Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING December 1, 2006 Teleconference AGENDA. 1:30 p.m. 3:00 p.m. CST

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1 Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING December 1, 2006 Teleconference AGENDA 1:30 p.m. 3:00 p.m. CST 1. Call to Order... Mr. Jim Eckelberger 2. MOPC Recommendation for Tariff Language Modifications...Ms. Robin Kittel a. PRR125 - Violation Relaxation Limits b. PRR128 - Response to Notification of Market Infeasibility c. Schedule 2 Modifications - Reactive Supply and Voltage Control from Generation Sources Service 3. Adjourn... Mr. Jim Eckelberger

2 Southwest Power Pool, Inc. MARKET WORKING GROUP Recommendation to the Market and Operations Policy Committee December 1, 2006 Organizational Roster The following members represent the Market Working Group: Richard Ross, AEP, Chairman Gene Anderson, OMPA Doug Base, WFEC Gary Clear, OG&E Terri Eaton, Xcel Energy Robert Janssen, Redbud Energy Charles Locke, KCPL Rick McCord, EDE Tambra Offield, ETEC Tom Saitta, Aquila James Stanton, Calpine John Stephens, Springfield MO Tom Stuchlik, Westar Keith Sugg, AECC Richard Dillon, SPP, Secretary Background Since the release of the Market Protocols to the MOPC and RTWG, questions have resulted in a desire to modify the Market Protocols to clarify certain aspects and correct certain details. A meeting was held by the MWG on November 21, 2006 for these changes. Analysis There have been changes proposed for the purpose of documenting additional understanding of market design aspects and clarification of current protocols. The PRRs approved by the MWG are listed below and grouped for recommendation purposes. Recommendation The MWG recommends the MOPC adopt the approved Protocol Revision Requests for incorporation into the Market Protocols. Action Requested: Approval of PRR Recommendations for incorporation into the Market Protocols. Page 1 of 2 Page 8 of 38

3 PRR Number Description Vote No Votes 125 Clarify procedures relating to application of Violation Relaxation Limits to address price excursions. SPP documentation does not address Violation Relaxation Limits that effectively act as pricing speed bumps due to the use of operational alternatives in resolving injection and withdrawal differences. 9-yes (both Tariff and Protocol Language) 1-no (Westar) MWG Meeting 21-Nov 128 In the absence of the intra-day feasibility analyses originally included in the protocols (removed in PRR 104), there is little utility to this analysis on a day ahead basis. Therefore, it is not reasonable to expect MPs to incur costs to modify their operating plans on a day ahead basis to address an infeasible solution that will likely not materialize in real-time. The requirement to modify operating plans should be deleted and reinstituted as appropriate when intra-day analysis exists. 4 yes (Protocol Language) 8 yes (Tariff Language) 1 no (OMPA) - Protocol Language only 21-Nov Page 2 of 2 Page 9 of 38

4 PRR 125 Number Timeline (Normal or Urgent) Protocol Section(s) Requiring Revision (include Section No., Title and Version) Revision Description PRR Recommendation Report PRR Title Violation Relaxation Limits (formerly known as Slack Variables) Urgent Recommended Action Approve 9.1, Introduction to section on Deployment Clarify procedures relating to application of Violation Relaxation Limits to address price excursions. SPP documentation does not address Violation Relaxation Limits that effectively act as pricing speed bumps due to the use of operational alternatives in resolving injection and withdrawal differences. Protocol and Tariff language approved with 9 yes and 1 no vote (Westar). Westar dissenting opinion: There are several reasons why Westar could not support PRR 125 on the 11/21/2006 MWG conference call. These reasons include specific shortcomings within PRR 125 and overall policy direction. PRR Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained) Shortcoming within PRR 125 Does not provide details and operational impacts of VRL application when VRL application in necessary and no flowgates are constrained. Does not provide any detail on magnitude, duration, and severity of VRL applications when no flowgates are constrained. Policy Issue PRR 125 continues the disturbing notion that any MOS limitations and/or market design limitations creating operational problems in the EIS market defaults to Balancing Areas having to mitigate with AGC. Example of MOS limitation include the single hourly ramp rate value of generating resources; example of market design limitation include the fact adequate depth of offers cannot ever be ascertained. Westar has consistently opposed to any protocol that uses the BAs as backstops. Another disturbing concept is SPP's apparent desire to rely on "Emergency." If market design limitations and/or MOS design limitations create a situation when only "Emergency" and subsequent manual dispatch can mitigate, then Westar is concerned that (1) SPP is possibly difusing the critical distinction between its roles as a market operator and a Reliability Coordinator, and (2) that EIS market will result in more frequent declarations of "Emergency" compared to non-market condition: which will provide negative benefits to all concerned. PRR125_Recommendation_Report Page 101 of of 38 7

5 PRR Recommendation Report ORWG Review MOPC Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained) Name Company Original Sponsor Terri Eaton Xcel Energy Comment Author SPP Staff Xcel SPP Staff Comments Received Comment Description Comments regarding the process of deployment calculation Incorporation of the VRL value setting process Tariff Language Proposed Protocol Language Revision 9.1 Introduction SPP shall determine the least costly means of obtaining energy to serve the next increment of Load at each injection/withdrawal node defined in the State Estimator for SPP and each interface bus between SPP and an adjacent Control Area using its Scheduling, Pricing, and Dispatch (SPD) program. The following limiting factors are The factors normally employed by the SPD program in determining the least costly means of serving the next increment of Load: shall be based on the system conditions described by the most recent power flow solution produced by PRR125_Recommendation_Report Page 112 of of 38 7

