Southwest Power Pool STRATEGIC PLANNING TASK FORCE May … · 2019. 2. 8. · MINUTES NO. 6...

MINUTES NO. 6 Southwest Power Pool

STRATEGIC PLANNING TASK FORCE May 28, 2003 Meeting Minutes SPP Offices – Little Rock, AR

Agenda Item 1& 2 – Call to Order & Introductions, Approval of Minutes Co-Chair, Dick Dixon (WESTAR) called the meeting of the SPTF to order at 8:04 a.m. (Agenda – Attachment 1). Other SPTF members in attendance were Co-Chair Richard Spring (KCPL), Mel Perkins (OKGE), Ricky Bittle (AREC), Michael Desselle (AEP), David Christiano (SPRM), Michael Gildea (DENA), Trudy Harper (Tenaska), and John Marschewski (SPP). SPP Staff in attendance included Nick Brown, Carl Monroe and Tom Dunn. Guests participating in the meeting included Keith Sugg (AREC), Jim Sherwood (SWPA), David Lemmons (Xcel), and Richard House (APSC). John Marschewski moved that the minutes of the May 16, 2003 teleconference meeting be approved as corrected. Mel Perkins seconded this motion, which passed unopposed. Agenda Item 3 – Member Outreach / Regional Coordination / Dialogue w/ States Nick Brown stated that participation in the weekly calls between the state regulators on SPP’s future were going very well and participation was increasing. Nick stated that interest is growing in the issue of transmission expansion and its relationship to congestion management methodologies under consideration and that this issue needed to be interwoven into the agenda for the market structure technical conference with the states scheduled for June 23 in Kansas City. Agenda Item 4 – Market Implementation Plan Richard Spring welcomed Keith Sugg, acting chair of the Market Settlement Working Group and Congestion Management Systems Working Group. Richard stated that these groups were, pursuant to the strategic plan approved by the Board of Directors, directed to provide a detailed plan for the implementation of the remaining functions of a RTO that SPP was not already providing; 1) an energy imbalance market, 2) market monitoring, and 3) market-based congestion management. Keith stated that the groups had met twice in person and three times by conference call with very good participation in all the meetings (Markets Slides – Attachment 2). Keith then presented an implementation plan consistent with the strategic plan’s guiding principle, in that it is an evolutionary approach. SPP would begin providing settlement of imbalance energy that is now performed by the member companies, but using tariff rates. A second increment would be to enhance the reliability data needed by the market and reliability operations of SPP. A third increment would be to have a market determine the rate to settle imbalance energy and would include market monitoring and market power mitigation as needed (Market Implementation Plan Report – Attachment 3). Following this first phase of three increments, SPP would implement market-based congestion management and ancillary services developed in coordination with SPP state regulatory bodies.

SPP Strategic Planning Task Force Minutes May 28, 2003 Meeting

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Following additional discussion, Michael Desselle motioned and Mel Perkins seconded that the SPTF adopt the proposed plan for recommendation to the Board of Directors. This motion passed without opposition. Agenda Item 11 – Nominating Task Force Report David Christiano reported that the Nominating Task Force was seeking recommendations from members to fill a vacant non-stakeholder director position. He also reported that, due to J.M. Shafer’s departure from Western Farmers, a transmission owner and also vice-chair of the board positions were opening. He solicited recommendations from the SPTF. Agenda Item 5 – Organization Structure Review Nick Brown discussed SPP’s organizational group structure and, based on limited comments on a previous draft of a Strategic Planning Committee scope and a recommendation report, he distributed second drafts of the documents (Organizational Structure Recommendation – Attachment 4). Richard Spring motioned and Michael Desselle seconded that the SPC scope be approved. Following discussion, this motion was withdrawn to allow modifications. Following additional discussion, Michael Desselle motioned and Dick Dixon seconded that the SPC scope, as modified during discussion, be approved for recommendation to the Board of Directors (SPC Scope – Attachment 5). This motion passed without opposition. The SPTF agreed to recommend to the Board of Directors that the current SPTF roster be grandfathered as the initial roster of the Strategic Planning Committee. Agenda Items 6 – Cost Allocation Approach & Budget Modifications Tom Dunn then discussed the new approach to SPP’s cost allocation - a manner consistent with how they would be billed under the regional transmission service tariff, whether or not their bundled retail load were actually placed under the regional tariff for service. The SPTF then discussed implementation timing and agreed to recommend September 1 to the Board of Directors, subject to discussion with the Finance Working Group. Nick Brown stated that he and Tom Dunn had met with representatives of Principle Financial, holder of SPP’s $25M note, on the assessment modification. Nick stated that a covenant in SPP’s note prohibits modification to SPP’s assessment formula without Principle’s consent. Nick stated that, subject to seeing final bylaws language, Principle was comfortable with the proposed modification. Nick then distributed draft bylaws modification on the assessment process for discussion (Draft Bylaws Modifications on Assessments – Attachment 6). The SPTF asked for modifications to capture the concept of levelizing monthly assessments and clarification on tariff billing units.

SPP Strategic Planning Task Force Minutes May 28, 2003 Meeting

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Neither Tom nor Nick had additional information on the proposed 2003 budget modifications that were to be discussed by the Finance Working Group on Friday. Agenda Item 7 – Update on RTWG Activities Ricky Bittle provided an update on activities and plans of the RTWG (RTWG Report – Attachment 7). Agenda Items 8, 9 and 10 – Agendas for Future Meetings The SPTF then discussed items for upcoming meetings and directed Staff to prepare agendas appropriately for the following meetings:

• Friday, June 6, 2003 from 7-9 a.m. in Atlanta with FERC Commissioners Pat Wood and William Massey;

• Tuesday & Wednesday, June 10-11 from 2 until 6 p.m. and 8 a.m. until 3 p.m. respectively in St. Louis, MO; and

• Monday, June 23, from 1 until 4 p.m. in Kansas City, MO – Imbalance and Congestion Management Seminar with States.

