers and the Regulation-Down requirement that is in excess of the sum of Fixed Demand Bids and fixed Export Interchange Transaction Bids, the DA Market SCUC algorithm will, in priority order (1) curtail non-firm fixed Import Interchange Transaction Offers until the capacity surplus is eliminated; (2) incorporate capacity down to Resources’ Minimum Emergency Capacity Operating Limit on an economic basis until the capacity surplus is eliminated while attempting to maintain the Regulation-Down requirement to the extent possible.

(b) To the extent that a particular reliability issue cannot be directly addressed within the DA Market SCUC algorithm as described under subsection (i) and (ii) above, SPP may manually commit Resources to alleviate such reliability issues. SPP will re-run the DA Market SCUC algorithm after such manual commitments, time permitting, and will notify the Market Participants that units were manually committed. The SCED algorithm will be run based on the manual commitment to produce a final market solution.

4.3.2.2 Day-Ahead RUC Execution

Using the inputs described above, SPP performs a capacity adequacy analysis for the upcoming Operating Day using the SCUC algorithm. The capacity adequacy analysis provides advisory information to the SPP Operators.


(2) Commitment costs are defined as Start-Up Offer, No-Load Offer and incremental cost to operate at minimum output as defined in the submitted Energy Offer Curve. Incremental Energy costs above minimum output and Operating Reserve Offers are not considered by the RUC SCUC in making commitment decisions;


(a) If this capacity is not sufficient to meet the system-wide SPP Mid-Term Load Forecast plus Operating Reserve requirements, the SCUC algorithm study will, in priority order: (1) curtail non-firm Export Interchange Transactions until the capacity shortage is

Deleted: (2) incorporate capacity down to the Resources’ Minimum Emergency Capacity Operating Limit for Resources not selected for Regulation-Down until the capacity surplus is eliminated and (3) incorporate capacity down to the Resources’ Minimum Emergency Capacity Operating Limit for Resources selected for Regulation-Down Down.


eliminated; (2) incorporate capacity up to Resources’ Maximum Emergency Capacity Operating Limit and/or commit Resources’ with a Commit Status of Reliability on an economic basis until the capacity shortage is eliminated while attempting to maintain the Regulation-Up requirement to the extent possible.

(b) If the sum of Self-Committed capacity at minimum output, fixed Import Interchange Transaction Offers and the system-wide Regulation-Down requirement is in excess of the sum of the SPP system-wide Mid-Term Load Forecast and fixed Export Interchange Transactions, the RUC SCUC algorithm study will, in priority order: (1) curtail non-firm fixed Import Interchange Transactions until the capacity surplus is eliminated; (2) incorporate capacity down to Resources’ Minimum Emergency Capacity Operating Limit on an economic basis until the capacity surplus is eliminated while attempting to maintain the Regulation-Down requirement to the extent possible;; (3) de-commit Resources that were committed in the DA Market with a Commit Status of Market until the capacity surplus in eliminated; and (4) de-commit Self-Committed Resources until the capacity surplus in eliminated.

(i) If there is a transmission constraint within a Reserve Zone occurring simultaneously with a Reserve Zone excess capacity event, SCUC may commit additional Resources and/or de-commit Resources to relieve the constraints provided that any commitment changes do not aggravate the excess capacity situation.

(c) To the extent that a particular reliability issue cannot be directly addressed within the SCUC algorithm as described under subsection (a) and (b) above, SPP may manually commit Resources with a Commit Status of Reliability and de-commit Resources with a Commit Status of Self to alleviate such reliability issues in accordance with its authority as Reliability Coordinator.

Any curtailment of schedules, use of Reliability Status Resources or use of Emergency operating limits by the RUC algorithms will only be advisory information to the SPP RUC Operators. Day-Ahead RUC and Intra-Day RUC Operators will determine which of these options should be acted on and when as described in the Day-Ahead and Intra-Day RUC Results sections.

4.4.1.2 Intra-Day RUC Execution

Using the inputs described above, SPP performs a capacity adequacy analysis for the upcoming Operating Day and throughout the Operating Day using a SCUC algorithm. The capacity adequacy analysis provides advisory information to the SPP Operators.

(1) The objective of the SCUC is to commit Resources to meet the SPP Mid-Term Load Forecast and Operating Reserve requirements over the Operating Day such that commitment costs are

Deleted: (2) reduce Resource capacity down to the Resources’ Minimum Emergency Capacity Operating Limit for Resources not selected for Regulation-Down until the capacity surplus is eliminated


minimized while adhering to transmission system security constraints and the resource operating parameter constraints submitted as part of the RTBM Offers;

(2) Commitment costs are defined as Start-Up Offer, No-Load Offer and incremental cost to operate at minimum output as defined on the submitted Energy Offer Curve. Incremental Energy costs above minimum output and Operating Reserve Offers are not considered by the RUC SCUC in making commitment decisions;



(b) If the sum of Self-Committed capacity at minimum output, fixed Import Interchange Transaction Offers and the system-wide Regulation-Down requirement is in excess of the sum of the SPP system-wide Mid-Term Load Forecast and fixed Export Interchange Transactions, the SCUC algorithm study will, in priority order: (1) curtail non-firm fixed Import Interchange Transactions until the capacity surplus is eliminated; (2) incorporate capacity down to Resources’ Minimum Emergency Capacity Operating Limit on an economic basis until the capacity surplus is eliminated while attempting to maintain the Regulation-Down requirement to the extent possible; (3) de-commit Resources that were committed in the DA Market with a Commit Status of Market until the capacity surplus is eliminated; and (4) de-commit Self-Committed Resources that were committed following the Day-Ahead RUC process until the capacity surplus is eliminated.

(i) If there is a transmission constraint within a Reserve Zone occurring simultaneously with a Reserve Zone excess capacity event, RUC may commit additional Resources to relieve the constraints provided that the additional commitment does not aggravate the excess capacity situation.

(c) To the extent that a particular reliability issue cannot be directly addressed within the SCUC algorithm as described under subsection (a) and (b) above, SPP may manually commit Resources with a Commit Status of Reliability and de-commit Resources with a

Deleted: t

Deleted: (2) reduce capacity down to the Resources’ Minimum Emergency Capacity Operating Limit for Resources not selected for Regulation-Down until the capacity surplus is eliminated;


Commit Status of Self to alleviate such reliability issues in accordance with its authority as Reliability Coordinator.


5.1.2 Day-Ahead Market Execution

The Transmission Provider will employ a simultaneous co-optimization methodology to

perform the following tasks in order to clear the Day-Ahead Market for each hour of the

upcoming Operating Day:

(1) Commit Offered Resources, Import Interchange Transaction Offers and Virtual Energy

Offers using the SCUC algorithm to meet the Demand Bids, Virtual Energy Bids, Export

Interchange Transactions Bids and Operating Reserve requirements on a least cost basis

for each hour of the upcoming Operating Day.

(a) The Day-Ahead Market SCUC algorithm will initially consider commitment of

Resources not specified for reliability only use as described in Section 4.1(10)(c)

of this Attachment AE, including Resources committed in the Multi-Day

Reliability Assessment, up to the Resources’ Maximum Economic Capacity

Operating Limit or Maximum Regulation Capacity Operating Limit if selected for

Regulation-Up, and down to the Resources’ Minimum Economic Capacity

Operating Limit or Minimum Regulation Capacity Operating Limit if selected for

Regulation-Down.

(i) If this capacity is not sufficient to meet the fixed Demand Bids and fixed

Export Interchange Transaction Bids plus Operating Reserve requirements

on a system-wide basis, the Day-Ahead Market SCUC algorithm will, in

priority order: (1) curtail non-firm fixed Export Interchange Transaction

Bids until the capacity shortage is eliminated; and (2) incorporate capacity

up to Resources’ Maximum Emergency Capacity Operating Limits and/or

commit Resources designated as reliability only use, as described in

Section 4.1(10)(c) of this Attachment AE, on an economic basis until the

capacity shortage is eliminated while attempting to maintain the

Regulation-Up requirement. Deleted: to the extent possible


(ii) If there is a capacity surplus on a system-wide basis calculated as the sum

of self-committed capacity at minimum output, fixed Import Interchange

Transaction Offers and the Regulation-Down requirement that is in excess

of the sum of fixed Demand Bids and fixed Export Interchange

Transaction Bids, the Day-Ahead Market SCUC algorithm will, in priority

order: (1) curtail non-firm fixed Import Interchange Transaction Offers

until the capacity surplus is eliminated; and (2) incorporate capacity down

to Resources’ Minimum Emergency Capacity Operating Limits until the

capacity surplus is eliminated while attempting to maintain the

Regulation-Down requirement.

(b) To the extent that a particular reliability issue cannot be directly addressed within

the Day-Ahead Market SCUC algorithm as described under Subsections (i) and

(ii) above, the Transmission Provider may manually commit Resources to

alleviate such reliability issues. The Transmission Provider will re-run the Day-

Ahead SCUC algorithm after such manual commitments, time permitting, and

will notify the Market Participants that units were manually committed.

5.2.2 Day-Ahead Reliability Unit Commitment Execution

The Transmission Provider will perform a capacity adequacy analysis for the upcoming

Operating Day using the SCUC algorithm with the objective of committing Resources to meet

the Transmission Provider load forecast and Operating Reserve requirements over the Operating

Day such that commitment costs are minimized while adhering to Transmission System security

constraints and the Resource operating parameter constraints submitted as part of the RTBM

Offers.


incremental cost to operate at minimum output as defined in the submitted Energy Offer

Curve.


reliability only use as described in Section 4.1(10)(c) of this Attachment AE, up to the

Resources’ Maximum Economic Capacity Operating Limit or Maximum Regulation

Capacity Operating Limit if selected for Regulation-Up, and down to the Resources’

Deleted: for Resources not selected for Regulation-Down

Deleted: to the extent possible.


Minimum Economic Capacity Operating Limit or Minimum Regulation Capacity

Operating Limit if selected for Regulation-Down.