6 PRR Recommendation Report the State Estimator program, unit parameters provided in resource plans, energy offers, and binding transmission constraints. In certain situations, as described more fully below, SPP may dispatch the system in a manner that does not fully enforce all such system constraintslimiting factors by applying ConstraintViolation Relaxation Limits (CVRLs) in SPDmay direct system dispatch in a manner that is inconsistent with either the unit parameters in resource plans or in a manner that does not honor specified system constraints where such dispatch will provide a lower cost solution in a manner that does not compromise system reliability. Dispatch under these conditions shall be termed Alternative Dispatch. The SPD program uses an incremental linear optimization method to minimize energy costs. In performing this calculation, SPP shall use the EIS offer(s) that can serve the Load at a bus at the lowest cost and shall assume Self Dispatched Resources will be operating at their scheduled Megawatt level indicated on the RTO_SS schedules and the Native Load Scheduler at the end of each Dispatch Interval. The dispatch does not take into account the differences in loss factors between Resources when calculating dispatch instructions. This deployment determines the dispatch instructions for Resources that have offered to provide EIS. Resources that have elected to be dispatched by SPP will have the entire MW capability available for SPP dispatch, subject to the MaxMW, MinMW, Ramp Rate and Ancillary Service parameters specified by the Market ParticipantParticipant in the Resource and Ancillary Service Plans. The dispatch instructions on these Resources is based upon the Offer Curve, Resource Plan, and Ancillary Services Plan Application of CVRLs Where necessary to avoid excursions in shadow prices that may result if the shift factors associated with the units that can provide respond to security constrained, least cost system dispatch are relatively low, and to ensure a programmatic solution in all cases, the SPD program may employ CVRLs. direct Alternative Dispatch, or dispatch in a manner that does not respect unit parameters provided in resource plans or transmission system limits. CVRLs identify points at which SPD will consider operational options to balance system injections and withdrawals that involve violation of system constraintslimiting factors. or operational limits. The relative levels at which the CVRLs are quantified is an indication of the relative priority for enforcing the constraint and limitslimiting factors. For example, a higher CVRL assigned to a ramp rate constraintlimit relative to a flowgate constraint would indicate that the transmission constraint should be violated before the ramp rate constraintlimit. When an operational constraint limit is reached, it is referred to as binding. When a constraint is both binding and violated, its shadow price will be capped at the associated CVRL. Units that can be dispatched in a manner that will help relieve the constraint or limit will be so dispatched, starting with the unit that makes the lowest contribution to the shadow price, up to the point that the aggregate shadow price associated with all dispatched units would exceed the value associated with the CVRL. If the CVRL with the lowest value will not allow SPD to balance the market s energy obligations, other CVRLs will be applied in ascending value order until the market s energy obligations can be balanced. There are four categories of CVRLs that may be applied within SPD: Operational constraints (OCs); subcategories being: o Flowgate constraints o RTCA constraints PRR125_Recommendation_Report Page 123 of of 38 7

7 PRR Recommendation Report o Watch list constraints o Manual constraints o Pnode constraints (not currently active) Resource ramp rate limits Market balance (generation to load) Resource capacity maximum/minimum output limits If SPP is unable to achieve the market flow relief required by the IDC to address a TLR/CAT event on a constrained flowgate within 30 minutes, SPP will take whatever steps are necessary to bring the line flows to within acceptable limits, including declaring appropriate emergencies and/or issuing manual instructions. Upon such an event, SPP will initiate within one business day after this occurrence the analysis described in Section Any Alternative Dispatch solution will be selected from among a list of alternatives that have been assigned specified values that have been approved by MOPC and are posted on the SPP OASIS website. A posted alternative dispatch solution may be directed by SPP if the value assigned to that alternative is less than the cost of conventional system dispatch and application of the alternative will not compromise system reliability. The table below identifies the types of dispatch alternatives that may be applied by the SPD program. This list is not intended to be exhaustive, and simply because an alternative is shown below does not mean that that alternative must be employed within the SPD program at any given time. Potential Alternative Resource capacity (max/min) violation System energy balance Resource ramp rates Flowgate constraint Description SPD may select a dispatch solution that directs deployment of a unit at a level that is either below or above the unit minimum/maximum limits prescribed in the resource plan. SPD may select a system dispatch solution that creates imbalances between control areas. SPD may select a system dispatch solution that directs deployment of a unit at a ramp rate other than the unit ramp rate specified in the resource plan. SPD may select a system dispatch solution that directs dispatch in a manner that exceeds a flowgate limit Impact of CVRLs on LIPs and UD Charges PRR125_Recommendation_Report Page 134 of of 38 7

