Honorable Magalie R. Salas, Secretary 888 First Street, N ... readiness filing.pdfAccenture have been evaluated by Gestalt and substantially refined. These largely organizational refinements

December 22, 2006 Honorable Magalie R. Salas, Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20246 Re: Southwest Power Pool, Inc., Docket Nos. ER06-451-000, et seq. and ER06-1467-00_ Dear Secretary Salas:

Pursuant to Rule 1907 of the Commission’s regulations, 18 C.F.R. § 385.1907, and in accordance with the compliance requirements of Commission orders issued in the captioned dockets, Southwest Power Pool, Inc. (“SPP”) submits the enclosed materials demonstrating the readiness of SPP to deploy its Energy Imbalance Services market (“EIS”), effective February 1, 2007. In support, SPP states as follows: I. Background and Overview

In February, 2004, SPP received conditional approval of its proposal to become a regional transmission organization (“RTO”) under Commission Order Nos. 2000 and 2000-A.1 Since that time, SPP has implemented a series of market initiatives and tariff changes to comply with Commission directives, with the ultimate goal of improving the efficiency and reliability of electricity markets throughout SPP’s eight-state, 250,000 square-mile service territory.

The development of SPP’s real-time imbalance market reflects the culmination of

many months of market design efforts. Working through various task forces and committees, SPP has refined its original EIS proposal to satisfy the conditions imposed in a series of related Commission orders.2 1 See Southwest Power Pool, Inc., 106 FERC ¶ 61,110, order on compliance,

109 FERC ¶ 61,009 (2004), order on reh’g, 110 FERC ¶ 61,137 (2005).

2 See, e.g., Southwest Power Pool, Inc., 112 FERC ¶ 61,303 (2005) (“September 19 Order”); Southwest Power Pool, Inc., 114 FERC ¶ 61,289 (2006) (“Market Order”); see also Southwest Power Pool, Inc., 116 FERC ¶ 61,053 (2006) (“EIS Tariff Order”); and Southwest Power Pool, Inc., 117 FERC ¶ 61,139 (2006) (“EIS Compliance Order”).

Honorable Magalie R. Salas, Secretary December 22, 2006 Page 2

More specifically, the Market Order and EIS Tariff Order, inter alia, directed SPP to make the following compliance filings with the Commission. First, SPP was required to file a set of transitional safeguards and readiness metrics (“Readiness Metric Condition”) to measure SPP’s progress relative to market implementation milestones. See Market Order at P 23; accord EIS Tariff Order at P 45. Secondly, SPP was required to submit a written certification of SPP’s market readiness (“Certification Condition”) demonstrating SPP’s “substantial[] complet[ion]” of the items included in its readiness metrics. The Certification Condition further directed SPP to provide to the Commission the results of the North American Reliability Council (“NERC”) on-site Working Group’s evaluation of SPP’s markets and NERC’s recommendation on the readiness of SPP’s imbalance markets. See Market Order at P 20; EIS Tariff Order at P 45. Additional compliance requirements relating to the Certification Condition were imposed in the EIS Compliance Order. See, e.g., EIS Compliance Order at P 24.

On September 1, 2006 (as later corrected), in compliance with the Commission’s

Readiness Metric Condition, SPP filed with the Commission tariff revisions and other materials relating to SPP’s EIS market. SPP included in the September 1, 2006 filing, for informational purposes, a menu of independently evaluated metrics relating to operational readiness and testing. As described in the September 1 filing, Accenture LLP was retained by SPP to assess the state of the EIS implementation program and to provide a set of metrics to monitor the program’s progress.3

In a pleading filed October 11, 2006, SPP clarified certain aspects of its September 1 filing to address questions raised by several intervenors with respect to SPP’s compliance with the Readiness Metric Condition.4 In particular, SPP responded to concerns regarding the independence of Accenture by confirming the retention of a second consulting firm, Gestalt, LLC, to perform an independent evaluation of SPP’s market readiness metrics.