Provider load forecast plus Operating Reserve requirements, the SCUC algorithm

will, in priority order: (1) Curtail non-firm fixed Export Interchange Transaction

Bids until the capacity shortage is eliminated; and (2) Incorporate capacity up to

Resources’ Maximum Emergency Capacity Operating Limits and/or commit

Resources designated as reliability only use, as described in Section 4.1(10)(c) of

this Attachment AE, on an economic basis until the capacity shortage is

eliminated while attempting to maintain the Regulation-Up requirement.

(b) If there is a capacity surplus on a system-wide basis calculated as the sum of self-

committed capacity at minimum output, fixed Import Interchange Transaction

Offers and the Regulation-Down requirement that is in excess of the sum of the

Transmission Provider load forecast and fixed Export Interchange Transaction

Bids, the SCUC algorithm will, in priority order: (1) curtail non-firm fixed Import

Interchange Transaction Offers until the capacity surplus is eliminated; (2)

incorporate capacity down to Resources’ Minimum Emergency Capacity

Operating Limits until the capacity surplus is eliminated while attempting to

maintain the Regulation-Down requirement; (3) de-commit Resources that were

committed by the Transmission Provider in the Day-Ahead Market that were not

self-committed until the capacity surplus is eliminated; and (4) de-commit self-

committed Resources until the capacity surplus is eliminated.

(3) To the extent that a particular Transmission System security constraint cannot be directly

addressed within the SCUC algorithm, the Transmission Provider may manually commit

Resources and/or decommit self-committed Resources to alleviate such a Transmission

System security constraint in accordance with its authority as Reliability Coordinator.

6.1.2 Intra-Day Reliability Unit Commitment Execution

Using the inputs described in Section 6.1.1, the Transmission Provider will perform a

capacity adequacy analysis using the SCUC algorithm with the objective of committing

Resources to meet the Transmission Provider’s load forecast and Operating Reserve

requirements over the Operating Day such that commitment costs are minimized while adhering

Deleted: , to the extent possible


Deleted: to the extent possible


to Transmission System security constraints and the resource operating parameter constraints

submitted as part of the RTBM Offers.


incremental cost to operate at minimum output as defined on the submitted Energy Offer

Curve. Incremental Energy costs above minimum output and Operating Reserve Offers

are not considered by the SCUC in making commitment decisions.


reliability only use as described in Section 4.1(10)(c) of this Attachment AE, only

including capacity up to the Resources’ Maximum Economic Capacity Operating Limits

(or Maximum Regulation Capacity Operating Limits if selected for Regulation-Up) and

down to the Resources’ Minimum Economic Capacity Operating Limits (or Minimum

Regulation Capacity Operating Limits if selected for Regulation-Down).


Provider’s load forecast plus Operating Reserve requirements, the SCUC

algorithm will, in priority order: (1) Curtail non-firm fixed Export Interchange

Transaction Bids until the capacity shortage is eliminated; and (2) Incorporate

capacity up to Resources’ Maximum Emergency Capacity Operating Limits

and/or commit Resources designated as reliability only use, as described in

Section 4.1(10)(c) of this Attachment AE, on an economic basis until the capacity

shortage is eliminated while attempting to maintain the Regulation-Up

requirement.

(b) If there is a system-wide capacity surplus calculated as the sum of self-committed

capacity at minimum output, fixed Import Interchange Transaction Offers and the

Regulation-Down requirement that is in excess of the sum of the Transmission

Provider load forecast and fixed Export Interchange Transaction Bids, the Day-

Ahead Market SCUC algorithm will, in priority order: (1) Curtail non-firm fixed

Import Interchange Transaction Offers until the capacity surplus is eliminated; (2)

Incorporate capacity down to Resources’ Minimum Emergency Capacity

Operating Limits until the capacity surplus is eliminated while attempting to

maintain the Regulation-Down requirement; (3) De-commit Resources that were

committed by the Transmission Provider in the Day-Ahead Market that were not





self-committed until the capacity surplus is eliminated; and (4) De-commit self-

committed Resources until the capacity surplus is eliminated.

(3) To the extent that a particular reliability issue cannot be directly addressed within the

SCUC algorithm as described under subsections (a) and (b) above, the Transmission

Provider may manually commit Resources and/or decommit self-committed Resources to

alleviate such reliability issues in accordance with its authority as Reliability Coordinator.


N/A




Title Modification of Billing Determinant Anomalies

Timeline



Approve Reject


Defer Refer




Section No.: 4.5.17 Title: Billing Determinant Anomalies Protocol Version: 4.0



Revision Description Information in section 4.5.17 is based on EIS legacy system and needs to be corrected to better represent guidelines that will apply under Integrated Marketplace when it comes to when dealing with bill meter data issues such as data submitted in KW instead of MW or Submitting of negative values.



No


Date of Vote: 2/22/2012—Unanimously approved with modifications All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A

RTWG Review

ORWG Review

MOPC Recommendation

Board Review

EIS Market



Date 2/9/2012

SponsorName Tony Alexander E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3303

Comments ReceivedComment Author SPP Date 2/21/2012 Comment Description Clarification based upon MWG feedback at the February 14-15, 2012 meeting.


Comments Received

Comment Author MWG Date 2/22/2012 Comment Description Clarification



4.5.17 Billing Determinant Anomalies

Circumstances may occur where billing determinants received from system interfaces contain erroneous data anomalies that would have significant adverse financial impacts on Market Participants if these determinants were used to produce Settlement Statements. In these situations when certain billing determinants deviate beyond prescribed tolerance levels, SPP will work internally and with Meter Agents(s) to resolve the discrepancy and may modify data using actions including, but not limited to those in the following guideline to substitute data when the original data is deemed to be erroneous.

(1) Bad State Estimator (For resources dispatched in RTBM interval ) – 5-minute interval value based on:

(a) If High Tolerance Band - Greater than 120% of the RTBM Resource Maximum Emergency Capacity Operating Limit;

i. Then substitution value – Energy Dispatch Instructions;

(b) If Low Tolerance Band – Less than RTBM Resource Minimum Economic Capacity Operating Limit;

i. Then substitution value – Energy Dispatch Instructions.

(2) Bad State Estimator (For resources not dispatched in RTBM interval) – 5-minute interval value based on:

(a) If High Tolerance Band – Greater than 120% of the historic high value;

i. Then substitution value – Zero or last known valid value;

Deleted: substitute the following acceptable values.

Deleted: on dispatch

Deleted: SCADA

Deleted: S

Deleted: (results in zero URD)

Deleted: S

Deleted: (results in zero URD)

Deleted:

Deleted: not on dispatch


(b) If Low Tolerance Band – Less than historic low value;

i. Then substitution value – Zero or last known valid value.

(3) Bad Average Set Point Instruction – 5-minute interval value based on:

(a) If High Tolerance Band - Greater than 120% of the RTBM Resource Maximum Emergency Capacity Operating Limit;

i. Then substitution value – State Estimator;

(b) If Low Tolerance Band – Less than Zero;

i. Then substitution value – State Estimator.

(4) Bad Resource Meter Data Submittal – Based on: (a) If High Tolerance Band - Derived from historic high value;


(b) If Low Tolerance Band – Derived from historic low value;

i. Then substitution value –State Estimator.

(5) Bad Load Meter Data Submittal – Based on: (a) If High Tolerance Band - Derived from historic high value;




(6) Bad Settlement Area Inter-Tie Meter Data Submittal – Based on: (a) If High Tolerance Band - Derived from historic high value;





N/A


N/A

Deleted: Dispatch Instruction

Deleted: S

Deleted: Use SCADA value (results in zero URD)

Deleted: S

Deleted: Use SCADA value (results in zero URD)

Deleted: Trigger value supplied by meter agent/Market Participant

Deleted: S

Deleted: SCADA

Deleted: Auxiliary negative value supplied by meter agent/Market Participant

Deleted: S

Deleted:

Deleted: SCADA

Deleted: 150% of previous year annual peak

Deleted: S

Deleted: SCADA

Deleted: Zero value

Deleted: S

Deleted: SCADA


Deleted: S

Deleted: SCADA


Deleted: S

Deleted: SCADA




Title Clarification and Enhancement to Ramp Rate Logic

Timeline



Approve Reject


Defer Refer




Section No.: 1.0, 4.2.2.1, 4.2.2.1.1 Title: Glossary, Resource Offer Parameters, Ramp Rate Interaction – Energy and Operating Reserve Protocol Version: 8.0



Revision Description Added details regarding interaction between Energy ramp rates and Operating Reserve ramp rates and enhanced MP ability to submit Regulation Ramp Rate and Contingency Reserve Ramp Rate in the form of a 10 point curve.



No



RTWG Review

ORWG Review

MOPC Recommendation

Board Review

EIS Market



Date 2/21/2012

SponsorName Gerardo Ugalde E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3212



1.0 Glossary

Contingency Reserve Ramp Rate

A curve specifying MW/minute ramp rates that are used to determine a Resource’s maximum Spinning Reserve quantities or on-line Supplemental Reserve quantities.

Regulation Ramp Rate

A curve specifying MW/minute ramp rates that are used to determine a Resource’s maximum Regulation-Up and/or Regulation-Down quantities.

4.2.2.1 Resource Offer Parameters

The following Resource Offer parameters must be submitted to constitute a valid offer for use in either the DA Market or RTBM:

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

(2) Resource Type (as specified during Market Registration and cannot be changed as part of Resource Offer submittal). See Section 4.2.2.5 for specific modeling rules for certain Resource Types;

(3) Start-Up Offer ($/Start, Hot, Intermediate and Cold – Unit Commitment)1;

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

(5) Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, slope or block option, monotonically non-decreasing, block and slope pairs may not coexist – the Resource Offer in

1 For Asset Owners that have registered a JOU under the Combined Resource Option (see Section 6.1.7.2), , this value must be submitted by the specified Asset Owner and represents the value for the entire Physical JOU Resource)

Deleted: single

Deleted: value

Deleted: is

Deleted: Maximum Regulation Capability¶A Resource’s Maximum Regulation Capability is equal to that Resource’s Regulation Ramp Rate multiplied by the Regulation Response Time.¶

Deleted: single

Deleted: value

Deleted: is


effect for any given period of time must be comprised of all block or all slope price/quantity pairs);

(a) The price of all MWhs below the first pricing point MWh is equal to the first pricing point price. The price of all MWhs above the last pricing point MWh is equal to the last pricing point price.