Agenda Item 12 – Action Items

• Nick Brown will distribute meeting minutes by Monday, June 2. • Tom Dunn will work with members to fine-tune the assessment estimates per the

recommended methodology by June 10. • The RTWG will consider tariff modifications necessary to implement the

recommended assessment methodology by June 24. • Tom Dunn will develop recommended changes to SPP’s membership agreement

to clarify financial obligations of members upon departing. • Nick Brown will redline compare SPP’s existing membership agreement and

bylaws with those included in SPP’s 2001 RTO application filing and distribute to the SPTF prior to June 10.

• Nick Brown will draft a SPTF report to the Board of Directors including the recommendations on organizational changes, assessment changes and market implementation for distribution to the SPTF prior to June 10.

Agenda Item 13 – Adjournment With no further business, Dick Dixon thanked everyone for participating and adjourned the meeting at 3:41 p.m. Respectfully Submitted, Nicholas A. Brown

Southwest Power Pool STRATEGIC PLANNING TASK FORCE MEETING

Wednesday, May 28, 2003 SPP Offices, 9th Floor Conference Room – Little Rock, AR

8 a.m. until 5 p.m.

- A G E N D A - 1. Call to Order & Introductions .........................................................Richard Spring/Dick Dixon 2. Approval of 5/16/03 Meeting Minutes ............................................Richard Spring/Dick Dixon 3. Member Outreach / Regional Coordination / State Dialogue Update ..................................All 4. Market Implementation Plan..................................................................................Keith Sugg 5. Organization Structure Review / Strategic Planning Committee Scope ................ Nick Brown 6. Cost Allocation Approach & Budget Report ........................................................... Tom Dunn 7. Update on RTWG Activities .................................................................................. Ricky Bittle 8. Agenda for June 6 Meeting w/ FERC Commissioners ...................Richard Spring/Dick Dixon 9. Agenda for June 10-11 SPTF Meeting .........................................Richard Spring/Dick Dixon 10. Agenda for June 23 Conference w/ States ......................................................... Nick Brown 11. Nominating Task Force Report................................................................... David Christiano 12. Review of Action Items ....................................................................................... Nick Brown 13. Adjournment................................................................................Richard Spring/Dick Dixon

1

CMSWG / MSWG Presentation to

SPTF

May 28, 2003Keith Sugg

CMSWG / MSWG Meeting History:April 29 – Kansas City

� Organizational meeting to develop framework and process.

� Reviewed history.� Directed SPP staff to develop and distribute draft for

comment.

May 14, 15 – St Louis� Review SPP staff draft recommendation, analysis and

discussion documentation.

May 22 – teleconference� Respond to feedback from SPTF regarding possibility of

earlier implementation than spring ’05.� Developed consensus on new, improved option.

May 27 – teleconference� Reviewed and edited final document.� Send to SPTF.

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Important Themes

1. Consistent emphasis on a member-driven approach.

2. Phased implementation.a. Real Time Imbalanceb. Market Based Congestion Managementc. Possible Ancillary Services market

3. Market Monitoring and Market Power Mitigation needed at market opening

Important Themes, cont.

4. Serious concerns about the ability of market participants to adequately prepare –especially in some of the shorter timeframes.

5. Serious concern about the ability to get meaningful state input and agreement in a short timeframe.

6. Level of readiness determines timeline. Timeline does not determine level of readiness.

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Important Themes, cont.

7. Recognition that any option or path chosen will require a significant commitment of resources from all parties.

Range of Options

1. Use 2001 system almost as-is.2. Use other pre-existing system3. Start from scratch – new rules.4. Use 2001 system with changes, implement

phase 1 in spring ‘055. Use 2001 system with changes, incremental

implementation provides opportunity for corrections, implement phase 1 in fall ’04.

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Recommendation1. Start with existing 2001 system2. Detailed design of Phase 1 (Real Time

Imbalance ) and overall design of other Phases.

3. Ability to modify implementation of Phase 1 if later phase market design dictates

Recommendation, cont.4. Roll out Phase 1 in three steps.

1. Settle imbalance at tariff rates1. Calculated by SPP2. Feb ’04 target

2. SPP provided Net Scheduled Interchange values

1. April ’04 target3. Offer-based energy imbalance market

1. November ’04 target

5

Recommendation, cont.

5. Implement Phase 2 (Market based Congestion Management) by November ‘05.

6. Study Phase 3 (Ancillary Services. Market) implementation in ‘06

Advantages1. Builds on past experience (MISO) and investment (2001 system)2. Incremental implementation of phase 1 allows maximum flexibility� Breaks development, testing and training effort into

smaller blocks� Multiple schedule milestones increase likelihood that

systems and participants will be ready.� Reduces the “culture shock” of participants by gradually

changing the business processes.� Both participants and SPP have more time to validate the

processes and calculations.� State input and acceptance should be easier to secure

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Timeline and DetailsTimeline and DetailsTimeline and DetailsTimeline and Details

See chart and analysisFrom

Discussion paper

SPP Presentation

Recommendation of the

CMSWG/MSWGto the SPTF Keith Sugg

ChairmanMarket Settlement Working Group

RecommendationRecommendationRecommendationRecommendation

The CMSWG/MSWG recommends:� Option 5 with a three-phased approach be used

to implement Order 2000 compliant functions. The phases are (1) Real-time Balancing Market and Market Monitoring and Market Power Mitigation, (2) Market Based Congestion Management, and (3) Other Ancillary Services Market. It is further recommended that Phase 1 be implemented in an incremental approach with the full operational objective of November 2004; Phase 2 be fully operational by November 2005; and Phase 3 be analyzed for implementation during 2006.