In its October 31, 2006 EIS Compliance Order, the Commission largely accepted SPP’s September 1 filing as compliant with the requirements of the Readiness Metric Condition, subject to minor additional clarifications and tariff revisions. The Commission specifically found (at P 24) that SPP’s engagement of Gestalt “directly addresses [intervenor’s] independent evaluation concerns related to Accenture.” The 3 As an additional layer of protection and to permit collaborative input by SPP

stakeholders, Accenture agreed to certain additions to the original, master metric list.

4 “Motion for Leave to File Late Answer and Answer of Southwest Power Pool, Inc. to Comments and Limited Protest of TDU Intervenors and Xcel Energy Services Inc. on Behalf of Southwestern Public Service Company,” Docket Nos. ER06-451-009 and ER06-1467-000, filed October 11, 2006, hereinafter “SPP Answer.”

Honorable Magalie R. Salas, Secretary December 22, 2006 Page 3 Commission further determined that “SPP and its Board of Directors will ultimately decide SPP’s readiness to begin its market operations after reviewing its readiness, including Gestalt, LLC’s assessment.” Id. In addition, SPP was directed to file, on an informational basis, the Gestalt report as part of its market readiness certification at least 30 days prior to EIS market implementation. Id. II. Certification of Market Readiness

The purpose of the instant filing is to confirm SPP’s readiness to implement its

EIS market, pursuant to the requirements of the Certification Condition of the Market Order, as modified in the EIS Tariff Order and EIS Compliance Order. To this end, SPP is submitting, in addition to this compliance letter, the Readiness Certification of SPP’s President and Chief Executive Officer, Nicholas A. Brown (Attachment I), the required NERC evaluation and recommendation concerning SPP’s market readiness (“NERC Assessment”) (Attachment II)5 and the Gestalt Report assessing SPP’s market readiness metrics (filed for informational purposes, per the EIS Compliance Order) (Attachment III). In addition, pursuant to the requirements of the EIS Tariff Order (P 53), SPP provides an updated transition and reversion plan (Attachment IV) that documents the results of SPP’s reversion to normal operations following the deployment of recent market trials. The updated transition and reversion plan has been modified to reflect a February 1, 2007 go-live date as well as various improvements identified from SPP’s numerous testing activities. Of note, a majority of the steps in these procedures have been exercised and refined during the 21 deployment tests performed by SPP.

As discussed below, and as confirmed in the attachments hereto, SPP is prepared

to implement its EIS market as of February 1, 2007. SPP has tested its market systems, tested its transition and reversion plan, trained necessary personnel and committed the required resources to ensure the launch of the EIS market without compromising the reliability of operations in SPP’s service region. All necessary legal and regulatory requirements specified in the Commission’s orders regarding SPP’s Open Access Transmission Tariff (“OATT”) have been, or will be, complied to enable SPP to have the requisite authority to implement the EIS market on February 1, 2007.

5 The NERC technical verification report was addressed in a written response by

SPP submitted September 8, 2006, which is also attached as part of Attachment II hereto. The recommendations contained in SPP’s September 8, 2006 response were subsequently approved at NERC’s Operating Reliability Subcommittee meeting on September 20, 2006.


• Readiness Metrics

SPP is certifying that it has “substantially complete[d]” the items identified in its market readiness metrics. However, as was the case with other market start-ups,6 there are certain elements of SPP’s market implementation plan that, as of the date of this filing, are undergoing further review and testing.