(b) Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-4 illustrates Energy Offer Curves developed from submitted price/MWh pairs for both the slope and block options.

Exhibit 4-1: Energy Offer Curve Development

(6) Regulation-Up Offer ($/MW); (7) Regulation-Down Offer ($/MW); (8) Spinning Reserve Offer ($/MW); (9) Supplemental Reserve Offer ($/MW); (10) Sync-To-Min Time (hours:minutes); (11) Min-To-Off Time (hours:minutes); (12) Start-Up Time (hours:minutes, Hot, Intermediate, Cold – Unit Commitment)1; (13) Hot to Intermediate Time (hours:minutes– Unit Commitment)1; (14) Hot to Cold Time (hours:minutes– Unit Commitment)1; (15) Maximum Daily Starts (Unit Commitment)1; (16) Maximum Weekly Starts – rolling 7-day (Unit Commitment1; (17) Maximum Daily Energy (MWh – Unit Commitment)1; (18) Minimum Run Time (hours:minutes– Unit Commitment)1;

MW $/MW100 20.00200 40.00400 60.00500 80.00

Submitted DataEnergy Offer Curve

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

0 100 200 300 400 500 600

MW

$/M

Wh

Slope Option

Block Option


(19) Maximum Run Time (hours:minutes– Unit Commitment)1; (20) Minimum Down Time (hours:minutes– Unit Commitment)1; (21) Minimum Emergency Capacity Operating Limit (MW); (22) Minimum Emergency Capacity Run Time (hours:minutes – Operations Information); (23) Minimum Normal Capacity Operating Limit (MW); (24) Minimum Economic Capacity Operating Limit (MW); (25) Minimum Regulation Capacity Operating Limit (MW); (26) Maximum Regulation Capacity Operating Limit (MW); (27) Maximum Economic Capacity Operating Limit (MW); (28) Maximum Normal Capacity Operating Limit (MW); (29) Maximum Emergency Capacity Operating Limit (MW); (30) Maximum Emergency Capacity Run Time (hours:minutes – Operations Information); (31) Maximum Quick-Start Response Limit (MW, this represents the maximum amount of

Supplemental Reserve that may be supplied by an off-line Quick-Start Resource)1; (32) Ramp-Rate-Up (curve, MW/Minute - for use when the Resource is not selected for Regulation-

Up and/or Regulation-Down clearing and dispatched in the up direction). Ramp-Rate-Up submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);

(a) Breakpoint Limit 1– Resource MW output at which segment 1 Ramp-Rate-Up will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Ramp-Rate-Up in Block 1 will apply back to the actual measured MW.

(b) Block 1 Ramp Rate Up – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to Breakpoint Limit 1.

(c) Block 1 Ramp Rate Emergency – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to Breakpoint Limit 1 during an Emergency.

(d) Breakpoint Limit n– Resource MW output at which Ramp-Rate-Up changes from previous segment values to segment n values.

(e) Block n Ramp-Rate-Up - Rate at which Resource can change output upward in MW/min at output levels greater than or equal to the Breakpoint Limit n

(f) Block n Ramp-Rate-Up Emergency – Rate at which Resource can change output upward in MW/min at output levels greater than the Breakpoint Limit n and less than Breakpoint Limit n+1 during an Emergency.

(33) Ramp-Rate-Down (curve, MW/Minute - for use when the Resource is not selected for Regulation-Up and/or Regulation-Down clearing and dispatched in the Down direction). Ramp-Rate-Down submittal is through a segmented profile as follows. Each profile will

Deleted: I

Deleted: 1

Deleted: 2


require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);

(a) Breakpoint Limit 1– Resource MW output at which segment 1 Ramp-Rate-Down will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Ramp-Rate-Down in Block 1 will apply back to the actual measured MW.

(b) Block 1 Ramp Rate Down – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to Breakpoint Limit 1.

(c) Block 1 Ramp-Rate-Down Emergency – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to Breakpoint Limit 1 during an Emergency.

(d) Breakpoint Limit n– Resource MW output at which Ramp-Rate-Down changes from previous segment values to segment n values.

(e) Block n Ramp-Rate-Down - Rate at which Resource can change output downward in MW/min at output levels greater than or equal to the Breakpoint Limit n.

(f) Block n Ramp-Rate-Down Emergency – Rate at which Resource can change output downward in MW/min at output levels greater than the Breakpoint Limit n and less than Breakpoint Limit n+1 during an Emergency.

(34) Turn-Around Ramp Rate Factor (a percentage between 0% and 100%). This factor is used to adjust a Resource’s Ramp-Rate-Up or Ramp-Rate-Down in a Dispatch Interval for which a Resource’s Energy Dispatch Instruction has changed direction from the previous Dispatch Interval and is only used in the RTBM. For example, if in the last Dispatch Interval the Resource’s Dispatch Instruction was in the up direction and in the current Dispatch Interval its Dispatch Instruction is in the down direction, this factor is applied to the Resource’s Ramp-Rate-Down prior to the calculation of the actual Dispatch Instruction in that Dispatch Interval. A submittal of 0% creates a Ramp-Rate-Up or Ramp-Rate-Down of 0 MW/Min and a submittal of 100% indicates no change to the Resource’s Ramp-Rate-Up or Ramp-Rate-Down. Additionally, the Turn-Around Ramp Rate Factor is applied to limit on-line Contingency Reserve clearing when a Resource’s Energy Dispatch Instruction in the previous Dispatch Interval was in the down direction. The Turn Around Ramp Rate Factor does not apply to a Resource that is selected as available to be cleared for Regulation-Up and/or Regulation Down;

(35) Regulation Ramp Rate (curve, MW/Minute - for use when the Resource is selected for Regulation-Up and/or Regulation Down clearing). Regulation Ramp Rate submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);

(a) Breakpoint Limit 1– Resource MW output at which segment 1 Regulation Ramp Rate will apply. In the RTBM, if the actual measured MW during deployment is less than the

Deleted: I

Deleted: 1

Deleted: 2

Deleted: the

Deleted:

Deleted: single value, MW/Minute


Breakpoint Limit 1, the Regulation Ramp Rate in Block 1 will apply back to the actual measured MW.

(b) Block 1 Regulation Ramp Rate – Rate at which a Resource on Automatic Generation Control can change output in the up and down direction in MW/min at output levels greater than or equal to Breakpoint Limit 1.

(c) Breakpoint Limit n– Resource MW output at which Regulation Ramp Rate changes from previous segment values to segment n values.

(d) Block n Regulation Ramp Rate - Rate at which Resource on Automatic Generation Control can change output in the up and down direction in MW/min at output levels greater than or equal to the Breakpoint Limit n.

(36) Contingency Reserve Ramp Rate (curve, MW/Minute). Contingency Reserve Ramp Rate submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10) (a) Breakpoint Limit 1– Resource MW output at which segment 1 Contingency Reserve

Ramp Rate will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Regulation Ramp Rate in Block 1 will apply back to the actual measured MW.

(b) Block 1 Contingency Reserve Ramp Rate – Rate at which a Resource not on Automatic Generation Control can change output in the up direction in MW/min when deploying Contingency Reserve at output levels greater than or equal to Breakpoint Limit 1.

(c) Breakpoint Limit n– Resource MW output at which Regulation Ramp Rate changes from previous segment values to segment n values.

(d) Block n Contingency Reserve Ramp Rate - Rate at which Resource not on Automatic Generation Control can change output in the up direction in MW/min when deploying Contingency Reserve at output levels greater than or equal to the Breakpoint Limit n.);

(37) Resource Status (see Section 4.2.2.2); and (38) JOU Ownership Share (See Section 4.2.2.5.4).

4.2.2.1.1 Ramp Rate Interaction – Energy and Operating Reserve

The following ramp rate use assumptions apply to the clearing of Energy and Operating Reserve in the Day-Ahead Market and to the dispatch of Energy and clearing of Operating Reserve in the RTBM. The examples provided below assume that there is no ramp sharing between Energy and Operating Reserve products (see Section 4.1.6 for ramp sharing description).

(1) If a Resource has not been selected as clearable for either Regulation-Up and/or Regulation-Down, the Resource’s Ramp-Rate-Up is used to clear Energy in the up direction in the Day-Ahead Market and dispatch Energy in the up direction in the RTBM. The combination of that

Deleted: ;

Deleted: single value, MW/Minute


Resource’s Ramp-Rate-Up and Contingency Reserve Ramp Rate is used to clear Contingency Reserve in the Day-Ahead Market and RTBM. In the RTBM, if that Resource’s previous RTBM Energy dispatch target ramps the Resource in the downward direction, that Resource’s Ramp-Rate-Up and the Contingency Reserve Ramp Rate are multiplied by the Turn-Around Ramp Rate Factor.

(a) For example, assuming in the RTBM that Resource A has a single Ramp-Rate-Up value that is equal to 5 MW/Min, a single Contingency Reserve Ramp Rate value of 8 MW/Min, and the previous RTBM Energy dispatch target was upward, the maximum amount of positive change in Energy clearing/dispatch is 25 MW (5 MW/Min times 5 minutes) and the maximum amount of Contingency Reserve that can clear on that Resource is 80 MW (8 MW/Min times 10 minutes). If we assume that the change in Energy clearing/dispatch on that Resource is 25 MW, then a maximum of 30 MWs of Contingency Reserve could be cleared on that Resource. Alternatively, if we assume that the change in Energy clearing/dispatch on that Resource is 0 MW, then a maximum of 80 MW of Contingency Reserve could be cleared on that Resource.