8 PRR Recommendation Report The limit value associated with any CVRL applied by SPD shall not be used directly in determining the LIP for any unit. Therefore, LIPs will not reflect application of any CVRL.LIPs produced will be determined by the Resource dispatch instructions issued by MOS. The VRL will impact Resource dispatch instructions when the projected shadow price exceeds the value of the VRL Charges for uninstructed deviation shall not be applied to the extent that dispatch instructions provided for a unit reflect application of a CVRL that resulted in dispatch of the unit in a manner that violates a unit parameter specified in a Market Participant s Resource Plan Determination of CVRLs CVRLs and their associated values shall be approved by the MOPC based on recommendations received from ORWG and MWG. Approved CVRLs and their associated values shall be postedbe posted on the SPP OASIS website. CVRL values shall be set at a levels projected to assure that: (1) mitigate the occurrence of price excursions above the safety net offer cap or below zero is not statistically significant; and (2) loading violationscurtail the portion of a loading violation attributed to market flow on a flowgates do not persist for morewithin than 15 minutes of the start of a VRL violation; (3) mitigate the regulation burden placed on the units providing regulation services; (4) not contribute to CPS violations; and (5)minimize the need for Manual Dispatch Instructions.. Initial CVRL values shall be developed based upon an analysis of data generated through deployment tests. Thereafter, on at least an annual basis, SPP will prepare an analysis of whether existing CRLVRLs and associated values are meet the criteria specified above. If these criteria are not being met, SPP shall recommend new CRLVRLs and associated values and provide an analysis that supports this recommendation. SPP s analysis and recommendations shall be to ORWG and MWG for their evaluation and consideration. Any changes to CRLVRLs and their associated values recommended by ORWG and MWG shall be presented to MOPC for consideration as discussed above. During at least the first 12 months of the market, SPP shall report the following information to MWG and ORWG on at least a monthly basis within 15 days of the last day of the month: a. The number of times that CRLVRL values were applied by SPD during the month, and associated detail regarding the CRLVRL type and value for each incident; b. The value of each LIP in excess of the safety net offer cap or below zero during the month; c. The number and duration of each incident where a CRLVRL was employed with respect to the same flowgate for more two or more consecutive intervals. d. If SPP was unable to achieve the market flow relief required by the IDC, the constraint that was violated, the deployment interval(s) during which the violation occurred, the MW amount of the violation, and the Min and Max LIP during the violation period. e. The assessment of regulation requirement from application of a VRL. PRR125_Recommendation_Report Page 145 of of 38 7

9 PRR Recommendation Report f. The number of CPS violations coincident with the application of a VRL. g. The number and magnitude of Manual Dispatch Instructions issued coincident with the application of a VRL. Upon review of this data, either MWG or ORWG may request that SPP reevaluate existing CRLVRL levels to determine whether existing CRLVRL values meet the criteria specified above. SPP s analysis shall be presented to MWG and ORWG for their evaluation and consideration as specified above. If SPP is unable to achieve the market flow relief required by the IDC to address a TLR/CAT event on a constrained flowgate within 30 minutes,, SPP will initiate within one business day after this occurrence the analysis described above. If SPP determines through its analysis that a CRLVRL or its associated value needs to be adjusted to allow SPP to achieve market flow relief within 30 minutes in the future if a TLR/CAT event is called, SPP may adjust the CRLVRL without approval for a maximum period of 14 days. Within this 14 -day period, a joint meeting of the ORWG and MWG shall be convened to consider the CRLVRL adjustment implemented by SPP. Any CRLVRL adjustment approved by ORWG and MWG shall remain in effect pending review and approval by MOPC, which review and approval must occur within 120 days of interim approval by ORWG and MWG. Any CRLVRL adjustment implemented by SPP without prior approval of the MOPC shall be posted on the SPP OASIS website, and notice of such adjustment shall be distributed via the ORWG, MWG, and MOPC exploders. Tariff Language Changes to Attachment AE: 4.1 Dispatch Process (a) Throughout the Operating Day, generally every 5 minutes, the Transmission Provider shall: (i) Perform a security constrained economic dispatch (SCED) for the SPP Region utilizing an optimization method to determine the least costly means of obtaining energy to serve the next increment of load based upon submitted Offer Curves, Resource operating data submitted as part of the Resource Plan, binding transmission constraints, forecasted SPP Region load and system conditions from the State Estimator, relaxation of operating limits (Violation Relaxation Limit or VRL); (e) To the extent that a Resource is determined by the Transmission Provider to have failed to follow the Transmission Provider s dispatch instruction, such failure to PRR125_Recommendation_Report Page 156 of of 38 7

10 PRR Recommendation Report follow dispatch instruct determination in accordance with the procedures set forth under Section 4.1(d) of the is Attachment AE, the Market Participant owner of that resource shall be subject to an Uninstructed Deviation Charge. Resources shall not be subject to Uninstructed Deviation Charges for any Uninstructed Deviation Megawatts caused by: (1) manual deployment of dispatch instructions by the Transmission Provider; (2) operating a Resource in Test Mode; (3) operation of a Resource in Start-up Mode or Shut-down Mode; (4) instances when a Resource trips after receiving dispatch instructions from the Transmission Provider; or (5) the Resource is an Intermittent Resource or (6) the dispatch instructions issued to a Resource were beyond the reported capabilities in the Resource Plan due to the application of a VRL. Uninstructed Deviation Charges shall be calculated by the Transmission Provider in accordance with Section 5.5 of this Attachment AE. The Transmission Provider may also waive Uninstructed Deviation Charges 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. 4.6 Violation Relaxation Limit Values (a) Violation Relaxation Limit (VRL) values determine the point at which the deployment considers operational options to balance system injections and withdrawals that involve violation of limiting factors. (b) At least annually, SPP will analyze the effect of VRL values on reliability and pricing above the safety net offer cap. Initial VRL values shall be developed based upon an analysis of data generated through deployment tests. If the VRL values are compromising reliability or allowing pricing above the safety net offer cap, SPP shall recommend new VRL values to the SPP membership for approval as specified in the Market Protocols. (c) If SPP is unable to achieve the market flow relief required by the IDC to address a TLR/CAT event on a constrained flowgate within 30 minutes, SPP will initiate within one business day after this occurrence the analysis described above. If SPP determines through its analysis that a VRL or its associated value needs to be adjusted to allow SPP to achieve market flow relief within 30 minutes in the future if a TLR/CAT event is called, SPP may adjust the VRL values without approval while seeking SPP membership approval as specified in the Market Protocols. (d) The current values for VRL will be posted on SPP s OASIS. PRR125_Recommendation_Report Page 167 of of 38 7