Recommendation Recommendation Recommendation Recommendation (cont.)(cont.)(cont.)(cont.)

The CMSWG/MSWG recommends:

� The plan for implementation of Phase 1 and 2 is to have teams focused on evaluating the SPP 2001 Real-time Balancing Market design, commencing immediately, and developing a high-level design for all phases to determine the usability of the 2001 Market Design and the implementation timeline.



� The teams should be under the direction of a single Market Working Group to ensure consistency between the phases and to smoothly coordinate the evolution from one phase to another. The Market Working Group would be responsible for the overall design and implementation of market functions.



� A team pursues, with SPP staff, seams agreements with the border entities.


The implementation dates in this plan can be relied upon only to the extent that schedule milestones, established by a Market Working Group, are met. This requires commitment of resources for both participants and SPP to accomplish these tasks.

Option 5Option 5Option 5Option 5Begin with the prior system design developed by SPP

during 2001 and perform a detail design for Phase 1 and a high-level design for the other phases.

Changes in Phase 1 to support other phases will be incorporated with an objective of November 2004 implementation for Phase 1. Rollout of Phase 1 will be broken into three distinct increments: 1) Settlement of Imbalance at tariff filed rates of each Transmission Owner with an objective of February 2004; 2) Enhanced Reliability Data and Net Schedule Interchange with an objective of April 2004; and 3) Offer-based energy imbalance market resulting in the use of market-based rates for imbalance settlement, with an implementation objective of November 2004.

Implement other phases on an annual cycle basis thereafter.

TimelineTimelineTimelineTimeline

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July Aug DecNovOctSep Feb Mar JulyJunMayAprJan Aug DecNovOctSep

2005

Feb Mar MayAprJan

Market Design

Market Rules

SPP System

Systems

Hardware

Data

Market Monitoring andMarket Power Mitigation

ParticipantReadiness

Training

Technical Specifications

Market Trials

Regulatory Filings

Review & Finalize Phase I -Imbalance/Reliability Increment

Develop Overall Design for allPhases

Identify & Prioritize Enhancements

Develop & Test System

Design & ConfigureEnvironments

ConfirmApproach

Convert & PopulateData

Select Market Monitor and DefineRequirements Develop & Test Release Final

ImbalanceTraining

DefineRequirements

ReleaseInitial

ReleaseFinal

Participant System Dev/Test - Imbalance

Tariff Filings

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System Design and Test - Phase 2

System Issue Resolution

Develop Rules for Phase 2

Define Requirementsfor Phase 2

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Confirm Cost & Schedule1 Confirm Go-live2

Option 5

Tariff Filings

Participant System Dev/Test - Reliability

Participant SystemDevelopment/Test- Offer &

Dispatch22

Note: Requires both development and production environments

Review & Finalize Phase I - Real-time Imbalance Market Increment

ReliabilityTraining

Offer &DispatchTraining

Validation/Registration ofData

Contact SPPContact SPPContact SPPContact SPP

Southwest Power Pool, Inc. Phase 1 Order 2000 Description

Page 1 of 10

Table of Contents

Objective ......................................................................................................................................................2 Assumptions................................................................................................................................................2

Types of Markets .......................................................................................................................................2 Member/Customer/Regulatory Roles ........................................................................................................2 Design and Implementation .......................................................................................................................3 Additional Assumptions..............................................................................................................................3

Phase Definitions and Impacts ..................................................................................................................3 Implementation Phases .............................................................................................................................3 Phase 1 Participant Impacts ......................................................................................................................4 Phase 2 Participant Impacts ......................................................................................................................4 Phase 3 Participant Impacts ......................................................................................................................4

Options Considered ....................................................................................................................................4 Option 1: Enhance 2001 Market Design...................................................................................................4 Option 2: Utilize “Off the Shelf” Software..................................................................................................4 Option 3: Develop New Market Rules.......................................................................................................4 Option 4: High-level Design of ALL phases and Full Phase 1 Implementation April 2005.......................4 Option 5: High-level Design of ALL phases and Incremental Implementation of Phase 1 finishing November 2004 .........................................................................................................................................5

Option Analysis ...........................................................................................................................................5 Decision Drivers Table...............................................................................................................................6

Critical Path Activities.................................................................................................................................8 Schedule.......................................................................................................................................................8


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Objective Implement a real-time balancing market, market monitoring with market power mitigation, and market-based congestion management using a phased approach. Involve FERC and the state regulatory commissions throughout the process.

Assumptions The following are some general assumptions for the development of SPP Market Systems.

Types of Markets

The SPP Market System will be compliant with FERC Order 2000. Additional proposed requirements outlined in the FERC NOPR for Standard Market Design will be considered but not adopted unless approved by the stakeholder process in collaboration with the state regulatory commissions. SPP will implement a Real-time Energy Balancing Market as quickly as possible as the first phase of Market Operations. The Energy Balancing market will be implemented using physical transmission rights. SPP will have an independent market monitor established in conjunction with the RT Energy Balancing Market. The market monitoring activities will include market power mitigation. SPP will transition from a physical transmission rights market to a financial transmission rights market with Market-based Congestion Management as the second phase of its Market Operations. SPP will have an Ancillary Services market either as part of Phase 2 or Phase 3 of its Market Operations.