(2) If a Resource has not been selected as clearable for either Regulation-Up and/or Regulation-Down, the Resource’s Ramp-Rate-Down is used to clear Energy in the down direction in the Day-Ahead Market and dispatch Energy in the down direction in the RTBM. In the RTBM, if that Resource’s previous RTBM Energy dispatch target ramps the Resource in the upward direction, that Resource’s Ramp-Rate-Down is multiplied by the Turn-Around Ramp Rate Factor. For the Day-Ahead Market, the Resource’s Turn-Around Ramp Rate Factor does not apply (Contingency Reserve Ramp Rate is used). Referring to the example above, any dispatch of Energy in the down direction would allow up to 80 MWs of Contingency Reserve to be cleared on the Resource.

(3) If a Resource has been selected as clearable for Regulation-Up and/or Regulation-Down, that Resource’s Regulation Ramp Rate is used in both the up and down direction to clear Energy, Regulation-Up and/or Regulation-Down in the Day-Ahead Market and to dispatch Energy and to clear Regulation-Up and/or Regulation-Down in the RTBM. That Resource’s Regulation Ramp Rate is used in combination with that Resource’s Contingency Reserve Ramp Rate to clear Contingency Reserve in the Day-Ahead Market and RTBM.

(a) For example, assuming in the RTBM that Resource A has a single Regulation Ramp Rate value that is equal to 4 MW/Min and a Contingency Reserve Ramp Rate of 8 MW/Min, the maximum amount of Regulation-Up plus the change in Energy clearing/dispatch is 20 MW (4 MW/Min times 5 minutes) and the maximum amount of Contingency Reserve that can clear on that Resource is 80 MW (8 MW/Min times 10 minutes). If we assume that Regulation-Up cleared at 10 MW and the change in Energy clearing/dispatch on that Resource is 10 MW, then a maximum of 40 MWs of Contingency Reserve could be cleared on that Resource. Alternatively, if we assume that the Regulation-Up clearing


and the change in Energy clearing/dispatch on that Resource is 0 MW, then a maximum of 80 MW of Contingency Reserve could be cleared on that Resource.

(4) In addition to the Energy clearing/dispatch limits and Operating Reserve clearing limits calculated using applicable ramp rates as described above, Energy clearing/dispatch and Operating Reserve clearing on a Resource is also subject to limitation based upon that Resource’s operational capacity limits.


N/A


N/A




Title Provision of Wind Forecasts


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


Approve Reject


Defer Refer




Section No.: 4.1.2.2 Title: Wind-Power Generation Resource Output Forecasts Protocol Version: 8.0



Revision Description This MPRR requires SPP to provide wind forecasts to Market Participants with registered Wind-powered Generation Resources (WGRs). It also requires SPP to provide the total footprint wind forecast to all Market Participants.



No



RTWG Review

ORWG Review

MOPC Recommendation

Board Review N/A

EIS Market



Date 2/22/2012

SponsorName Jessica Collins E-mail Address [email protected] Company Xcel Energy/SPS Phone Number 303.571.7740

Comments ReceivedComment Author MWG Date 3/13/2012 Comment Description Clarification



4.1.2.2 Wind‐Power Generation Resource Output Forecasts

SPP produces and updates an hourly Mid-Term Wind Forecast (MTWF) that provides a rolling 48-hour hourly forecast of wind production potential from each Wind-powered Generation Resource (WGR). This process uses a combination of physical and statistical models. SPP will produce an hourly Expected Wind Output Forecast (EWOF) for each WGR using a physical modeling technique that incorporates the relationships of the WGRs to wind speed, topography, atmospheric conditions, actual WGR output, and other variables that influence WGR production. SPP also produces and updates an hourly SPP Total Wind Power Forecast (TWPF) providing a probability distribution of the hourly production potential from all wind-power in SPP for each of the next 48 hours.

The WGR Production Potential (WGRPP) is an hourly probability of exceedance forecast of energy production for each WGR. SPP shall use the probabilistic TWPF and select the forecast that the actual total SPP WGR production is expected to exceed 50% of the time (50% probability of exceedance forecast). To produce the WGRPP, SPP will allocate the TWPF 50% probability of exceedance forecast to each WGR based on the EWOF of each WGR. The updated WGRPP forecasts for each hour for each WGR are used as input into each RUC process.

SPP produces the WGRPP forecasts using the information provided by WGR owners including WGR availability, meteorological information, and Supervisory Control and Data Acquisition (SCADA) as described in the SPP Criteria. In addition to the Availability and Actual Output data required of all generation Resources, each Market Participant that owns a WGR shall install and telemeter to SPP the site-specific meteorological information that SPP determines is necessary to produce the MTWF and TWPF. SPP shall establish procedures specifying the accuracy requirements of WGR meteorological information telemetry.


SPP shall provide the MTWF and EWOF to Market Participants for their specific WGRs. In addition, SPP shall provide all Market Participants with the TWPF. Historical data shall be immediately available for seven (7) calendar days.


N/A


N/A

Deleted: The forecast will be per wind farm, with hourly updates and intraday and day ahead projections; with a prediction horizon of 0 to 48 hours.

Deleted:

Deleted: up to

Deleted:

TRR-58: Review of Issues Raised by RTWG

Presentation to RTWGMarch 22, 2012

Overview

• Intent of Changes:Provide Additional Flexibility Within Window for Request TimingMatch SPPs Modeling Process – 18 Month Window

• Addressed by two revisions to Att. P. Relatively minor modifications to file at FERC.

• Allows service requests to be made farther in advance, potentially matching better with timing of power purchasing opportunities or generation construction.

• SPP Staff has reviewed this proposal in detail and does not believe these changes will result in any conflicts with other processes or significant costs to implement.

Issues Raised by RTWG on 2/23/12

Overlap with / Impact on Long-term ServiceConsideration of Service Terms of Neighboring TOPs (Utilities and RTOs)DC TiesPro Forma Tariff LanguageDiscriminatory TreatmentIncreased Pre-Emption / Competition ReviewRequest “Cycling” and “Queue Clogging”

Results of Review

Terms and Form of ServiceReview of neighboring utilities’ and RTO’s service terms in comparison to SPP’sShort-term monthly firm terms and processes vary widely

SPP – 18 month online ATC study window; four month “request no earlier than” date (RNETD)AECI – 18 month window; 4 month RNETDCLECO – 13 month window; 12 month RNETDMISO – 36 month window; 17 month RNETDEntergy – 18 month window; No RNETD

Results of Review

Terms and Form of Service (cont’d)In neighbors’ business practices, not tariffsSummary / Conclusions:

Some neighbors (Entergy and CLECO) do not restrict short-term service request to window of online ATC calculations.All neighbors have longer RNETD for short-term monthly service than SPP, except AECI which is the same term.Variety of terms and inclusion in business practices indicate significant flexibility available for SPP.

Results of Review

Terms and Form of Service (cont’d)Other Conclusions:

In addition to simple comparison to neighboring utilities and RTOs, this review addresses several issues also raised – discriminatory treatment; pro forma tariff.Hard to conclude that proposed changes will create conflict with pro forma tariff. Hard to conclude that changing SPP’s short-term firm term and flexibility would result in discriminatory treatment.

Results of Review

Agg Study Issues RaisedRequest date window of overlapPotential for problems due to overlap

Long-term firm service terms and processes generally standard

SPP – Aggregate study process; four month “open season”; 6-10 month “request no later than” date (RNLTD); No RNETDAECI, MISO, Entergy, CLECO – 60 day RNLTD; No RNETD

Results of Review

Agg Study (cont’d)Long-term service in Agg Study can be requested to start no earlier than 6 months after the close of the open season.Short-term firm service is excluded from Agg Study models if requested on or after start of open season. With a four month open season, there is at least a 10-month window of no overlap.

Results of Review

Agg Study (cont’d)Therefore, if more than six months of short-term firm service is requested prior to the start of the open season today, there is a potential overlap with long-term requests under SPP’s current terms and processes.However, this is significantly less potential for overlap in SPP than for our neighbors with their 60 day RNLTD for long-term service.

SPP Service Request Windows

4 Months 12 Months

6 Months

Service Start Service StopRequest Period

CurrentShort-term

Long-term

Open SeasonEarliest Service Start

Maximum Potential Overlap

Proposed Service Request Changes in TRR-58: Flexibility and Term

120 Days ~12 Months

~14 Months

Service Start Service Stop

Service Stop

Request Period

Current Short-term

Proposed Short-term Request 2

Request

Request 1

As an example, instead of waiting until Feb 1, 2013 to request four months of service starting June 1, 2013, that service could be requested as early as April 1, 2012 under the proposed changes to Attachment P.

SPP Service Request Windows

4 Months 14 Months

6 Months


ProposedShort-term

Long-term

Open SeasonEarliest Service Start

Maximum Potential Overlap

Maximum potential overlap increases from six to eight months and potential for overlap may be higher as a result of added flexibility in requesting service.

Request 1 Request 2

Results of Review

Agg Study (cont’d)In the 2010 and 2011 Agg. Studies, approximately 20% of requests in initial round were for service starting between 6 months and one year after the close of the open season.None of these studies have been completed within 6 months.A one-year expectation for completion in future seems to be a reasonable goal, but has not been achieved recently.

Service Request Windows

4 Months 14 Months

12 Months


ProposedShort-term

Long-term

Open Season Maximum Potential Overlap

Request 1 Request 2

Results of Review

Agg Study (cont’d)Conclusion:

Actual overlap under today’s Aggregate Study processes is most likely a low probability / low impact event with proposed short-term service terms. Appears to be zero probability for current short-term service terms.

The actual length of time that it takes for today’s Aggregate Study to be completed and service granted is one of the primary reasons that this change is being proposed.

Results of Review

Increased Pre-Emption / Competition ReviewLonger-term service pre-empts shorter-term service from same POR / PODLarge majority of pre-emption / competition review in SPP today is for hourly service on DC tiesChanges in TRR-58 are not likely to make much differenceSPP plans to have an automated pre-emption/competition module in place to handle these issues by the end of the year.

Results of Review

Request “Cycling” and “Queue Clogging”Potential issue is cycling accepted requests without confirming them in order to hold ATC.Proposed changes in TRR-58 not likely to make this a bigger issue than it is now.TRR-58 changes may actually mitigate this issue since more flexibility is available to request service within the timing window at the times service is actually needed.Pre-confirmed requests can always pre-empt accepted requests not confirmed.