11 PRR 128 Number Timeline (Normal or Urgent) Protocol Section(s) Requiring Revision (include Section No., Title and Version) Revision Description PRR Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained) ORWG Review MOPC Recommendation (indicate whether all segments were present for the vote, and the segment of parties that voted no or abstained) PRR Recommendation Report PRR Title Response to Notification of Market Infeasibility Urgent Recommended Action Approve Market Infeasibility In the absence of the intra-day feasibility analyses originally included in the protocols (removed in PRR 104), there is little utility to this analysis on a day ahead basis. Therefore, it is not reasonable to expect MPs to incur costs to modify their operating plans on a day ahead basis to address an infeasible solution that will likely not materialize in real-time. The requirement to modify operating plans should be deleted and reinstituted as appropriate when intra-day analysis exists. Protocol Language approved with 4 yes, 2 abstentions (KCPL and ETEC) and 1 no vote (OMPA). Tariff Language approved with 8 yes, 2 Abstentions (Calpine and Redbud). Name Company Original Sponsor Terri Eaton Xcel Energy Comment Author Comments Received Comment Description PRR128_Recommendation_Report Page 171 of of 38 5

12 PRR Recommendation Report Proposed Protocol Language Revision Market Infeasibility If SPP s analysis projects a system constraint that cannot be resolved through redispatch of Dispatchable Resources, SPP will run a second infeasibility analysis that simulates potential impacts that a TLR may have on the constraint. To simulate TLR SPP will, for the purposes of this study only, remove external schedules and change all self-dispatched Resources as Dispatchable Resources. SPP will post a notification, via the SPP OASIS website or Application Program Interface (API), identifying the projected constraint and that TLR may be necessary to resolve the issues. This notification, provided on the SPP OASIS or Application Program Interface (API), will include the expected constraint, and that TLR may be necessary. SPP shall notify the Market Participant s host Balancing Authority of that analysis. If the constraint in the above analysis is not resolved, SPP will post a notification on the API identifying the projected constraint and that the set of Resource Plans submitted for the study period are not feasible. The affected Market Participant shall mitigate the deliverability issue by modifying its Resource Plan and/or schedules in such a way that it can obtain its relief responsibility on the constraint and serve its Energy Obligation. The Market Participant shall make the appropriate modifications by 1700 prior to the OD for any deliverability issue revealed by the daily study. SPP will review those changes by 1800 day prior. The Market Participant shall make appropriate modifications by 45 minutes prior to the OH for any analyses performed during the current OD. SPP shall keep the Market Participant s host Balancing Authority notified of any such changes. To determine the relief responsibility for those Market Participants that impact the constraint, SPP shall first determine the impacts of the Market Participant s Resources supplying its Load (GLDF) and any associated interchange schedules (TDF). If the Market Participant does not have sufficient Resources to supply its Load and interchange schedules, SPP will then determine the impact of the marginal Resource to be dispatched by the Market to supply that Market Participant s obligation (GLDF) and add that impact to the impacts determined in the previous step. The relief responsibility assigned to a Market Participant is then its share of total relief needed on the constraint based on the ratio of its impacts to the total impacts for all Market Participants. For the determination of responsibilities only those Market Participants with positive impacts will be included. PRR128_Recommendation_Report Page 182 of of 38 5

13 PRR Recommendation Report If the Market Participant who has received notification of a deliverability issue, via the SPP OASIS website or Application Program Interface (API), fails to provide an acceptable change, SPP will notify the Market Participant, the Balancing Authority wherein the Market Participant s Load resides, and provide an after-the-fact report to FERC. If the Market Participant fails to provide an acceptable change, the Market Participant will be subject to interruption of Load and/or manual deployment instructions in real-time and/or other action as necessary. Tariff Language Changes Between 1300 and 1500 Central Prevailing Time on the day prior to the Operating Day, the Transmission Provider shall perform a review of the operating capacity scheduled in each Market Participant s Resource Plan. This review shall include an assessment of the total operating capacity scheduled in each hour of the next Operating Day and a simultaneous feasibility study to ensure that such operating capacity is deliverable in each hour of the next Operating Day. (a) Supply Adequacy Analysis. The inputs to the supply adequacy analyses shall be the load forecasts developed pursuant to Section 2.1 and submitted under Section 2.2, the Resource Plans submitted pursuant to Section 2.2 the energy obligations calculated under Section 2.2 and Ancillary Service Plans submitted pursuant to Section 2.3. The objective of performing the supply adequacy analysis is to ensure there is sufficient operating capacity scheduled so that the Transmission Provider may operate the system reliably to meet the load forecast. For each hour, the Transmission Provider shall determine if each Market Participant s energy obligation as set forth in Section 2.2 is: (i) less than the aggregate of the Economic Maximum Limits; and (ii) greater than the aggregate of the Economic Minimum Limits submitted in its Resource Plan. Similarly, for each Balancing Authority Area, the Transmission Provider shall determine if the Balancing Authority s energy obligation set forth in Section 2.2 is: (i) less than the aggregate of the Economic Maximum Limits; and (ii) greater than the aggregate of the Economic Minimum Limits submitted in all Market Participant Resource Plans in that area. If the Transmission Provider determines there is an Energy Obligation Deficiency or Energy Obligation Excess in any hour of the next Operating Day within a Balancing Authority Area, the Transmission Provider shall immediately notify those Market Participants within that Balancing Authority Area that have an Energy Obligation Deficiency or Energy Obligation Excess, as applicable, in that hour. Such Market Participant shall correct the deficiency or excess and resubmit revised plans and/or schedules to the Transmission Provider by 1700 on the day prior to the Operating Day. PRR128_Recommendation_Report Page 193 of of 38 5