Member/Customer/Regulatory Roles

SPP members and customers desire to pursue a market and are willing and able to dedicate the resources (monetary, time and staff) to the design and implementation of a market. SPP Control areas will continue to exist and operate at least until a Regional Ancillary Services market is created. They will be responsible for Control Performance and Disturbance Control standards as well as sharing of operational data as they are today. Decisions on the Market Rules will be made through a stakeholder process. Stakeholders will actively participate in development of readiness and implementation initiatives. The state regulatory commissions are responsible for impacts to customers within their states. The state regulatory commissions of the states where SPP members serve customers will be invited to participate actively in the stakeholder process to evaluate and advise SPP with regards to impacts to customers. Participation in the offer-based dispatch SPP market is voluntary. All load serving entities and generation owners connected to the transmission systems of Transmission Owners that are signatories to the current SPP Regional OATT will be considered as the starting footprint for the SPP Market System. SPP may provide other entities Tariff Administration Services, Scheduling Services, and Reliability Authority services without requiring them to be a part of the Market System footprint.


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The SPP Market System must be designed to accommodate additional entities that may wish to join SPP. It must also accommodate the formation of Independent Transmission Companies.

Design and Implementation

The selection of implementation dates of the market phases should minimize testing, training and implementation in the summer months. This is in order to avoid additional risks to reliability, personnel unavailability, and potential price instability associated with the summer peak conditions. SPP must have significant market rules decisions developed prior to system design starting. System Requirement documents will be developed following the market rules. This is to minimize the pitfalls of trying to do both simultaneously and having to redesign significant aspects due to major Market Rules decisions. Third party contractors will be involved with the development of the SPP Market System. Transmission Service Billing and Market Settlement will be maintained separately.

Additional Assumptions

SPP recognizes that seams issues exist and will need to be resolved by market implementation. SPP will continue to participate in the MISO/PJM/SPP joint and common market forum and actively participate in seams resolution efforts with MISO, non-MISO MAPP members, Entergy, Associated Electric Cooperative, ERCOT and WECC to ensure a smooth transition to energy markets. The SPP Regional Tariff Working Group will have liaisons in this process to help facilitate incorporation of the market rules into the Regional OATT where required. SPP will build on prior knowledge gained from the development process for the initial SPP Market and the MISO/SPP market project. The stakeholder process will develop this market system from the top down utilizing the information from the previous two efforts and potentially concepts from other markets that have been enacted. Some new hardware will be required for the Market System. Some computer resources purchased for the previous project have been reformatted and deployed for other purposes in lieu of purchasing new equipment as needs in other departments have arisen requiring upgrades of outdated equipment or to provide necessary redundancy of other systems.

Phase Definitions and Impacts

Implementation Phases

Each of the options considered included a phased approach as listed below. Phase I - Real-Time Balancing Market with Market Monitoring and Market Power Mitigation Phase 2 - Market Based Congestion Management Phase 3 - Ancillary Services Market


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Phase 1 Participant Impacts

• Submit energy schedules that include native load. • Submit generator operating characteristics such as limits and ramp rates. • Receive and act on real-time NSI (net-scheduled interchange) from SPP. • Submit voluntary offers for the sale of generation. • Receive and act on real-time dispatch instructions from SPP.


• Subject to Market Rules decisions.


• Subject to Market Rules decisions.

Options Considered

Option 1: Enhance 2001 Market Design

Implement the market design and supporting systems developed by SPP during 2001, with only minor changes and the addition of market monitoring, in Spring 2004 for Phase 1. Implementing other phases on an annual cycle basis thereafter.

Option 2: Utilize “Off the Shelf” Software

Adopt “Off the Shelf” software for an implementation in Spring 2004 of Phase 1, modifying market rules to adhere to the capabilities of that solution. Implementing other phases on an annual cycle basis thereafter.

Option 3: Develop New Market Rules

Defer any implementation until Spring 2005 (Phase 1) and begin developing new market rules immediately. Implementing other phases on an annual cycle basis thereafter.

Option 4: High-level Design of ALL phases and Full Phase 1 Implementation April 2005

Begin with the system design developed by SPP during 2001 and perform a detail design for Phase 1 and high-level design for other phases. Changes in Phase 1 to support other phases will be incorporated with an objective of implementation by spring 2005. Implement other phases on an annual cycle basis thereafter.


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Option 5: High-level Design of ALL phases and Incremental Implementation of Phase 1 finishing November 2004

Begin with the prior market system design developed by SPP during 2001 and perform a detail design for Phase I and a high-level design for the other phases. Changes in Phase I to support other phases will be incorporated with an objective of November 2004 implementation for all of Phase I. Phase 1 will be broken down into three distinct increments: 1) Settlement of Imbalance at tariff filed rates of each Transmission Owner with an objective of February 2004, 2) Enhanced Reliability Data and Net Schedule Interchange with an objective of April 2004 and 3) Offer-based energy imbalance market resulting in the use of market-based rates for imbalance settlement with an implementation objective of November 2004. Implement other phases on an annual cycle basis thereafter.