In this regard, SPP notes that the original Readiness Metrics developed by Accenture have been evaluated by Gestalt and substantially refined. These largely organizational refinements reflect revisions in form, not substance, to the Accenture metrics. For example, a number of items initially included in the metrics set developed by Accenture, while descriptive of tasks requiring completion prior to market start-up, are not properly considered performance measurements – i.e., “metrics,” as the term is commonly understood – of market readiness.7 Accordingly, based on the Gestalt assessment, SPP re-categorized items from the original Accenture list to distinguish “Go-Live Readiness Metrics,” which focus on measuring the performance of the processes and systems necessary to run the EIS market, from “Go-Live Issues,” which are more administrative in nature and serve to track items that must be corrected/completed prior to market implementation. Importantly, every item from the original Accenture metrics set is mapped and accounted for; in addition, the re-categorized lists were reviewed with the SPP Board and various SPP committees and status reports are provided on each item on a regular basis.

As shown in the accompanying Gestalt Report, there are twenty-seven (27)

discrete metrics being tracked. Where appropriate, metrics are tracked on a daily basis and 14-day and 30-day trends are reported. Most recent deployment test show improving performances and substantially higher pass rates for these metrics, as confirmed in the Gestalt Report. Based on the most recent test, 24 metrics passed and 3 failed. The Gestalt Report provides an analysis of these metrics and concludes that the systems have demonstrated consistently stable operation over their last observation period. As explained in the Gestalt Report, fail status generally relates to minor issues that are near 6 See, e.g., Midwest Indep. Transmission Sys., Operator, Inc., 110 FERC ¶ 61,289,

at PP 35, 38 (2005) (accepting MISO’s Readiness Certification, notwithstanding reservations concerning further system testing and acknowledging continuing efforts to meet certain readiness metrics at time of certification); see also Midwest Indep. Transmission Sys., Operator, Inc., 110 FERC ¶ 61,049, at P 72 (2005) (stating that the Commission did not expect verification of “each and every metric,” but rather confirmation that an appropriate level of reliability and readiness had been achieved prior to market start-up).

7 Two obvious examples include the completion of task force review of settlement calculations and the obligation of SPP to file with FERC a certification letter confirming market readiness.

Honorable Magalie R. Salas, Secretary December 22, 2006 Page 5 misses and/or slow performances rather than complete failures of applications for extended periods; none of the 3 failures poses an impediment to SPP’s ability to reliably operate the EIS market effective February 1, 2007.

In addition, as of the date of this certification filing, there are 26 issues on the Go-

Live issues list and 12 remain outstanding with minor tasks that are on track for completion before the Go-Live date. SPP has identified the resolution required for each outstanding issue and has developed a plan to implement the necessary actions to close out these remaining issues well in advance of the Go-Live date.

• Pre-Launch System Updates and Market Trials

SPP notes that as part of its Market Transition and Reversion plan (filed May 19,

2006), a “Go/No-Go” Advisory Team was established, consisting of the Chairs of various SPP stakeholder committees, task forces and working groups, as well as SPP Staff, SPP’s Board of Directors, the Regional State Committee and the Strategic Planning Committee. The Go/No-Go Advisory Team will review operational conditions and status of transition activities in the days and weeks immediately preceding the February 1 launch date. See Section 4.1.4 of Market Transition and Reversion Overview. The final decision on whether to implement SPP’s EIS market on February 1, 2007 (or delay such implementation) will be made in consultation with the Go/No-Go Advisory Team, based on a series of pre-launch assessments, including a checkpoint the final day of the transition period.

Extensive time and effort has been dedicated to ensure SPP’s readiness to commence market operations effective February 1, 2007. These efforts will necessarily continue up to the “go/no-go” decision. SPP expects that outstanding implementation issues will be addressed on or before February 1, 2007. As certified by Mr. Brown, none of these issues poses an impediment to SPP’s ability to reliably operate the EIS market beginning February 1, 2007.

Finally, the development of the various systems and business processes required

for SPP’s EIS market requires multiple project phases. The last phase is Market Trials which includes tests of the systems and processes across SPP, vendors and Market Participants. The results of these Market Trials often require detailed analysis and sometimes changes to processes or systems which then require additional Market Trials for validation. Ideally, systems issues identified through Market Trials would all be complete prior to the filing of this certification.