14 PRR Recommendation Report (b) Simultaneous Feasibility Analysis (i) (ii) (iii) The inputs to the simultaneous feasibility analyses shall be the load forecasts developed pursuant to Section 2.1, the Resource Plans submitted pursuant to Section 2.2, including any applicable Energy Schedules, Offer Curves submitted pursuant to Section 2.5 and Ancillary Service Plans submitted pursuant to Section 2.3. The simultaneous feasibility analysis determines the impacts of single transmission facility contingencies on a set of monitored transmission facilities. To verify project on a day-ahead basis that the submitted Resource Plans and applicable Energy Schedules can be implemented reliably, the Transmission Provider shall determine if all constraints identified in the simultaneous feasibility analysis can be resolved through; (i) the simulated dispatch of Dispatchable Resources only; and (ii) simulation of potential impacts that a TLR may have on the constraint as described in the Market Protocols. If the day ahead analysis indicates that such constraints might not be capable of being resolved in real time by market redispatchcan be resolved, the Transmission Provider shall post a notification on its website identifying the projected constraint and that TLR may be necessary to resolve the issues in Real-Time. If the Transmission Provider determines through the simultaneous feasibility analysis that the submitted Resource Plans cannot be implemented reliably, the Transmission Provider shall immediately notify the Market Participant and the Market Participant shall modify its Resource Plan and resubmit such Resource Plan affected Market Participants that their plans are infeasible. The Transmission Provider shall determine each affected Market Participant s responsibility for resolving the infeasibility in accordance with the Market Protocols. Such Market Participants shall revise and resubmit their plans to the Transmission Provider. by 1700 on the day prior to the Operating Day To the extent the revised plans do not address the Energy Obligation Deficiency or the Energy Obligation Excess condition within a Balancing Authority or the infeasibility, the Transmission Provider may: (a) (b) (c) direct a Market Participant with an Energy Obligation Deficiency within the applicable Balancing Authority Area to commit additional Resources to correct the Energy Obligation Deficiency; or direct a Market Participant with an Energy Obligation Excess within the applicable Balancing Authority Area to de-commit a Resource to correct the Energy Obligation Excess; or direct the applicable Market Participants to commit or de-commit Resources to alleviate constraint violations that have not been addressed within the applicable Market Participants plans. PRR128_Recommendation_Report Page 204 of of 38 5

15 PRR Recommendation Report If a Market Participant fails to follow the Transmission Providers instructions as described in Sections 2.4.3(a) and, 2.4.3(b) and 2.4.3(c), and such action causes an Emergency Condition during the Real-Time Period, the Transmission Provider shall submit a report of the Market Participant s actions to the Commission. PRR128_Recommendation_Report Page 215 of of 38 5

16 Southwest Power Pool, Inc. REGIONAL TARIFF WORKING GROUP Recommendation to the Markets & Operations Policy Committee December 1, 2006 Organizational Roster The following members represent the Regional Tariff Working Group: AEP-West Arkansas Electric Cooperative Corp. Calpine Energy Services East Texas Electric Cooperative Empire District Electric Co. Kansas City Power & Light Kansas Electric Power Cooperative Lafayette Utilities System Midwest Energy Missouri Public Service Commission OG+E Electric Services Oklahoma Municipal Power Redbud Energy LP Southwest Power Pool Southwestern Public Service Co. Tenaska Power Services Co. Westar Energy Western Farmers Electric Mr. Robert Pennybaker Mr. Ricky Bittle Mr. Jason Atwood Mr. David Brian Mr. Bary Warren Mr. Charles Locke Mr. Robert Bowser Mr. Ron Gary Mr. Bill Dowling Mr. Mike Proctor Mr. David Kays Mr. Gene Anderson Mr. Rob Janssen Mr. Pat Bourne Mr. Bernard Liu Mr. Mark Foreman Mr. Dennis Reed Mr. Mitchell Williams The following stakeholders participated in group discussions: AEP-West AEP-West AEP-West Arkansas Electric Cooperative Corp. Arkansas Electric Cooperative Corp. Arkansas Public Service Commission Calpine Energy Services Calpine Energy Services East Texas Electric Cooperative Empire District Electric Co. Kansas City Power & Light Kansas Corporation Commission Kansas Corporation Commission Kansas Electric Power Cooperative Lafayette Utilities System Midwest Energy Missouri Public Service Commission Mr. Dennis Bethel Mr. Robert Pennybaker Mr. Bob Tumilty Mr. Ricky Bittle Mr. Robert Shields Mr. Richard House Mr. James Stanton Mr. Jason Atwood Mr. David Brian Mr. Bary Warren Mr. Charles Locke Mr. Larry Holloway Mr. Tom DeBaun Mr. Robert Bowser Mr. Ron Gary Mr. Bill Dowling Mr. Mike Proctor Page 22 of 38