Option Analysis Decision Drivers used in the evaluation were: Systems Costs; Schedule; Participant Impacts; Market Rule Flexibility; Market Participant experience, and relevance of the market system work in 2001. An additional driver discussed but deferred to the SPTF efforts is the impact of any decision in the State and Federal Regulatory environments. In all options, there is recognition that the highest risk factors are the participants’ system development and readiness efforts and regulatory buy-in. Without both of these, a market system could be built but would not become operational. As a result, the Group emphasizes that implementation dates are subject to change as a result of scheduled milestone reviews. The scheduled milestone reviews include resolution of issues, e.g. inadvertent handling amongst SPP Control Areas. This requires commitment of resources for both participants and SPP to accomplish these tasks. Option 1 is the most feasible option to achieve a Spring 2004 implementation. Use of Option 1 results in: (1) Knowledge from the MISO development efforts not being incorporated, (2) Risk of not having regulatory support, (3) Increased risk to participant readiness. Option 1 is not recommended for these reasons. Option 2 has a very restrictive timeline to implement by Spring 2004 and has a high risk for participant readiness and systems testing. It is improbable that an acceptable “off the shelf” product could be located within a reasonable timeframe because the “off the shelf” concept would require adoption of the underlying rules which may not meet SPP requirements. All prior work for the initial 2001 implementation would also be discarded, including the capital invested in that effort. Option 2 is not recommended for these reasons. Option 3 would discard all prior work, including the capital invested in that effort. The earliest possible start-up of Phase 1 of the market under this option would be Spring 2005 and there is a high risk associated withachieving this date. It does provide the most flexibility for making sure the system design provides for smooth transitions from one phase to the next. Option 3 is not recommended due to the improbability of achieving this timeline. Option 4 delays the start-up to Spring 2005 but by building on the prior work done in 2001 has a lower risk of meeting that timeline than option 3 while still providing most of the flexibility to make sure the Market Rules have gone through a thorough review. Starting in Spring 2005 also allows for all training and Market Trials to be conducted during the fall and winter off-peak time periods when resources are readily available. The later start date also allows more time to ensure regulatory buy-in. It does require a “big bang” implementation with all new functions starting at one time. Option 4 is not recommended due to the projected start date of Spring 2005 and the “big bang” implementation. Option 5 is an effort to implement along the lines of Option 4 but target a start date in Fall 2004 by further instituting the SPP guiding principle of “evolution not revolution”. Breaking the implementation of Phase I into three increments will allow participants and SPP staff to test and implement necessary infrastructure


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and data collection processes to support the market that have fewer design issues and “Market” impact while taking additional time to resolve any Market Rules issues regarding the offer submittal, centralized dispatch and market pricing. This also lowers the risk for participant and staff readiness by avoiding the “big bang” implementation that is inherent in each of the other four options and does not require the complete system to be available for market trials at one time. This targets part of the system to be tested and implemented prior to the Summer of 2004 reducing the amount of training and development efforts during the summer and early fall. Option 5 is recommended. The first increment will be for the settlement of imbalance, using tariff filed rates of each of the Transmission Owners. This increment, targeted for implementation in February 2004, will require the market settlements system, SPP scheduling system changes and after-the-fact meter data submission processes to be in place. The second increment, targeted for implementation in April 2004, will be an enhanced reliability implementation to collect the unit commitment and resource plan information through the market system and also send out the net scheduled interchange to control areas for incorporation into their systems. The final increment, with an implementation objective of November 2004, would be to roll out the submission of resource offers, centralized dispatch and use of market based pricing for imbalance settlement. Market trials and training would be split accordingly into smaller efforts to test each of the increments prior to implementation including a final “Market Trial” prior to implementation of the resource offers, centralized dispatch and market pricing for imbalance. The first increment will primarily affect settlements personnel and the commercial operations aspects of the market system with some impacts to scheduling. The second increment will primarily involve operations personnel and the data input or front-end aspects of the market operations system. The final increment will involve both operations and settlements to transition to the centralized dispatch and market based pricing for imbalance settlement. The market trial for the final increment would start in September 2004. Use of the incremental process does require development and production systems to be used on a parallel path. This may also result in some personnel issues due to part of the market system being implemented and other parts in development or testing.

Decision Drivers Table

Option 1 Option 2 Option 3 Option 4 Option 5

System Costs

Takes advantage of investment to-date (estimated increase in cost of $200-$500 K, could be more depending upon modifications.)

Likely more cost than Option 1; adoption of “Off the Shelf” would require additional integration efforts and costs; likely scraps prior investment.

More costly than Options 1 or 2 since totally new system build.

At least the same cost as Option 1; likely more costly due to modifications resulting from Phase 2 impacts.

Same costs as 4 Additionally Requires production and development systems operating in parallel, which may affect Participant costs.


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Schedule High schedule risk. More schedule risk than Option 1; 2004 implementation questionable.

2005 implementation at earliest.

Lower schedule risk given lengthened design time.

Lower schedule risk than option 1 to meet overall by Nov 2004 Greater risk than Option 4 but incremental implementation allows some additional design /development time and avoids “big bang” implementation.

Participant Impacts

Less resource time required for rules development/revision. Development start would be immediate. May have more immediate budgetary impact for that development.

Up front costs relative to market rules development. Development start would be delayed. Increases budgetary impact.

Greater resource commitment to development of rules. Development start would be delayed.

Greater resource commitment to development of rules. Easier budget management due to multi-year build. Development start would be immediate to delayed.

Higher resource commitment to develop rules faster but some Market issues have additional time. Higher resource commitment than Option 4 to get partial system ready by Spring. Personnel and systems must cover some implemented operations and some final development in parallel. Participants must budget for Spring Implementation items in 2003 Development still starts immediately.

Market Rules Flexibility

Allows minimal flexibility for modifications to design/rules and still meet schedule

No flexibility Flexible Flexible Less flexible than option 4 but does allow some additional time for significant “Market” issue resolution.


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Other Earliest start of participant market experience

Early start of participant market experience. Market design does not consider gains from 2001.

Later start of participant market experience. Market design does not consider gains from 2001.

Later start of participant market experience. Market design builds on 2001 effort and a plan for the future.

Earlier start of participant market experience than option 4 Market design still builds on 2001 effort and a plan for the future. Initial imbalance implementation will require review of SPP Tariff and individual Provider Tariffs for possible additional FERC filings.