Because the Market Trials phase has resulted in some system changes that are not

yet complete, SPP has not been able to utilize final versions of all software in the testing to date. However, SPP expects to complete all market system modifications in sufficient time to provide at least seven continuous days of system monitoring prior to February 1, 2007.


• Open Regulatory Matters

SPP notes that certain matters relating to its EIS market design are pending Commission review. With one exception, i.e., SPP’s Violation Relaxation Limits (“VRLs”), SPP does not believe that regulatory approval of these matters prior to EIS market implementation is necessary. Nonetheless, the market will benefit by having resolution of all pending matters that may directly or indirectly affect the terms and conditions of SPP’s EIS market design and for that reason SPP urges prompt consideration of the matters identified below:

• SPP's October 26, 2006 filing to (1) revise Section 1.2.6 of Attachment AE to require offer curve price caps of $1000/megawatt-hour until SPP demonstrates that sufficient demand response exists in the EIS market to allow a higher offer curve price limit or removal of the offer curve price limit and (2) to incorporate the specified modification into Schedule 4. These revisions are designed to comply with FERC’s September 26, 2006 Order (ER06-451-010).

• SPP's November 20, 2006 filing in compliance with FERC's October 19, 2006

order conditionally approving SPP's revisions to the loss compensation provisions of Attachment M and Attachment AE to reflect the EIS market (ER06-729-003).

• SPP's November 27, 2006 filing in compliance with FERC's October 26, 2006

order conditionally approving SPP's August 21, 2006 compliance filing (ER06-451-012).

• SPP's December 12, 2006 filing of tariff revisions to implement Violation

Relaxation Limits in response to the penalty factor issue in compliance with the October 31 Order (ER07-319-000). Commission approval of these tariff revisions is necessary prior to EIS market implementation.

• SPP’s December 15, 2006 filing of (i) a revised Balancing Authority

Agreement as Attachment AN to the SPP tariff and (ii) revisions to existing Attachment AE, Section 8, establishing the liabilities relating to the balancing functions described in Attachment AN in compliance with FERC’s November 17, 2006 Order Conditionally Approving Partial Contested Settlement (ER06-451-015).

• SPP’s December 20, 2006 filing of tariff revisions to reflect improved

efficiency in the procedures used by SPP to monitor system conditions and coordinate operating plans with Balancing Authorities (ER06-451-007 and ER07-345).

ATTACHMENT I

ATTACHMENT II

NERC SPP Market Technical Verification Team Report March 2006

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Verification Team Summary and Conclusions

Audit Criteria and Topics At its February 2006 meeting, the Operating Reliability Subcommittee (ORS) approved a motion which accepted the proposed criteria for SPP’s market readiness review. The minutes from the meeting indicate the following:

SPP Energy Imbalance Service Market Lanny Nickell provided a status report of SPP’s Energy Imbalance Service Market implementation. Market trials are going well, and SPP is on schedule for filling required operating positions. Market startup remains scheduled for May 1, 2006, with a go/no-go decision date of April 21, 2006. The go-live decision will be based upon stakeholder input related to market member readiness and the implementation status of the reliability and market tools. Mr. Nickell reviewed the proposed criteria for the SPP market readiness verification. Jim Castle encouraged SPP’s neighboring reliability coordinators to participate in the readiness verification. The subcommittee scheduled a conference call on April 4, 2006 at 10 a.m. EDT to consider the results of the readiness verification. Dave Zwergel moved to accept SPP’s proposed criteria for its market readiness verification review. The subcommittee approved the motion.

The general topics that were reviewed by the Technical Verification Team are as follows:

1. SPP Post Market Reliability Plan i) Verifying any references to SPP market tools, congestion practices, and

operational studies.

2. Regional Differences to Reliability Standards — Verification that SPP is ready to perform market and reliability functions and that its market and reliability tools are in place and functional, in accordance with the regional differences.

i) RTO Market Inadvertent Accounting — BAL-006. ii) Enhanced Congestion Management — IRO-006.