Results of Review

DC TiesRequest made to treat DC ties differently than the rest of SPP PORs/PODs for purposes of the changes proposed in TRR-58.Questions raised by this request:

Would treating DC ties differently be unduly discriminatory?Can reasons for treating DC ties differently be presented that FERC would accept?Would the proposed changes in TRR-58 really have any impact on service requests on the DC ties?

Results of Review

DC TiesSPP Staff believes that while pre-emption / competition between service requests on DC ties is significant in very short time frames (daily and hourly), it is not likely to be an issue in the longer monthly time frames addressed by TRR-58.The reason for this is that access to the DC ties is typically sold out on a long-term firm basis and only becomes available on a very short-term basis.

Conclusions

• The modifications proposed in TRR-58 are improvements to Attachment P that add needed flexibility without incurring any significant costs.

• While we’re wrestling with changes and improvements to the Aggregate Study Process, this change will hopefully provide some near-term relief for users to obtain firm service.

• Potential downsides, if any, are minimal, and can be mitigated or managed if necessary.

Request for Approval

Request that the RTWG approve this proposed Tariff change so it can be considered by the MOPC in April 2012 and implemented as soon as possible thereafter.


Page 1

TRR Number 58 TRR

Title Short Term Firm Monthly Service Timing Changes

Cross Reference # PRR BRR Other (Specify) _ _____________

Sponsor Name Rob Janssen E-mail Address [email protected] Company Dogwood Energy Phone Number 443-542-5125 Date January 24, 2012

Tariff Section(s) Requiring Revision

Section No. Attachment P Title Tariff Version (effective date)

Requested Resolution Normal Urgent (provided justification below for urgent

request)


This revision request includes two changes to the timing for short-term monthly firm service requests. The first is to extend the request window out by an additional two months from sixteen to eighteen months to match current SPP modeling processes. The second proposed modification is to change the timing of requests for multi-monthly firm service to key off the end or stop date rather than the start date for service in order to provide more flexibility to transmission customers in making requests for service. No other features of Attachment P or the rest of the OATT are changed by this revision request.

Reason for Revision To match existing SPP processes and provide additional flexibility for SPP transmission customers.

Stakeholder Approval Required (specify date and record outcome of vote; n/a for those stakeholders not required)

MWG (n/a) BPWG (n/a) TWG (n/a) ORWG (n/a) Other (specify) (n/a) RTWG MOPC Board of Directors


Page 2

Legal Review Completed

Yes (Include any comments resulting from the review)

No

Market Protocol Implications or Changes

Yes (Include a summary of impact and/or specific changes & PRR #)

No

Business Practice Implications or Changes

Yes (Include a summary of impact and/or specific changes & BPR #)

No

Criteria Implications or Changes


No Other Corporate Documents Implications (i.e., SPP By-Laws, Membership Agreement, etc.)

Yes (Include which corporate documents)

No

Credit Implications


No

Impact Analysis Required

Yes

No SPP Staff indicates that there is no impact to existing or anticipated future systems.


Page 3

Proposed Tariff Language Revision (Redlined)

ATTACHMENT P TRANSMISSION SERVICE TIMING REQUIREMENTS

Transmission Service Type

Term

Transmission Requests 2/ 10/ No No Later Earlier Than Than 8/

Transmission Provider

Response to Application

Aggregate Transmission

Service Study

Customer Response

1/

Energy Scheduling 2/ Changes No No Later Later Than Than

Long Term

Firm

1 Year or

More

In accordance with the open season specified in Section

II of Attachment Z1

At the close of the open season

specified in Section II of

Attachment Z1s

Aggregate Transmission Service Study performed

following close of open season as specified in Attachment Z1 in

accordance with schedule specified in Sections 19.4 or

32.4 as appropriate

In

accordance with the schedule

specified in Sections 19.4 or 32.4 as

appropriate

12:00 day

prior

20 mins prior

to hour


Term




Determine System Capacity Impact Available or Study

(From Date of Customer Commitment)

Customer Response

1/



Page 4


Term




Aggregate Transmission

Service Study

Customer Response

1/


Short-Term

Firm

More than 1 month

(monthly)

31 days

prior

546 days prior

to stop 10/

24 hrs

30 days

60 days

4 days

12:00 day

prior

20 mins prior

to hour

Short-Term

Firm

1 mo

(monthly)

8 days prior

90

days prior

24 hrs

30 days

60 days

4 days

12:00 day

prior

20 mins prior

to hour

Short-Term

Firm

More than 1 wk up to 1

month (weekly)

8 days prior

60

days prior

24 hrs

30 days

60 days

48 hrs

12:00 day

prior

20 mins prior

to hour

Deleted: 120 days¶prior


Term


Transmission

Provider Response to Application



Customer Response 1/


Short-Term

Firm

1 wk

(weekly)

2 days prior

30 days

prior

24 hrs

30 days

60 days

48 hrs

12:00 day

prior

20 mins prior

to hour

Short-Term Firm

More than 1 day up to

1 wk (daily)

2 days prior

14 days

prior

24 hrs

30 days

60 days

24 hrs

12:00 day

prior

20 mins prior

to hour

Short-Term

Firm

1 Day (daily)

10:00 day

prior

3 days prior

4/

24 hrs

queued > 24 hrs to start:

30 days

60 days

queued > 24 hrs to start:

24 hrs

12:00 day

prior

20 mins prior

to hour

queued < 24 hrs to start: best effort

queued < 24 hrs to start:

2 hrs

Non-Firm

1 month or

greater (monthly)

3 days prior

60 days

prior

N/A

2 days

N/A

24 hrs

15:00 day

prior

20 mins

prior to hour

Non-Firm

1 wk up to

1 mo (weekly)

2 days prior

14 days

prior

N/A

4 hrs

N/A

24 hrs

15:00 day

prior

20 mins

prior to hour

Southwest Power Pool ‐ Open Access Transmission Tariff, Sixth Revised Volume No. 1

Page 6


Term


Transmission




Customer

Response 1/


Non-Firm

1 wk up to

1 mo (weekly)

2 days prior

14 days

prior

N/A

4 hrs

N/A

24 hrs

15:00 day

prior

20 mins

prior to hour

Southwest Power Pool ‐ Open Access Transmission Tariff, Sixth Revised Volume No. 1

Page 7


Term


Transmission




Customer Response 1/


Non-Firm

1 day up to 1 wk (daily)

12:00 day

prior

2 days prior 4/

N/A

30 mins

N/A

2 hrs

15:00 day

prior

20 mins

prior to hour

Non-Firm

On-Peak Hours 9/

16 hours

(0600 – 2200)

(daily)

12:00 day

prior

2 days prior 4/

N/A

30 mins

N/A

30 mins

20 mins

prior to hour

20 mins

prior to hour

Non-Firm

Off-Peak Hours 9/

8 hours

(0000 – 0600

& 2200 – 2400) (daily)

12:00 day

prior

2 days prior 4/

N/A

30 mins

N/A

30 mins

20 mins

prior to hour

20 mins

prior to hour

Non-Firm

1 hour up to

1 day (hourly)

30 mins.

prior

12:00 day prior

N/A

Queued > 1 hr prior to

start: 30 mins

N/A

Queued day

prior: 30 mins

20 mins

prior to hour

20 mins

prior to hour

Queued < 1 hr prior to

start best effort

Queued current day:

5 min 5/

Next Hour

Market

next-hour (hourly)

20 mins prior 3/

1 hour prior 3/

N/A

Best Effort

N/A

N/A 3/

20 mins prior to hour 3/

20 mins. prior to hour 3/

Southwest Power Pool Open Access Transmission Tariff, Sixth Revised Volume No. 1

Page 8

1/ For transactions not covered by an umbrella service agreement, the customer response must be execution of a service agreement or a request that an unexecuted service agreement be filed with the Commission pursuant to Section 15.3 of the Tariff. For transactions under an umbrella service agreement, the above times are the deadlines by which time the customer must notify the Transmission Provider of its acceptance of the offer to provide transmission.

2/ The Transmission Provider, in its discretion exercised on a non-discriminatory basis, may

waive any of these requirements. 3/ All Next-Hour Market requests are submitted on schedule request and are deemed to be

pre-confirmed. 4/ Excluding Sundays and NERC Holidays. 5/ Or 2300 of previous day if for first hour of day. 6/ Non-firm schedules will be accepted after 15:00 day prior if there are no new reliability

risks identified since the reservation was accepted. This includes but is not limited to NERC TLR in effect.

7/ With regard to non-firm hourly for next day transmission involving the DC ties under

this Tariff, the following rule applies to limit abuse of the Transmission Provider’s scheduling process: If more than ten (10) requests are submitted by the same Transmission Customer or group of affiliated Transmission Customers per DC tie, per direction between 11:55:00 a.m. and 12:05:00 p.m. CPT, then all such requests shall be considered invalid.

8/ All transmission service requests received within the first five minutes after the specified

deadline shall be deemed as having been received simultaneously. Transmission Provider shall not make such requests publicly available via the OASIS or otherwise until the close of the five minute period. Subject to the preceding sentences, reservation requests received within the five minute period will receive priority--as between other requests received within the five minute period and in relation to reservation requests received thereafter--in accordance with the principle set forth in Sections 13.2 and 14.2 of the SPP OATT. Thereafter, in the event that there is insufficient capacity to meet all requests of an equal priority submitted within such five minute period, the available capacity shall be allocated to such requests on a pro rata basis in proportion to the megawatt quantity of the requests.