17 Missouri Public Service Commission Occidental Energy Ventures OG+E Electric Services Oklahoma Municipal Power Authority Southwestern Power Administration Southwest Power Pool Southwest Power Pool Southwest Power Pool Southwestern Public Service Co. Southwestern Public Service Co Southwestern Public Service Co Tenaska Power Services Co. Westar Energy Westar Energy Western Farmers Electric Golden Spread Electric Coop. Mr. Greg Meyer Mr. Tim Soles Mr. David Kays Mr. Gene Anderson Ms. Tracey Stewart Mr. Les Dillahunty Mr. Pat Bourne Mr. Mike Small Mr. Bernard Liu Mr. Tim Woolley Ms. Terri Eaton Mr. Mark Foreman Mr. Shah Hossain Mr. Dennis Reed Mr. Mitchell Williams Mr. Michael Wise Background Tariff Schedule 2 In its September 26, 2006 order in the Calpine reactive rate matter (ER03-765), the FERC directed SPP to compensate all generators including independent power producers, on a comparable basis for the provision of reactive power. Thus FERC has required that SPP replace its existing Schedule 2 with a revised Schedule 2 that provides compensation for all generators. This proposed revised Tariff Schedule 2 (Reactive Supply and Voltage Control from Generation Sources Service) provides for such compensation. It is designed to fully supersede the currently effective Schedule 2 and comply with the FERC order. Analysis Tariff Schedule 2 At its meeting on November 2, 2006, the RTWG approved the proposed Schedule 2 by a vote of ten in favor, two opposed and one abstention. The vote to approve was subject to the RTWG s opportunity to review the economic impact of the proposed changes. Calpine and Redbud opposed the compensation provisions since they did not provide compensation in an amount equal to their calculated reactive revenue requirements. Proposed Tariff Schedule 2 is designed to compensate all qualified generators for reactive power produced or absorbed outside a specified dead-band. Its provisions apply equally to generation assets of Transmission Owners and other generation owners, including independent power producers. To be recognized as a qualified generator, the owner of such generator must meet the specific general and technical requirements specified in Section II of the schedule. The dead-band is a contiguous hourly power factor range of 0.95 lead or lag. Compensation due each generator will be based on the MVArh produced outside the dead-band during the previous year at a stated proxy reactive compensation rate. Such compensation requirement will be calculated for all qualifying generators in each zone and collected from both Network and Point-To-Point transmission service customers on a zonal basis. Any over or under collection of compensation due to the qualified generators will be trued-up. This compensation construct satisfies the requirements of the Calpine order. It provides comparable compensation to all reactive power providers and permits any qualified provider connected to the Transmission System to participate in the sale of reactive power. Its provisions are in accord with 2 Page 23 of 38

18 established FERC policy that provides that reactive power provision inside a generator s established power factor range should be provided by the generator without compensation. Recommendation The RTWG recommends that the MOPC approve proposed Tariff Schedule 2, subject to the RTWG s review of the economic impact of the proposed schedule. Approved: Regional Tariff Working Group November 2, 2006 Action Requested: Approval of the proposed Schedule 2, subject to the RTWG s review of the economic impact of its provisions. Attachments: Attached Proposed Tariff Schedule 2 3 Page 24 of 38

19 I. GENERAL RTWG Proposed Tariff Schedule SCHEDULE 2 Reactive Supply and Voltage Control from Generation Sources Service 1 Definitions (These definitions are to be used in this Schedule 2 only; to the extent of a conflict between these definitions and other definitions in the Tariff, these definitions control in the interpretation of this Schedule 2; other capitalized terms are defined elsewhere in this Tariff) 1.1 Dead Band (DB): A contiguous range of Power Factor operation where an hourly PF is greater than or equal to 0.95 (lead or lag). 1.2 Point of Interconnection (POI): The location where the generator connects to the Transmission System. 1.3 Power Factor (PF): The power factor of a QG as measured or determined by the integrated hourly MW and MVAr values at its POI. 1.4 Qualified Generator (QG): A generator, or a single generator that is part of a group of generators at a single Point of Receipt, that has been recognized by the Transmission Provider as meeting the criteria specified in Section II to receive compensation under this Schedule Reactive Compensation (RC): The amount of compensation a QG receives in a year based upon MVArhs produced or absorbed outside the DB by the QG. 1.6 Reactive Compensation Rate (RCR): The amount per MVArh paid to a QG, for generating reactive power outside the DB. 1.7 Through and Out Reactive Revenue (T&O Reactive Revenue): The amount of reactive power revenue allocated to a Zone each year that was collected by the Transmission Provider from Through and Out transactions. 1.8 Zonal Reactive Compensation (ZRC): The annual sum of the RC for all QGs in the pricing zone. 1.9 True-up Revenue: The difference between the total zonal reactive revenue collected under the provisions of this Schedule 2 and the total payments to all QG s, within the Zone, from the previous calendar year. 1 Page 25 of 38