3. Market Tools — Identifying and binding constraints in market systems versus TLR. Verification of regional congestion management and market tools.

4. Operator Training — Review content related to congestion management and the market.

5. Review of Operator Processes and Procedures.

Audit team members included:

1. SPP Representation — Mike Gammon – KCPL 2. Neighboring Reliability Coordinators

(a) MISO — Julie Pierce, Dede Subakti


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(b) TVA — Rich McCrory (c) Entergy — Ryan Prejean

3. Neighboring Regions (a) MRO — John Seidel

4. NERC IDCWG (a) IESO— Tim Babcock (b) Entergy — Ryan Prejean (c) PJM — Ted Franks (d) MISO — Julie Pierce (e) SPP — Wayne Galli (f) TVA — Rich McCrory

5. NERC Staff — Larry Kezele Summary of Reviews 1. SPP Post Market Reliability Plan — The changes to the SPP reliability plan were reviewed

and the team acknowledged that the addition of the statements to the reliability plan were the primary focus of the technical verification activities. These changes will be verified in the review of the other technical verification scope topics listed.

2. Regional Differences

a) BAL-006 — SPP was found to have the necessary tools, processes, and procedures in place to meet the requirements of NERC Reliability Standard BAL-006. The detailed verification items are included in detail in Section 2.1 and in Appendix A of this document.

b) IRO-006 — The necessary SPP data flows for this regional difference were in place as detailed in the report below. i) Congestion Management Process — The team observed the congestion management

process on a limited basis in the SPP market systems. There were concerns regarding the operational process flow of a congestion management event that takes place in the SPP control room. The team feels that more automation and fewer steps to implement will improve the operator’s capability to handle a congestion event.

The team is asking SPP to evaluate the operational tools and displays for the purposes of summarizing the important information and streamlining the process necessary for a congestion management event.

One specific operator tool identified, the effective limit calculator, has tentative plans to move towards additional automation to gather data to reduce manual entry for finding the limit for a flowgate during a congestion management event. The team supports the move in this direction as soon as possible.

3. Market Tools — The team observed the market dispatch process on a limited basis in the

SPP market systems. There were concerns around the lack of graphs that show load, generation, schedule, and dispatch trending for real-time operational use. It seemed it would


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be difficult for the SPP operator to gather situational awareness around the market activities and real-time system operations.

SPP should review and analyze whether or not the auto approval of its market dispatch is the best configuration for its market processes. For example, MISO, IESO, and PJM have operator-approved dispatch cases that allow for anomalies in the day-to-day operations to be circumvented before a corrupt dispatch is sent out.

SPP should develop a plan for market system model updates, determine required market operations system (MOS) downtime, and plan for this occurrence.

4. Operator Processes and Procedures — The group reviewed the available market processes

and procedure documentation. There is still a need to evaluate the operational conditions that may be presented to the SPP operational staff on a day-to-day basis with the market in place and create procedures to identify the necessary actions needed. How each member of the control room will be affected needs to be identified so effective communication and situational awareness can take place during an event.

The operational procedures for the SPP market operators should provide a means for a manual intervention into the market dispatch solution when necessary for operational conditions. The procedure should address the market balancing authority’s responsibility and capability to stop using the base points that are sent when the operational conditions warrant.

The operational procedure for the SPP market that ensures that the market balancing areas are able to utilize any of the SPP market net scheduled interchange (NSI) values for their ACE equations needs to be created and verified with each market balancing area. Verification is needed to ensure that each market balancing area in the market is able to efficiently switch between the different SPP NSIs sent when needed.

Based on wide variations of dispatch patterns that may occur with a new market, SPP should evaluate the need to model generation contingencies in its on-line analysis tools rather than off-line.