9/ For displaced and superseded purposes, Daily Non-Firm On-Peak hours and Daily Non-

Firm Off-Peak hours services will have a NERC priority (3-ND) greater than Hourly Non-Firm (2-NH) service. A Daily Non-Firm request that is 24 hours in duration will have priority over a Daily Non-Firm request for either the On-Peak hours only or the Off-Peak hours only. For curtailment purposes, a tagged transaction utilizing Daily Non-Firm On-Peak hours or Daily Non-Firm Off-Peak hours transmission service will be


Page 9

assigned a priority of 3-ND to be curtailed with other transactions with a priority of 3-ND on a pro rata basis. The Customer taking Daily Non-Firm On-Peak hours or Daily Non-Firm Off-Peak hours transmission service will be charged the applicable Attachment T rate for daily service determined by the day for which the service is being reserved. Unless otherwise explicitly stated in Attachment T, Off-Peak days are defined as Saturdays, Sundays, and NERC Holidays. All other days are considered On-Peak for the purposes of transmission service charges.

10/ Unless stated otherwise, all references to times “prior” refer to the requested start time of

service.

SERVICE INCREMENTS OFFERED BY SPP Point-to-Point Transmission Service and Network Integration Transmission Service are further characterized by service increments and windows, consistent with North American Energy Standards Board (NAESB) Wholesale Electric Quadrant (WEQ) Business Practice Standards 001-2.1.1, 001-2.1.2, 001-2.11, 001-2.12, and 001-2.13, which are incorporated into and made part of the Tariff pursuant to Attachment R-1. SPP offers only the following service increment and window combinations:

Fixed Hourly - The service starts at the beginning of a clock hour and stops at the end of a clock hour. Fixed Daily - The service starts at 00:00 and stops exactly 24:00 of the same calendar day (same as 00:00 of the next consecutive calendar date). Extended Weekly - The service starts at 00:00 of any date and stops at 00:00 more than one week later, but less than four weeks later. Extended Monthly - The service starts at 00:00 of any date and stops at 00:00 more than one month later, but less than twelve months later. Extended Yearly - The service starts at 00:00 of any date and stops at 00:00 more than one year later.

SPP Transmission Service products only are offered and processed in central prevailing time.

Deleted: prior for columns “No Earlier Than” and “No Later Than” are times

Deleted: to the requested

Deleted: date /


Page 10 of 10

Proposed Market Protocol Language Revision (Redlined) n/a

Proposed Business Practices Language Revision (Redlined)

n/a

Proposed Criteria Language Revision (Redlined)

n/a

Revisions to Other Corporate Documents (Redlined)

n/a

Balanced Portfolio Compliance Filing

March 22, 2012

Susan [email protected] ∙ 501.614.3260

Compliance Filing Timeline

• November 2, 2009

– Prior compliance filing, ER08‐1419

• December 16, 2011 (2 Years, 1 month, 14 days later…)

– FERC Order on Rehearing and Compliance Filing

• January 24, 2012

– Motion for Extension of Time

To develop tariff revisions through the stakeholder process

• January 31, 2012

– FERC Notice of Extension of Time to May 14, 2012

3

Compliance Filing Timeline (cont.)

• February – April 2012

– Stakeholder discussions

RTWG: February 23 & March 22

MOPC: April 10

Board of Directors: April 24

• May 14, 2012

– Compliance filing due

• October 17, 2008

– Effective date of tariff revisions

4

Compliance Filing Order Requirements

• Section VII.7(d) of the Information Exchange provisions of Attachment O

– Restricts access to resource‐specific data; “denies access to data that market participants need to replicate the results of transmission planning studies, such as an SPP Balanced Portfolio analysis”. Paragraph 19.

– Is inconsistent with FERC’s June 18, 2009 Order (127 FERC ¶ 61,271) and with the Order No. 890 transparency requirement that stakeholders have sufficient information to replicate transmission planning studies. Paragraph 19.

5

Compliance Filing Order Requirements (cont.)

– Imposes a “blanket restriction” on access to resource‐specific data and “does not strike an appropriate balance between transparency and confidentiality in the Balanced Portfolio review process”. Paragraph 21.

• FERC found that “confidentiality agreements may be used to restrict the availability of confidential competitive information in the transmission planning process such that it is available to customer personnel that are involved only in transmission functions, as opposed to merchant functions.” Paragraph 24.

6


• FERC found that “SPP’s proposed definition of Competitive Duty Personnel is too broad to allow interested SPP market participants to access resource‐specific data, subject to confidentiality agreements, that may be needed to participate fully in SPP’s Balanced Portfolio process and/or to replicate its transmission planning studies.” Paragraph 41.

7


• Problem

– “Competitive Duties” included

“the provision of consulting services in connection with the marketing, purchase, or sale of electric power at wholesale in the SPP Region”.

This “could encompass a wide variety of utility operations to effectively limit the counsel and outside consultants that market participants can turn to for assistance with evaluating Balanced Portfolio studies”. Paragraph 41.

8


• Transmission providers must disclose resource‐specific data if the information is:

– Provided in the planning process, and

– Necessary for stakeholders to replicate transmission planning studies and participate in the transmission planning process. Paragraph 42.

• “However, transmission providers may use confidentiality agreements to restrict the availability of confidential competitive information to transmission function customer personnel.” Paragraph 42.

9


• SPP must revise section VII.7(d) to:

– Remove unreasonable restrictions on access to resource‐specific data, and

– Provide for access to such data under appropriate confidentiality protections. Paragraph 47.

10

Proposed Compliance Filing

• Narrows the definition of “Competitive Duties”

– Eliminates its application to counsel or outside consultants

See redline comparison of proposed compliance language v. November 2, 2009 compliance language (background materials)

• One approach to compliance

– In 2009, FERC addressed Order No. 890 transmission planning process compliance filings of participants in the Southeast Inter‐Regional Planning Process (“SIRPP”), directing revisions to remove restrictions on information sharing identical to that of concern to SPP.

11

Compliance Filing Next Steps

• Next steps

– Presentation at April 10, 2012 MOPC meeting

– Presentation at April 24, 2012 Board of Directors meeting

– Compliance filing by May 14, 2012

12

Open Access Transmission Tariff, Sixth Revised Volume No. 1


Document Generated On: 1/25/2012

Contents VII. Information Exchange ................................................................................. 3

VII. Information Exchange

1) Data Requirements a) Any entity that is subject to the NERC Reliability Standards is

required to provide data to the Transmission Provider in accordance the NERC Reliability Standards for Modeling, Data and Analysis (the “NERC MOD Standards”).

b) When an entity has developed a preliminary engineering concept

for new facilities that impact the interconnected operation of the Transmission System, it shall contact the Transmission Provider so that the optimal integration of any new facilities and potentially benefiting parties can be identified.

c) In preparation for the annual update of transmission planning

models for each annual planning cycle, Members, Transmission Customers, Transmission Owners, Generation Interconnection Customers and all other stakeholders must provide to the Transmission Provider the data specified in this Section VII.

d) During the course of the annual planning cycle, if material changes

to the data occur, the data owners must provide timely written notice to the Transmission Provider.

e) The format required to submit modeling data shall be posted on the

SPP website. f) The modeling data shall be posted on the SPP website with

password protected access.

2) Owners of transmission facilities shall provide to the Transmission Provider: a) Modeling data for power flow, short-circuit and stability analysis; b) Detailed power system models of their transmission systems and

provide updates to their models via a password protected web based application;

c) Data regarding the design and operation of their transmission

facilities; d) Their FERC Form 715;

e) Their individual company-specific planning criteria; f) Planning grade cost estimates and schedules for upgrades in the

SPP Transmission Expansion Plan in a timely manner; g) Their five-year transmission construction plans; and h) Their transmission fixed charge rate.

3) Generator owners shall provide to the Transmission Provider:

a) Modeling data for power flow, short-circuit and stability analysis; b) Data for planned additions or upgrades, including status and

expected in-service dates, planned retirements and environmental restrictions; and

c) Modeling data to perform economic planning studies in accordance

with Sections III and IV of this Attachment O. Data required to model generating units for the economic planning studies is documented in the Transmission Network Economic Modeling and Methods manual which shall be posted on the SPP website.

4) Transmission Customers

a) Network Customers shall provide the Transmission Provider an

update of the information on its Network Integration Transmission Service application with a ten year forecast of summer and winter load at each delivery point and ten year projection of network resources and with any other information that has changed from the original application.

b) Point-to-point Transmission Customers shall provide to the

Transmission Provider their good faith projections on their need for service including transmission capacity, duration and points of delivery and receipt over the ten year planning horizon.

c) Transmission Customers with existing and planned demand

response resources, including demand response resources, shall provide information on such resources.

5) Neighboring Transmission Providers and RTOs

In accordance with applicable agreements and Section VIII of this Attachment O, the Transmission Provider shall exchange with neighboring Transmission Providers and RTOs the data required for the development

of power flow cases, short-circuit cases and stability cases over the ten year planning horizon.

6) Stakeholder Access to Transmission Planning Information a) The planning information, data, and models provided pursuant to

this Section VII shall be sufficient to allow parties to replicate results of the planning studies.

b) The Transmission Provider shall provide a secure web-based

workspace for hosting and sharing planning information, data, and models.

c) The secure web-based workspace shall be password protected and

require CEII clearance in accordance with Section VII.8 of this Attachment O.

d) Instructions to obtain access to the Transmission Provider’s power

flow models shall be posted on the SPP website. e) Instructions to obtain copies of the Transmission Provider’s

transmission planning maps shall be posted on the SPP website.

7) Confidentiality Requirements

a) The Transmission Provider shall make all reasonable efforts to preserve the confidentiality of information in accordance with the provisions of the Tariff and the SPP Membership Agreement.

b) For those entities that have executed a confidentiality agreement,

the Transmission Provider shall provide password protected access to confidential information related to the SPP Transmission Expansion Plan and the underlying studies and models via the SPP website.

c) The form of confidentiality agreement shall be posted on the SPP

website. d) The confidentiality agreement shall allow access to applicable

system design software results needed to participate in the SPP Transmission Expansion Plan process, replicate the results of specified transmission planning studies, or to confirm assumptions used in creating adjusted production cost-benefit metrics used to analyze a specified Balanced Portfolio; provided however, if the results include resource-specific data (including input data), access will be limited to individuals that are not Competitive Duty Personnel. For the purposes of this section:

i) “Competitive Duty Personnel” are any individuals directly

engaged in Competitive Duties. ii) “Competitive Duties” include: (1) the marketing, purchase,

or sale of electric power at wholesale, or (2) the direct supervision of any employee with responsibilities for the marketing, purchase, or sale of electric power at wholesale. However, “Competitive Duties” shall not include those duties enumerated above by an entity that has received a Commission-approved waiver of the Commission’s Standards of Conduct requirement.

e) Other transmission planning information shall be posted on the SPP website and may be password protected, as appropriate.

f) Confidentiality agreements shall be required for Members and

Market Participants to receive data where the owner of the data has given permission to the Transmission Provider to release the data.