Critical Path Activities Market Rule Development: Market Rules will be the primary requirements document for implementation of the market phases. As such, finalization of these market rules is crucial to providing an accurate estimate of schedule and cost and providing stable requirements for participant system development. Before finalization of market rules for each phase, a check against the overall market direction must be completed to minimize risks of significant changes in the following phases. Mitigation of risks in this area will include aligning specific market rule versions with specific software releases at agreed upon dates. Participant Readiness: Participants need to be prepared from an operational viewpoint and technical viewpoint. Operationally, participant staff will require proper and timely training in order to understand and develop their own business practices and business process changes. Technically, existing participant systems must be enhanced, and new systems must be designed and developed. Minimizing risk in the operational area will include phasing in training with two goals – Overall Market Objectives and Focused Objectives. Minimizing risk in the technical area will include early releases of technical requirements and incremental releases of data exchange requirements as a result of market rule versions. Regulatory Approval: Crucial to the implementation of each phase are regulatory approvals. In order to minimize the risk in this area, regulatory representatives will be included in the market rule development process.

Schedule

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20042003

July Aug DecNovOctSep Feb Mar JulyJunMayAprJan Aug DecNovOctSep

2005

Feb Mar MayAprJan

Market Design

Market Rules

SPP System

Systems

Hardware

Data

Market Monitoring andMarket Power Mitigation

ParticipantReadiness

Training

Technical Specifications

Market Trials

Regulatory Filings

Review & Finalize Phase I -Imbalance/Reliability Increment

Develop Overall Design for allPhases

Identify & Prioritize Enhancements

Develop & Test System

Design & ConfigureEnvironments

ConfirmApproach

Convert & PopulateData

Select Market Monitor and DefineRequirements Develop & Test Release Final

ImbalanceTraining

DefineRequirements

ReleaseInitial

ReleaseFinal

Participant System Dev/Test - Imbalance

Tariff Filings

MarketTrials

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System Design and Test - Phase 2

System Issue Resolution

Develop Rules for Phase 2

Define Requirementsfor Phase 2

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Confirm Cost & Schedule1 Confirm Go-live2

Option 5

Tariff Filings

Participant System Dev/Test - Reliability

Participant SystemDevelopment/Test- Offer &

Dispatch22

Note: Requires both development and production environments

Review & Finalize Phase I - Real-time Imbalance Market Increment

ReliabilityTraining

Offer &DispatchTraining

Validation/Registration ofData


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Southwest Power Pool BOARD OF DIRECTORS MEETING

June 24, 2003

Strategic Planning Task Force Recommendation SPP Organizational Group Structure

Background At its April 16, 2003 meeting, the SPP Board of Directors approved an initial Strategic Plan recommended by its Strategic Planning Task Force. This plan contained several recommendations regarding SPP’s administrative processes and specifically its organizational group structure. Two specific recommendations approved included:

• SPP should combine its Engineering & Operating Committee with its Commercial Practices Committee to have only one full representation committee reporting to the Board of Directors; and

• SPP should assess its working groups and task forces to ensure efficient and effective administration of SPP services.

These actions were assigned to the SPTF and senior staff with a target of developing more specific recommendations and any necessary bylaws modifications by June 1, 2003. Analysis Regarding combination of SPP’s full representation committees, the SPTF recommends that the resulting group be titled the “Policy Committee,” and related recommended modifications to Sections 5.1 and 5.2 of SPP’s Bylaws are shown in the attached document that convolve the responsibilities of the two previous committees. Regarding the assessment of current working groups, the SPTF reviewed and discussed SPP’s current structure with various leadership, members and staff. The SPTF recommends the modifications shown in the attached organizational group structure chart that deletes the Ancillary Services, Black Start Study, Control Area Implementation, and Scheduling Task Forces, and adds the Strategic Planning Committee reporting to the Board of Directors, and the Business Practices, Operation Model Development and the Critical Infrastructure Protection Working Groups reporting to the Policy Committee. Scope documents for each of the added groups are also attached. Recommendation The SPP Strategic Planning Task Force recommends that the SPP Board of Directors approve the attached organizational group structure, scope statements and related bylaws modifications, to become effective immediately. The SPTF also recommends that SPP’s remaining organizational groups review their scope statements and present any necessary modifications for Board of Directors consideration at their November 2003 meeting.

Southwest Power Pool Strategic Planning Committee

Organizational Group Scope Statement June 24, 2003

Purpose The Strategic Planning Committee (SPC) is responsible for the development and recommendation to the Board of Directors of strategic direction for the corporation. Scope of Activities In carrying out its purpose, the SPC will:

1. Gather information from SPP members, customers, Staff, regulatory jurisdictions, market monitors, and legislative bodies on industry trends, forecasts and directions.

2. Assess the industry environment in which SPP will be operating. 3. Assess SPP’s capabilities and competencies against the industry

environment, including coordination with neighboring entities. 4. Develop and recommend to the SPP Board of Directors a mission and

vision statement and accompanying goals and objectives as needed. 5. Formulate strategies to ensure achievement of SPP’s mission statement,

goals, objectives and responsibilities and recommend necessary modifications to SPP processes to carry out these strategies.

6. Work with other SPP organizational groups in developing related action plans, schedules and budgets.

Representation The SPC is to be comprised of at least eight and no more than twelve members, including a Chair and Vice Chair, who are appointed by the Board of Directors pursuant to SPP Bylaws. At all times, a majority of the members must be elected Directors. Every attempt will be made to maintain a membership with balanced representation from Transmission Owning Members and Transmission Using Members. At least two members will be non-stakeholder Directors with one being the SPP President. Business shall be done in accordance with SPP Bylaws. There are no term limitations. Reporting The SPC reports to the Board of Directors.

Southwest Power Pool, Inc. Bylaws

SPTF DRAFT – May 28, 2003

7.1 Operating Budget The SPP Staff and the Finance Working Group will prepare an annual budget of expenditures for the next fiscal year and an estimate for an additional two years. The proposed budget shall be submitted to the Board of Directors not less than two weeks prior to the meeting at which the budget is to be considered for approval. Once approved by the Board of Directors, the budget shall constitute the authority for expenditures for the ensuing year. Modifications to the budget during the fiscal year must be recommended to the Board of Directors by the Finance Working Group. The President shall have the authority to approve unbudgeted expenditures of up to $250,000 individually or in the aggregate during the fiscal year. The President may approve unbudgeted expenditures in excess of $250,000 but less than $1,000,000 with the concurrence of the Finance Working Group. Unbudgeted expenditures in excess of $1,000,000 require prior approval of the Board of Directors.