5. Operator Training — The training done thus far for the SPP market has revolved primarily

around the new tools that will be present after the market. There is still a strong need for control room training on market scenarios that the SPP operators will be faced with when the market goes live. The Technical Verification Team encourages SPP to utilize the test systems it has in place while developing the market tools to run scenario-based examples with the entire control room crew including operations engineers, reliability coordinators, and market operators. Both the tools and the operators can only benefit from running additional congestion and tool failure scenarios to work out process flow and procedure issues for these critical situations.

The team also recommends that the SPP market operators seek out site visits to other market operator entities to gain additional understanding of the market dispatch situations and scenarios that they will be faced with on a day-to-day basis.


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The training department should expedite the inclusion of the market operator training into its operational curriculum and processes so that additional personnel can be trained efficiently.

A full job task analysis and job role evaluation should be done for the SPP market operator to ensure that the role is not going to require additional personnel to be hired. It is the observation of the team that the work load on the market operator will be significant and some of the tasks may need additional personnel and/or reallocation to other control room roles to ensure all reliability and operational tasks can be managed without error.


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Verification Team Detailed Report

The Technical Verification Team met with SPP staff and received presentations on the SPP Energy Imbalance Service market. Each topic was reviewed and tools demonstrated by the team. The results are included in the sections below. 1. SPP Post-Market Reliability Plan

This plan was approved by the SPP region and the SERC Operating Committee. This reliability plan will be presented to the NERC ORS and to the NERC Operating Committee in May and June respectively.

The reliability plan states in section 3.4 of Section F, Emergency Operations:

If SPP receives notification from the IDC that SPP Market Flows need to be curtailed in response to a TLR issuance, SPP will utilize its market systems to calculate and send dispatch instructions to its market participants necessary to achieve the curtailment. SPP updates its Market Flow information in the IDC every 15 minutes and will monitor this information to verify that SPP implemented the appropriate Market Flow curtailment instructions from the IDC.

The team acknowledged that the addition of this statement to the reliability plan was the primary focus of the technical verification activities and will be verified by reviewing the other scope topics.

2. Regional Differences

2.1. BAL-006-1 ⎯ Inadvertent Interchange The SPP tools and document were reviewed and verified. See Appendix A for detailed verification items. A summary of the verification follows.

2.1.1. Reviewed regional difference documentation and noted one instance where there should be revision.

2.1.1.1. In the 2004 waiver request for the RTO inadvertent interchange accounting, in the New Responsibilities section, there is a reference to “ECAR” as the RTO reporting entity when NERC is the actual reporting entity.

2.1.2. SPP presented the process and demonstrated the tools used to calculate and record hourly inadvertent.

2.1.3. SPP has the processes and procedures in place to calculate, report, and payback inadvertent in accordance with the responsibilities dictated by the Inadvertent Waiver Request as referenced in NERC Reliability Standard BAL-006, section E, Regional Differences.

2.1.4. SPP processes and procedures will meet the requirements of BAL-006 as modified by the Inadvertent Waiver Request.


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2.1.5. Specifically reviewed: 2.1.5.1. Observed demonstration of the tools used to calculate net interchange

schedules for the SPP balancing authorities. 2.1.5.2. Observed demonstration of the tool to calculate inadvertent and inadvertent

accumulations for SPP. 2.1.5.3. Found SPP reporting inadvertent to NERC. 2.1.5.4. SPP meets the requirements of BAL-006 through a combination of SPP and

its members. 2.1.5.5. SPP will complete the data requirements for schedules necessary for its

members to respond to AIE surveys. SPP will utilize the same processes it has in place now for its members to obtain the data necessary to respond to AIE surveys.

2.2. IRO-006-2 Reliability Coordination ⎯ Transmission Loading Relief

2.2.1. Verify all Market Data Flows 2.2.1.1. Day-Ahead and Real-Time Load/Interchange

2.2.1.1.1. The real-time load/interchange file was not being sent. 2.2.1.1.2. The day-ahead and next-hour load/interchange files are being sent and

posted correctly.