8) Critical Energy Infrastructure Information (CEII) Requirements

a) The Transmission Provider shall take appropriate steps to protect

CEII information. b) The Transmission Provider shall screen Members and Market

Participants prior to providing access to CEII information. Individuals that do not belong to a confirmed pre-screened Member or Market Participant shall be directed to the Commission’s website for instructions for access to CEII information.

c) For those entities that have met the CEII requirements in Section

VII.8.b of this Attachment O, the Transmission Provider shall provide password protected access to CEII information related to the SPP Transmission Expansion Plan and the underlying studies and models via the SPP website.

d) The Transmission Provider shall follow the guidelines set forth by

the Commission to flag data which shall be treated as CEII sensitive.

Effective Date: 7/26/2010 - Docket #: ER10-1960

Formatted: Indent: Left: 108 pt

Deleted: Resource specific data shall not be made available by the Transmission Provider if the data has been designated confidential by the data provider or if the data can be used to: ¶¶i) Determine security constrained unit commitment or economic dispatch for resources; or ¶¶ii) Perform an economic evaluation of costs and benefits. ¶¶



or sale of electric power at wholesale, or (2) the direct supervision of any employee with responsibilities for the marketing, purchase, or sale of electric power at wholesale.

iii) “Competitive Duties” shall not include those duties

enumerated in section 7(d)(ii) above by an entity that has received a Commission-approved waiver of the Standards of Conduct requirement of Order No. 889.

e) Other transmission planning information shall be posted on the

SPP website and may be password protected, as appropriate. f) Confidentiality agreements shall be required for Members and













or sale of electric power at wholesale, or (2) the direct supervision of any employee with responsibilities for the marketing, purchase, or sale of electric power at wholesale. However, “Competitive Duties” shall not include those duties enumerated above by an entity that has received a Commission-approved waiver of the Commission’s Standards of Conduct requirement.

e) Other transmission planning information shall be posted on the SPP website and may be password protected, as appropriate.

f) Confidentiality agreements shall be required for Members and











Formatted: Indent: Left: 108 pt

Deleted: Resource specific data shall not be made available by the Transmission Provider if the data has been designated confidential by the data provider or if the data can be used to: ¶¶i) Determine security constrained unit commitment or economic dispatch for resources; or ¶¶ii) Perform an economic evaluation of costs and benefits. ¶¶

Southwest Power Pool, Inc. SPP STAFF

Report to the Regional Tariff Working Group March 22, 2012

Withdrawal Obligations for Transmission Expansion Costs

Background The Corporate Governance Committee (CGC) met March 1 and discussed the recent feedback from the RTWG regarding the currently proposed revisions to SPP’s governing documents to address the impact of an entity’s withdrawal on regional transmission cost allocation. The results of that discussion:

1) The current drafts contemplate applying the provisions to all Network customers under the Tariff,

regardless of membership status. The RTWG questioned whether this was appropriate and/or would be considered equitable at FERC. Following further consideration and given that non-member network load represents approximately 1% of total load (and is expected to decline); the CGC has directed the draft be revised to apply only to member organizations. In addition, any potential mitigation measures to address the impact of non-member network customers will be researched and reported back.

2) The RTWG and NPPD separately raised concerns with no plans to provide any credits for future service for any withdrawal fee assessed. Following discussion, the CGC determined to continue to move forward with the current draft providing no credits, but to present this issue at the MOPC and Board meetings in April for discussion and policy direction. In addition, any suggestions from the RTWG would be helpful.

The CGC has asked staff to plan to present a more detailed report at the MOPC and Board meetings in April regarding the current draft (revised as noted above) and noting policy considerations for feedback (via straw votes if needed). This information will be reported back to the CGC for further consideration, with a goal if making recommendations and seeking votes at the MOPC and Board meetings in July.

Business Practice Revision

Page 1 of 5

BPR Number 018 BPR

Title Guideline for Clarifying Application of the SPP Generator Interconnection Procedures

Business Practice Section(s) Requiring Revision (include Section No., Title, and Protocol Version)

New business practice

Impact Analysis Required (Yes or No)

No

MMU Report Required (Yes or No) No Requested Resolution (Normal or Urgent) Normal


New BP This is the clean version of the Business Practice that was approved by the BPWG on 2/28/2012.

Reason for Revision To provide a guideline to clarify application of the SPP Generator Interconnection Procedures set forth in Attachment V to the SPP OATT

Tariff Implications or Changes (Yes or No; If yes include a summary of impact and/or specific changes)

Yes, this proposed new business practice may impact, or be impacted by, language in Attachment V of the SPP OATT.

Criteria Implications or Changes (Yes or No; If yes include a summary of impact and/or specific changes)

No

Credit Implications (Yes or No, and summary of impact)

No

Working Group/Committee Review and Results

BPWG – Approved on 2/28/2012 ORWG – Pending final review for reliability impacts on 8/16/2011 RTWG – Reviewed on 1/6/2011 and submitted comments. Reviewed

on 8/25/11 and submitted comments. TWG – Reviewed on 2/2/2011 and submitted comments. MOPC – Voted to send the approved language back to the BPWG

on 4/12/2011 for further editing.


Page 2 of 5

Sponsor Name James R. Hotovy E-mail Address [email protected] Company Nebraska Public Power District Company Address 1414 15th Street, Columbus, Nebraska 68601 Phone Number 402 563-5674 Fax Number

Proposed New Business Practice

XXXX GUIDELINE FOR CLARIFYING APPLICATION OF THE SPP GENERATOR INTERCONNECTION PROCEDURES Business Practice

Guideline for Clarifying Application of the SPP Generator Interconnection Procedures

A. Basic Principles of Applicability As set forth in Section 2.1 of Attachment V to the SPP Open Access Transmission Tariff (“OATT”), the OATT’s Generator Interconnection Procedures (“GIP”) apply to the processing of Interconnection Requests for generator interconnections to the Transmission System that are subject to FERC jurisdiction. Any generator interconnecting to the Transmission System where such interconnection is subject to FERC jurisdiction must submit an Interconnection Request pursuant to Attachment V of the SPP OATT. B. Exceptions to Applicability This guideline serves to clarify application of the GIP by providing examples of instances where the GIP would not apply. Examples include, but are not limited to instances where:

1. The Generating Facility will be a Qualifying Facility (“QF”) where the QF’s total output will be sold to its host utility according to PURPA and subject to state jurisdiction.1

1 Interconnection Customers claiming exemption from the GIP must provide documentation of Qualifying Facility FERC certification, substantiating state jurisdiction and documentation from the host that 100% of the output will be sold to the host utility at avoided cost. QFs intending to make third party sales are subject to FERC jurisdiction per Order 2003 and are appropriately studied as part of the GIP. See FERC

Deleted: that

Deleted: to

Deleted: because the interconnection request is not subject to FERC jurisdiction. ¶


Page 3 of 5

2. The Generating Facility will interconnect to a facility not already subject to the

OATT at the time the request is submitted, whether or not it plans to make wholesale electric energy sales.2

3. The Generating Facility will produce electric energy to be consumed only on the Interconnection Customer’s site. 3

4. The Generating Facility will be used to supply energy only to unbundled retail customers over local distribution facilities. 4

5. Generating Facility will not operate in sustained parallel with the Transmission

System. For purposes of this exception, “sustained parallel” applies to any Generating Facility which operates in synchronous operation with the electrical power system for 100msec or more.

C. System Studies for Non-jurisdictional Facilities Generator interconnections, not subject to the OATT, may still require studies to identify impacts on SPP’s or the Host Transmission Owner’s (“Transmission Owner”) transmission system. The Transmission Owner will notify SPP of interconnection requests of 5 MW or more that are submitted directly to the Transmission Owner because they fall under the exemptions in this business practice; or are otherwise required by the Transmission Owner’s processes to be studied pursuant to SPP’s study process. SPP and/or the Transmission Owner will evaluate each interconnection request not subject to OATT requirements and will make the final determination whether the interconnection study will be performed by SPP and/or by the Transmission Owner. In instances where Order No. 2003 at P 814 (“[T]he Commission has jurisdiction over a QF’s interconnection to a Transmission System if the QF’s owner sells any of the QF’s output to an entity other than the electric utility directly interconnected to the QF. . . This jurisdiction applies to a new QF that plans to sell its output to a third party, and to an existing QF interconnected to a Transmission System that historically sold its total output to an interconnected utility or on-site customer and now plans to sell output to a third party.”). See also FERC Order No. 2003 at P 813; FERC Order No. 2006-A at PP 100-102; PURPA 292.203.a (3); PURPA 292.303. No interconnection of a QF pursuant to the GIP affects or diminishes any substantive rights of the QF to assert non-FERC jurisdictional status at any time according to the requirements of the law. 2 See FERC Order No. 2006 at PP 5, 8; FERC Order No. 2003 at P 804; FERC Order No. 2003-A at P 710; FERC Order No. 2003-C at P 51. At the time an Interconnection Request is made to interconnect to a non-jurisdictional facility, the interconnection is not subject to the GIP. After a Generation Facility that makes wholesale electric energy sales has been connected, the interconnection facility is now subject to an OATT for Interconnection Requests made after that time. 3 See FERC Order No. 2003 at P 805; FERC Order No. 2003-A at P 747, n. 173. 4 Unbundled retail service over local distribution facilities is not under FERC jurisdiction. See FERC Order No. 2006 at PP 7-8 and n.8.