7.2 Annual Membership Fee All SPP members will be subject to an annual membership fee to recover the cost incurred by the SPP related to maintaining reliability criteria and related compliance. Members without “Net Energy for Load” will pay an annual membership fee of $6,000. Members with “Net Energy for Load” reported annually to the Department of Energy under EIA-411 will pay a fee equal to $0.0053 multiplied by their respective Net Energy for Load MWh as reported for the current year. These rates will be adjusted annually by the change (if any) in the approved SPP general wage adjustment. At least once every five years, the SPP will conduct a specific review of the time and expense associated with the cost of providing this basic service and adjust the membership fee accordingly. Entities joining SPP at times other than the start of SPP’s fiscal year will pay a pro rata portion of the first year membership fee. SPP will not refund membership fees.

7.3 NERC Assessment The NERC assessment is to be a direct pass-through and will be charged to the membership per the assessment formula outlined below at the time SPP is invoiced by NERC:

A = [ 0.25(1/N) + 0.75(B/C) ] X,

where; A = Member’s Share of NERC Assessment, N = Total number of Members, B = The Member's previous year Net Energy for Load within SPP, C = Total of factor B for all Members, and X = Actual NERC Assessment to SPP

7.4 Monthly Assessments SPP will assess all costs not otherwise collected via a monthly assessment. Costs recovered under the assessment will include all operating, financing, and capital costs associated with the performance of SPP’s functions as assigned by the Board of Directors. Significant among these are costs associated with regional security coordination and the provision of transmission service. SPP shall determine the assessment rate each month based on monthly budgeted net expenditures (adjusted for “true-up” from prior months) divided by estimated monthly Schedule 1-A billing units for service sold under SPP’s tariff and member load eligible to take, but not taking, Network Integration Transmission Service under SPP’s tariff. Each load-serving member shall then be assessed the monthly assessment rate applied to its load eligible to take Network Integration Transmission Service under the SPP tariff. Further, each load-serving

Southwest Power Pool, Inc. Bylaws

SPTF DRAFT – May 28, 2003

member shall receive a credit against the monthly assessment for that month’s Schedule 1-A fees paid for Network Integration Transmission Service under SPP’s transmission service tariff.

7.5 Fiscal Agent The President shall serve as the Fiscal Agent of SPP. The President shall keep an up-to-date record of receipts and disbursements and furnish reports to the Board of Directors and the Finance Working Group.

7.6 Auditors The Finance Working Group shall annually engage an independent certified public accounting firm to perform an annual audit of SPP’s financial records and prepare a report on the financial condition of SPP. The Finance Working Group shall present the audit report to the Board of Directors upon completion.

RTWG Report to the SPTF May 28, 2003

Formula Rates Task Force Participants Jay E. Toungate (Chair), American Electric Power; Dennis Bethel, American Electric Power; Mark Oligschlaeger, Missouri Public Service Commission; John Gunesch, OG+E; Steve Goodner, OG+E; Ward Combs, OG+E; Bob Oakes, Westar Energy; Scott Helyer, Tenaska; Robert Elrod, Western Farmers Electric; Robert Shields, Arkansas Electric Cooperative. Meetings to Date Wednesday, May 14; Friday, May 16; and Wednesday, May 21. Discussions to Date At its first meeting, the Formula Rates Task Force established its view was that: 1) use of the formula rate or a stated rate should be at the option of each Transmission Owner and that 2) application of the formulary process should allow some flexibility to reflect the respective situation of each Transmission Owner using it. Where functional direct assignment information or special studies are available, they should be used in place of the default allocation factor currently specified in the formula. Such departures would necessarily be fully documented. At its first meeting the task force worked through the Form-1 template (for use by the FERC jurisdictional TOs) line-by-line, setting out items for which it recommends change or where there were questions. The MISO templates as accepted by FERC and distributed by SPP Staff will be used as a starting point, with all recommended changes to them specified for RTWG review. In subsequent meetings the task force has discussed the following:

Inclusion of annual allocation of FERC costs. ROE options (FERC incentives, individual company ROEs or an SPP-wide ROE). Appropriate templates for use by Cooperative or Municipal utilities. Revenue adjustments Adjustments to the MISO templates

The task Force anticipates providing a recommendation on modifications to the template(s) at the June 5th RTWG meeting. Future Scheduled Meetings Wednesday, May 28.