20 RTWG Proposed Tariff Schedule Zonal Average Demand: The average of a zone s monthly transmission peaks for the previous calendar year Zone: SPP pricing zone as defined in the SPP OATT. 2 Page 26 of 38

21 2 Purpose RTWG Proposed Tariff Schedule In order to maintain Transmission System voltages within acceptable limits, generation facilities connected to the Transmission System are operated to produce (or absorb) reactive power. Reactive Supply and Voltage Control from Generation Sources Service (Reactive Supply) must be provided to support each transaction on the Transmission System. The amount of Reactive Supply required in real time to maintain Transmission System voltages within limits that are generally accepted in the region and consistently adhered to by the Transmission Provider will vary with conditions on the Transmission System. Generators operating within a range of 0.95 leading to 0.95 lagging PF will not receive compensation for supplying such reactive power. Generators meeting the requirements of this Schedule 2 will be compensated for producing reactive power outside the DB when such operation is at the direction of the Transmission Provider or local Balancing Authority. This Schedule 2 provides the criteria specifying which generators qualify to receive compensation for reactive power and sets out the rates and charges necessary to comparably compensate all QGs for such operation. II. QUALIFIED GENERATOR REQUIREMENTS A. General: All existing generation owners eligible to collect charges for Reactive Supply for generators connected to the Transmission System under a cost-based rate schedule on file with the Commission as of October 1, 2006, are deemed to have met the technical requirements of Section II.B and therefore are QGs. In order to receive compensation under this Schedule 2 during the first calendar year of its applicability, all other owners of generation must apply to the Transmission Provider for QG status and provide the necessary operating data to the Transmission Provider by no later than 30 days following 3 Page 27 of 38

22 RTWG Proposed Tariff Schedule the approval of this Schedule 2 by the Commission. Thereafter, the Transmission Provider shall recognize a new QG throughout the year if the new generator meets the requirements set out in Section II.B; and the new QG will start receiving payments in the following calendar year, consistent with Section III. The Transmission Provider shall have the right to remove the QG status of any generation resource that fails to meet any requirements of Section II.B. B. Technical: 1. Each QG shall designate the entity that is to receive dispatch instructions and the entity to receive compensation. 2. The generation resource must be able to produce reactive power outside the Dead Band at its Point of Interconnection with the Transmission System. 3. Each QG shall maintain the capability to provide MWh, MVArh and voltage data, by such means of transmittal, at such intervals and at such accuracy level as SPP shall require. 4. The generation resource must be able to follow a voltage schedule and respond to dispatch instructions from the Transmission Provider and/or the local Balancing Authority. III. RATES, CHARGES, AND REVENUE DISTRIBUTION Each January, the Transmission Provider shall calculate a rate for each Zone to be paid by all load within the Zone for Reactive Supply. Such rate will be based upon operating data collected by the Transmission Provider from the previous calendar year as well as data related to QGs recognized during such year. The revenue collected under this 4 Page 28 of 38

23 RTWG Proposed Tariff Schedule Schedule 2 is based upon the rates charged to Transmission Customers and shall represent a pass through of costs, based on the ZRC calculated in Section III.B. The Transmission Provider shall pay each Qualified Generator based on the calculations specified in Section III.B. After the Transmission Provider has completed the annual recalculation of the rates and payments in this section, it shall post on the OASIS (a) compensation to each QG that will be effective for the upcoming calendar year and (b) the updated rates to be charged Transmission Customers for service under this Schedule 2. For the initial calculation of the QG compensation and rates under this schedule, the Transmission Provider shall calculate the QG compensation and rates by no later than 60 days following the approval of this Schedule 2 by the Commission. The results of the calculations shall become effective on the first day of the first calendar month following the completion of the rate calculations. The Transmission Provider shall post on the OASIS the zonal rates and effective date of the new rates. A. Reactive Compensation Rate: The RCR shall be based on the cost of reactive power production from recently constructed generators so as to reflect the upper end of such costs. The RCR shall be $2.26 per MVArh. The Transmission Provider may periodically review the RCR to determine whether it remains at or near the upper end of a reasonable range of cost of producing reactive power by generators recently connected to the Transmission System. B. Qualified Generator Compensation The compensation paid to QGs each year will be based on the calculations as set forth below. 5 Page 29 of 38

24 RTWG Proposed Tariff Schedule Determine the integrated hourly values for real and reactive power generated by each Qualifying Generator for the previous calendar year. 2. Calculate the Reactive Power Outside the Dead Band (RPOD). For each hour of the previous year, calculate the amount of Reactive Power inside the Dead Band (in MVArh) that the QG would have had to produce or absorb to maintain a PF of 0.95 at its actual real power output level (RPID). Then subtract the absolute value of the RPID from the absolute value of the actual reactive power output from the QG for that hour (in MVArh). If the absolute value of RPID is greater than the absolute value of the actual reactive power output of the QG, then the RPOD for that hour is zero. The annual RPOD is the sum of the hourly RPOD calculations for each QG. 3. Calculate the total compensation that the owner of each QG will receive for the next calendar year (RC) by multiplying the QG s annual RPOD, times the RCR. C. Calculation of Rates RC = RCR * RPOD annual The rates paid by Transmission Customers will be based on the calculations set forth below. 1. Calculate the amount of T&O Reactive Revenue allocated to each Zone by taking the total amount of revenue generated by this Schedule 2 from Through and Out transactions collected in the previous year and allocate it on a pro-rata share based on the previous year s ZRC. 2. Calculate the True-up Revenue for each zone by subtracting the amount of revenue received by the Transmission Provider from the zonal customers 6 Page 30 of 38