Deleted: Distribution

Deleted: Facilities

Formatted: Not Superscript/ Subscript

Formatted: No bullets or numbering

Deleted: although

Deleted: to


Page 4 of 5

further study is warranted, such studies will be performed by the Transmission Owner or SPP, at the direction of the Transmission Owner. Non-jurisdictional generator interconnection customers may be required to enter into the appropriate study agreements with SPP to facilitate an Affected System Agreement. Additionally, requests for non-jurisdictional generator interconnections may be required to be coordinated with SPP in accordance with NERC standards. Although such studies may be performed within SPP’s GIP for planning purposes, the non-jurisdictional generator interconnection customer will not be subject to the OATT. In such instances, the following shall apply:

1) When notified, the Transmission Owner is responsible for conducting any required studies to determine if the request may impact the Transmission System.

2) Should the Transmission Owner determine that the generator interconnection may

impact the Transmission System, the Transmission Owner shall notify SPP of such impacts and provide to SPP any system impact studies that detail such impacts.

3) As an impacted system, SPP will determine what additional studies will be required to coordinate the impacts, up to and including studying the impact in the Definitive Interconnection System Impact Studies. The Transmission Owner/distribution provider shall require as a condition of interconnection with the interconnection customer, that all SPP required studies be completed. The Transmission Owner/distribution provider shall have the option to enter into the applicable Affected System study agreements and to be financially responsible for such studies, or as a condition of interconnection, to require the interconnection customer to submit a request to enter the Definitive Interconnection System Impact Study process or other SPP study process as applicable.5

4) It shall remain the Transmission Owner’s responsibility to complete any generator interconnection agreements in accordance with the Transmission Owner’s generator interconnection procedures regarding the completion of Network Upgrades required on the Distribution System and on the Transmission Owner’s transmission system.

5) If SPP’s studies show that Network Upgrades are required on the Transmission

System, the Transmission Owner/distribution provider shall have the option to enter into a facilities agreement with SPP or require, as a condition of interconnection, the interconnection customer to enter into a facilities agreement with SPP and any affected Transmission Owner(s)/distribution provider(s) to complete the Network Upgrades required on their Transmission System.

6) All Network Upgrades must be completed prior to operation of the Generating

Facility, unless other mitigations have been approved by SPP until the Network Upgrades are completed.

5 The Transmission Owner(s)/distribution provider(s) has the ability to pass-through the Interconnection Study costs to its customer.

Deleted: to the Transmission System

Deleted: Transmission/Distribution Owner


Page 5 of 5

Explanation / Rationale This Business Practice is intended to be general information for SPP customers.

DRAFTTHROUGH AND OUT RATE METHODOLOGY AND RATE IMPACT MITIGATION OPTIONS:

Rate Calculation Methodology

Option Description CommentsImplementation

Cost

Change in Zonal Rate in$/MW-yr & Revenue %

ImpactAdditional

CommentsImplementation

Cost

Change in Zonal Rate in $/MW-yr & Revenue %

ImpactAdditional

CommentsImplementation

Cost

Change in Zonal Rate in$/MW-yr & Revenue

% ImpactAdditional

Comments

A Lowest rate of interconnected zonesDoes not achieve cost basis and rate parity goals as effectively as average rates. $3,900

High POD = $572 Low POD = $0 Revenue = +13% $0 $0 Current method. $3,900

High POD = $1,223 Low POD = $0 Revenue = +2%

B Average rate of interconnected zones $45,500

High POD = $2,337 Low POD = $0 Revenue = +65% $45,500


Method proposed to MOPC in January $45,500


C

Weighted average exit rate with the weighting based on capacity of interconnection with the external POD

Depending on the relative interconnection capacity, this may benefit loads heavily dependent on SPP transmission facilities. Ongoing coordination required between SPP settlement and engineering departments. $59,800




D

Sum the zonal rates for Schedules 7/8 and 11 before determining the lowest interconnected zone rate

SPP would need to track Schedule 7/8 revenue separately from Schedule 11. Zones with lowest Sched 7/8 rates affect pricing under Schedule 11 $59,800


High POD = $0 Low POD = $0 Revenue = 0%

Not consistent with Schedule 11 excluding SPA $59,800


ERate of zone with highest capacity of interconnection with external POD

Depending on relative interconnection capacity, this may benefit loads heavily dependent on SPP transmission facilities. Ongoing coordination required between SPP settlement and engineering departments. $59,800




F Average rate of all zones Likely to result in less rate volatility than other methods $45,500

High POD = $1,633 Low POD = - $4,082 Revenue = +45%

Method proposed to MOPC in January

Rate Impact Mitigation

Option Description CommentsImplementation

Cost Rate ImpactsG No mitigation -$

H

Phase in the transition between minimum and average exit zone rates over an extended period, such as 5 or 6 years

Limits the transition period. Ultimately results in full rate impact on long-term commitments. Prolongs subsidy of T&O service relative to no phase-in $45,500

IAllow customers a one-time opt-out of their T&O transmission reservations

Directly assigned costs associated with T&O reservations must be recovered from the responsible parties even if the service terminates. Gives customer control. Manual bill procedure for SPP. Could result in a rush for short-term service. Does not resolve the problem of dependent load TBD

Approximately 70 T&O reservations, representing ___ MW, presently have service extending into 2014

J

Grandfather existing long-term transmission service under the minimum rate while any new service would be billed under an average rate

3 options include no rollover, unlimited rollover, and term of associated power supply. Very long transition period if unlimited rollover. No "hook" in settlement system if tied to term of power supply. Greater price stability for long-term service.

$130,000 one-time or $150,000

with rollover

K Combine one-time opt-out with longer phase-in Directly assigned cost issue noted above TBD

LCombine one-time opt-out with grandfathering only the current reservation. Directly assigned cost issue noted above

$130,000 plus $zzz

M

Carve out lowest rate pricing for only customers with certain characteristics (i.e., customers largely dependent on SPP interconnections

Addresses only a portion of customers with long-term service commitments TBD

Note: Mitigation measures can be applied to Schedules 7 and 8 only or to all three schedules.

Schedules 7 and 8 Rate Methodology with SPA Included Schedules 7 and 8 Rate Methodology without SPA Schedule 11 Rate Methodology without SPA

Crediting Process Task Force Recommendations

RTWG MeetingMarch 27, 2012

David L. Kays, Chair

Task Force FocusThe Task Force’s efforts have been to “simplify” the crediting process currently in the OATT. The focus of this effort has been to minimize the number of;

a) subsequent Upgrade Sponsors due credits, and b) Creditable Facilities being tracked by SPP Staff.

Therefore, the Task Force has the following clarifications and recommendations for RTWG consideration and endorsement.

Clarification:

Add language to the Tariff making it clear that a Generation Interconnection Customer that paid for a Network Upgrade(s) as part of its Interconnection Process will be treated in the same manner as a customer who paid for a Sponsored Upgrade.

– Which means the GI Customer will receive all of the credits until they are made whole before any other customer receives credits for that Creditable Facility.

Recommendation #1• If the total upgrade costs for a Transmission Service

Requests exceeds the Safe Harbor Limit (SHL), modify the Tariff such that Network Upgrades are “stacked” from lowest to highest costs with any credits owed for the use of existing Creditable Facilities “stacked” on top of the new upgrades, also from lowest to highest. The SHL is then applied to the “stack” beginning with the lowest cost new upgrade. Upgrade costs exceeding the SHL are directly assigned to the TSR.

Recommendation #1

• Benefits:– Currently, if the total upgrade costs exceed the SHL,

that cost is directly assigned to the customer on a prorata basis from all upgrades impacted by the TSR. (Attachment J, Section III.B.1f) making each one a Creditable Upgrade. This should limit the number of new Creditable Upgrades created.

– not direct assign de minimus costs from lower cost upgrades.

Recommendation #2• Attachment Z2, Section II contemplates “Future Roll-In”

without much specificity as to when the roll-in should occur.

• Modify the Tariff such that a Creditable Facility may be rolled into transmission rates if it meets the following two tests;– Test 1 – using the Summer Peak model the Creditable Facility

must have a loading greater than or equal to 30% of the added capacity.

– Test 2 – using the Summer Peak model and performing an N-1 analysis, the Creditable Facility must have a loading greater than or equal to 65% of the added capacity.

Support for Thresholds

‐20%

0%

20%

40%

60%

80%

100%

120%

140%

160%

0% 20% 40% 60% 80% 100% 120%

% of Loa

ding

% of Elements

Element Loading

N‐1 Max Loading

SP Loading

Support for Thresholds

‐20%

0%

20%

40%

60%

80%

100%

120%

0% 20% 40% 60% 80% 100% 120%

% Loading less than vs % of Elements ‐ Summer Peak

Loading

69 kV

115 kV

138 kV

161 kV

230 kV

345 kV

Support for ThresholdsSummary Table ‐ % of Loading (less than) by % of Elements

% of Elements N – 1 Loading Summer Peak

10% 17% 5%

20% 28% 9%

30% 37% 13%

40% 43% 17%

50% 50% 21%

60% 57% 25%

70% 65% 31%

80% 72% 38%

90% 82% 48%

100% 141% 94%

Still Ahead

• SPP Staff’s efforts to implement the White Paper

• Review how an Upgrade Sponsor is “paid” off to see if any issues exist

• Develop Tariff language • Look at crediting and future Integrated

Marketplace

Request

RTWG’s endorsement of the Task Force’s clarifications and recommendations.

Questions

From: Liu, BernardTo: Reed, Dennis; Kays, David; Nicole WagnerSubject: Xcel Voting Proxy for the RTWG 3/22 meetigDate: Wednesday, March 21, 2012 2:42:29 PM

Dennis, This email is to inform you that I would like to assign my voting proxy to Mr. David Kays for the March22, RTWG meeting. I also copied Nicole Wagner since I do not have our new staff member’s contactinformation. Please let me know if you have any questions. Thanks,Bernie

Bernard LiuXcel EnergySr. Transmission Tariff Consultant, Regulatory Administration - Transmission414 Nicollet Mall, 7th Floor Minneapolis, MN 55401P: 612-330-5728 F: 612-330-7699E:[email protected]________________________________________________XCELENERGY.COMPlease consider the environment before printing this email.

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