2.2.1.2. Tag Dump 2.2.1.2.1. Verified that the tag dump included interchange and load for all

existing balancing authorities. 2.2.1.2.2. Verified that a tag dump file was submitted each hour in accordance

with reliability standards. 2.2.1.2.3. Verified that the day-ahead load and interchange was submitted at a

minimum of once a day. 2.2.1.2.4. Verified that the format of the tag dump was in accordance with

approved reliability standards.

2.2.1.3. Day Ahead Network and Native Load (NNL) 2.2.1.3.1. Verified that day ahead NNL is being sent to the interchange

distribution calculator (IDC) at least once per day. 2.2.1.3.2. Could not verify that all coordinated flowgates are included in this file.

2.2.1.3.2.1. IDC test system did not have the current information from the Book of Flowgates.

2.2.1.3.3. Verified that the file is sent by the time of day specified in the congestion management whitepaper.

2.2.1.4. Marginal Zone Weighting Factors 2.2.1.4.1. Verified that the marginal zone weighting factors produced by SPP

reflect marginal units and correspond to the data being submitted to the IDC.

2.2.1.4.2. Verified that these factors can be utilized by the IDC for the calculation of import and export market transfer distribution factors.

2.2.1.4.3. Marginal zone export, for all ten zones, is being sent every 15 minutes.


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2.2.1.4.4. Verified that there was not a marginal zone import filed due to the market structure.

2.2.2. Market Flow 2.2.2.1. Verified that SPP is not including counter flow or netting in either direction.

The net market flow reduction may be seen either in the forward or reverse flow supplied by SPP, depending on their generation response. This is consistent with PJM and MISO.

2.2.2.2. Could not verify that market flow is being submitted for all coordinated flowgates.

2.2.2.2.1. IDC test system did not have the current information from the Book of Flowgates, which attributed to the lack of flowgate data in the IDC.

2.2.2.2.2. SPP also indicated that not all coordinated flowgates have market flow currently being calculated due to changes being made in the SPP OASIS automation system. All coordinated flowgates will be added prior to market go-live. SPP and the IDCWG will be tasked with verifying.

2.2.2.3. Current hour flow is calculated and sent to the IDC every six minutes. 2.2.2.4. Next hour flow is calculated and sent to the IDC every nine minutes. 2.2.2.5. Verified that a reciprocal coordinated flowgate contains ED-2 market flow,

but a coordinated flowgate does not. 2.2.2.6. Current and next hour, forward/reverse, unconstrained/constrained market

flows are being sent every six minutes and nine minutes. 2.2.2.7. Verified that the ten balancing authorities under the SPP market footprint

are treated with regional difference considerations. The treatment of SPP’s non-market balancing authorities has not changed.

2.2.2.8. Verified that joint-owned units (JOUs) are modeled such that the SPP market portion and the external portion are treated separately. Only the market portion is dispatched for market flow considerations. The external portion is not part of the market and is treated accordingly.

2.2.3. Generator Mobility Factors (GMF) 2.2.3.1. Verified that the GMFs were submitted at a minimum of once a day.

2.2.4. Tag Dump 2.2.4.1. Verified that the tag dump included interchange and load for all existing

balancing authorities. 2.2.4.2. Verified that the day-ahead load and interchange was submitted at a

minimum of once a day. 2.2.4.3. Verified that the format of the tag dump met the approved standards. 2.2.4.4. Verified that the IDC and tag dump used the hour-ahead balancing authority

load and interchange for the next hour and utilized the day-ahead load and interchange for the subsequent hours.


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2.2.5. Tag Impacts 2.2.5.1. Verified that the impact of tags should be removed from the market flow

calculation in accordance with the presented process. 2.2.5.2. Verified that tagged exports from the SPP market are accounted for in the

marginal zones, generator mobility factors, etc. 2.2.5.3. Verified that imports are not included in the SPP market flow calculation. 2.2.5.4. Verified that tags with non-market balancing authorities within the SPP

reliability coordinator footprint are treated the same as tags with external balancing authorities.