25 RTWG Proposed Tariff Schedule during the previous year from the total amount of compensation paid to the zonal QGs the previous year. 3. Calculate the total amount of revenue to be collected for the upcoming year by zone, by summing the RC for each QG by zone plus the True-up Revenue from the previous year less the T&O Reactive Revenue. ZRC = Σ n=1 to x (RC) + True-up revenue T&O Reactive Revenue; where: x=total number of QGs in the Zone 4. Calculate the Schedule 2 Rates, for each Zone, as shown below. a. Annual Rate ($/MW/Yr) = ZRC / (Zonal Average Demand) b. Monthly Rate ($/MW/Mo) = Annual Rate / 12 c. Weekly Rate ($/MW/Wk) = Annual Rate / 52 d. Daily Off-Peak Rate ($/MW/Day) = Weekly Rate / 7 e. Daily On-Peak Rate ($/MW/Day) = Weekly Rate / 5 f. Hourly Off-Peak Rate ($/MW/Hr) = Daily Off-Peak Rate / 24 g. Hourly On-Peak Rate ($/MW/Hr) = Daily On-Peak Rate / 16 The total charge in any day, pursuant to an hourly service reservation, shall not exceed the applicable rate for daily service specified above for the applicable Zone, times the highest amount of hourly service reserved in any hour during such day. In addition, the total charge in any week pursuant to a reservation for hourly or daily service shall not exceed the rate for weekly service specified above for the applicable Zone, times the highest amount of hourly or daily service reserved in any hour or day during such week. 7 Page 31 of 38

26 RTWG Proposed Tariff Schedule On-Peak and Off Peak Off-Peak days shall be Saturdays and Sundays and all NERC holidays. All other days shall be On-Peak. All hours during Off-Peak days shall be Off-Peak. On-Peak hours during On-Peak days shall be all hours from HE 0700 through HE 2200 Central Prevailing Time. All other hours during On-Peak days shall be Off-Peak. 5. For the purposes of determining the charge applicable to transactions under this Tariff, the transaction will be charged based on the applicable zonal rate where the load is physically located. 6. If the service is a Through and Out transaction, the transaction will be charged based on the simple average of all zonal rates for the applicable period of service. D. Collection of Charges and Distribution of Revenues 1. All load shall pay the Transmission Provider a charge for Reactive Supply determined by multiplying the applicable rate as calculated in Section III.B by the Reserved Capacity for the Transmission Customer taking Point-To-Point Transmission Service or the Network Customer s and non-rate terms and conditions customer s average coincident peak load for the prior calendar year. 2. The Transmission Provider shall distribute to each QG owner 1/12 th of its RC each month as determined under this Schedule 2. 8 Page 32 of 38

27 E. Joint Owned Units RTWG Proposed Tariff Schedule The Transmission Provider will compensate the entity designated in II.B.1 for a jointly owned QG. The Transmission Provider is not responsible for disbursing revenue to other owners. F. Multiple Generators Behind a Common Meter If more than one generator exists behind a single meter, the Transmission Provider must individually certify all the generators behind the meter as QGs. Compensation will be handled in the same way as an owner with multiple units in the same zone. IV. QUALIFIED GENERATOR STATUS A. Re-Evaluation of Qualified Generator Status 1. If a QG fails to comply with the Transmission Provider s or Balancing Authority s voltage control requirements three or more times in a calendar month, or six or more times in the preceding twelve month period, for reasons other than planned or unscheduled outages, the Transmission Provider shall determine whether the Generation Resource should continue to be a QG based on the criteria established in Section II.B of this Schedule In making a determination of whether a Generation Resource should continue to be a QG, the Transmission Provider will evaluate, among other factors, whether the Generation Resource was operated consistently with its design characteristics, if the QG responded in accordance with other agreements and whether system conditions prevented it from responding as required by the Balancing Authority or Transmission Provider. 9 Page 33 of 38

28 RTWG Proposed Tariff Schedule If the Transmission Provider determines that the generator should not continue to be a QG, the Transmission Provider shall notify the owner and stop providing reactive compensation to such generator owner. B. Regaining Qualified Generator status: If a generator has had its status as a QG removed by the Transmission Provider, such generator may be reinstated to receive reactive compensation six (6) billing months after disqualification. If the owner of the generator desires to be reinstated, it must make application for such reinstatement to the Transmission Provider and demonstrate that the cause(s) for the disqualification has been remedied. The Transmission Provider shall waive the six month period and immediately reinstate the QG status if it determines that such status was erroneously removed. 10 Page 34 of 38

29 Proposed Changes to Schedule 2 MOPC Conference Call December 1, What Will be Covered I. Brief Review of Reactive Power and the existing Schedule 2 II. Go over the proposed Changes III. Look at the impact of implementing the Changes IV. Request Acceptance of the Changes 1