Transmission Facilities Definition Task Force Participants

Les Dillahunty (Chair), SPP; Bill Dowling, Midwest Energy; Ron Kite, Kansas City Power and Light Company; Mike Proctor, Missouri Public Service Commission; Lena Mantle, Missouri Public Service Commission; John Gunesch, OG+E; Phil Crissup, OG+E; Jay Toungate, American Electric Power; Dennis Bethel, American Electric Power; Terri Gallup, American Electric Power; Robert Pennybaker, American Electric Power; Scott Helyer, Tenaska; David Brian, GDS Associates, Inc.; Seth Brown, GDS Associates, Inc.; Ricky Bittle, Arkansas Electric Cooperative; Ronnie Frizzell, Arkansas Electric Cooperative; Dennis Reed, Westar Energy; David Grover, Xcel Energy; Bary Warren, Empire District Electric; Edwin Farrar, Oklahoma Corporation Commission; Karen Forbes, Oklahoma Corporation Commission; Alan Derichswiler, Western Farmers Electric; Christine Ryan, Brickfield, Burchette, Ritts & Stone; and Mike Lavanga, Brickfield, Burchette, Ritts & Stone. Meetings to Date Monday, May 13 and Thursday, May 22. Discussions to Date At the first meeting of the Transmission Facilities Definition Task Force, substantial discussion was had concerning the rate and revenue implications associated with any change in definition for ratemaking purposes. There was general agreement that the effort should be split into two parts, a definition that applies for system planning and operational control purposes and a definition that applies for ratemaking. There was general agreement that the planning and operational control definition should apply to facilities operating at 60 kV and above since 69 kV facilities are represented in planning and operational models. For ratemaking, the group favored adoption of the definition used by MSIO, and similar to SPP’s currently effective tariff definition, which includes all facilities booked by a Transmission Owner to transmission plant accounts and properly includable for transmission service ratemaking pursuant to FERC policy. In subsequent discussion of alternative “Bright Line”, “Bright Line With Transition”, and “Evergreen” definitions on May 22, the task force reaffirmed support for the approach initially favored on May 13, with adoption of clarifying language changes proposed by East Texas and inclusion of the operational control criteria as a subpart in the definition.

Future Scheduled Meetings Friday, May 30.

Generation Interconnect Task Force Participants Robert Tumilty (Chair), American Electric Power; Robert Pennybaker, American Electric Power; Jim Sherwood, Southwestern Power Administration; John Gunesch, OG+E; Phil Crissup, OG+E; Brad Cox, Tenaska; Scott Helyer, Tenaska; Dennis Reed, Westar Energy; Don Taylor, Westar Energy; Mitch Williams, Western Farmers Electric; Jim Useldinger, Kansas City Power & Light; Darrell Gilliam, Southwestern Power Administration; and Christi Nicolay, Duke Energy Trading and Marketing.

Meetings to Date Tuesday, May 13; Thursday May 15; Tuesday May 20; and Thursday May 22. Discussions to Date There was general support for continued use of the pattern Interconnection Agreement that SPP has been using. This is based on MISO’s IA template. The MISO pro forma IA has been through the FERC process and has been used as a basis for negotiating several IA's by the SPP. Additionally FERC has issued several orders stating that FERC will require new IAs to be conformed to the pro forma issued by FERC when the final IA rule is issued. The interests in modification of the MISO IA were primarily in Sections 4 and 7, related to operations; Sections 9, related to the income tax consequences of Generator funding of interconnection facilities of income taxes; and miscellaneous editorial and grammatical changes. Where there has been an expressed interest in change, the interest has been to move toward the draft pro forma included in the NOPR. This Task Force is also developing a Schedule for Generation Imbalance Service and has essentially concluded a proposal for consideration of the full RTWG at it’s June 5th Meeting. Future Scheduled Meetings Friday May 30.

Queue Improvement Task Force Participants Bruce Rew (Chair), SPP; Grant Wilkerson, Westar Energy; Jason Attwood, Calpine; Scott Helyer, Tenaska; Norman Williams, Sunflower. Meetings to Date Monday, April 28; Wednesday, May 7; Wednesday, May 14. Discussions to Date The QITF met by conference call on April 28 to discuss the SPP Staff initial proposal. This proposal was developed from a previous effort to modify the queuing process. The QITF reviewed the proposal and provided comments for the presentation to the RTWG on May 5. On May 7 and on May 14, the QITF had conference calls to define the process and develop a recommendation for the RTWG to review. The QITF has developed the preliminary framework for an aggregate study process. The QITF recommends the SPP change its process for transmission service and generation interconnection processing to an aggregate study methodology. Key components of the proposed methodology include an open season to establish a study group, a four-month period to perform the study with SPP determination of optimal solution, allocation to customers based on impact and restudy subsequent to optional withdrawal. This concept was presented at the May 19th RTWG with a request that the RTWG support

development of this concept into a proposed tariff modification for consideration by the RTWG. The RTWG endorsed this effort. Future Scheduled Meetings Tuesday, June 3.

Participant Funding The RTWG had a general discussion of participant funding at its Meeting on May 5. SPP Staff and Ricky Bittle had subsequent discussion on May 6 concerning modification to SPP OATT Attachments J (“Recovery Of Costs Associated With New Facilities”) and O (“Coordinated Planning Procedures”) and on May 15 discussion of Part IV, Section 37 of the PJM OATT as a basis for RTWG discussion of cost assignment of interconnection facilities at its May 19th meeting. At the May 19th meeting, cost assignment scenarios were developed for assessment by the committee members prior to the June 5th meeting. A listing of these scenarios is attached.

Southwest Power Pool

RTWG Meeting – 05-19-03 Cost Assignment Scenarios – Participant Funding

Network Upgrades for Reliability of Service within a Pricing Zone. Network Upgrades for Reliability of Service within the SPP Footprint. Radial lines to Load for Reliability of Service within a Pricing Zone. Radial lines to Load for Reliability of Service within the SPP Footprint. Radial Lines from Generation. Network Upgrades for Economic Service to Load within a pricing Zone. Network Upgrades for Economic Service to Load within the SPP Footprint. Network Upgrades for Export from SPP Footprint. Out of Footprint Upgrades for Reliability. Out of Footprint Upgrades for Economic Imports. Generation Interconnection Facilities for generation to load within a Zone. Generation Interconnection Facilities for generation to load within the SPP Footprint. Generation Interconnection Facilities for generation to load outside the SPP Footprint. Generation Outlet Facilities for generation to load within a Zone. Generation Outlet Facilities for generation to load within the SPP Footprint Generation Outlet Facilities for generation to load outside the SPP Footprint

Southwest Power Pool STRATEGIC PLANNING TASK FORCE May … · 2019. 2. 8. · MINUTES NO. 6...

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