2.2.5.5. Verified that tag export transfer distribution factor (TDF) calculator from the SPP market are accounted for in the marginal zone and generator mobility factors. No import TDF due to the market structure.

2.2.5.6. Tags with non-market balancing authorities within the SPP market are treated the same as tags with external balancing authorities.

2.2.5.7. NERC needs to notify the industry that the impact files (TDFs) that are posted will be very different with the size and inclusion of point of receipt/point of delivery (POR/POD) factors.

2.2.6. TLR Issuances

2.2.6.1. TLR levels 5A and 5B were issued. 2.2.6.2. Market flow relief and tag curtailments were prescribed by the IDC. 2.2.6.3. Curtailments were entered into the SPP market system and a dispatch was

created to move towards getting the relief necessary for three flowgates. 2.2.6.4. Verified that the IDC excluded the appropriate tags in the relief prescription

that were included in the SPP market flow. 2.2.6.5. Verified that the IDC curtailed the appropriate SPP tags in the relief

prescription that were not included in the SPP market flow.

2.2.7. Market Tools 2.2.7.1. SPP curtailment and adjustment tool (CAT).

2.2.7.1.1. The purpose of this tool is to curtail SPP market schedules during a congestion event in concurrence with the IDC prescription.

2.2.7.1.2. Verified that the tags curtailed by the CAT made it to the SPP market system for inclusion in SPP’s next dispatch cycle.

2.2.7.1.3. Verify SPP interaction with IDC. 2.2.7.1.3.1. SPP data flows were verified in the IRO-006 section. 2.2.7.1.3.2. TLR relief data was sent to CAT and processed.

2.2.7.2. Constraint Manager (CM) 2.2.7.2.1. Verified that a constraint could be manually entered by an operator

and a redispatch to remove flow was sent out through the SPP market system.

2.2.7.2.2. Sent a coordinated external flowgate to the SPP market system from the CM for redispatch purposes.

2.2.7.3. Market Operations System (MOS) 2.2.7.3.1. Ability to adjust NSI for operational conditions


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2.2.7.3.1.1. This is not done usually on the fly, only for special cases and is done by adding schedules or override schedules in the scheduling system. Three NSIs are sent out: energy imbalance market, scheduled and total of the energy imbalance market, and scheduled.

2.2.7.3.2. Auto approve of dispatch case 2.2.7.3.2.1. There is no manual mechanism to stop a dispatch case from

being issued. 2.2.7.3.2.2. Any problems with the dispatch caused by data failure, etc. will

be issued as dispatch instructions. The only method of nullifying this dispatch set is with hotline phone calls or with the SPP internet-based messaging system.

2.2.7.3.2.3. Balancing authority messaging is utilized to indicate to the market participants not to follow the base points or take other actions as the corrupt or invalid dispatch instructions continue to be issued.

2.2.7.3.3. Load forecast 2.2.7.3.3.1. Received a presentation on the mid-term and short-term load

forecast. 2.2.7.3.3.1.1. Have shadow and actual dispatch – NSI is based on shadow

dispatch and base points are based on the actual dispatch. Base points will not sum to the NSI being sent. Base points are an indication of price and schedule.

2.2.7.3.3.1.2. Do have capability to enter a delta into the load forecast to help control dispatch to meet demands. Although this has not been initiated with the operations staff at the time of the verification.

2.2.7.3.4. Joint-Owned Units (JOU) ⎯ Each unit is modeled as a separate unit with separate schedules.

2.2.7.3.4.1. SPP does not allow owners to offer a piece of a JOU physical resource. SPP market participants must offer their piece of the unit as a stand alone unit or have the resource operator offer the entire unit as one resource (SPP Protocols Revision 2.5b, page 66, 11.2.4 Registration of a Joint Owned Unit).

2.2.7.3.4.2. Verified LaCygne, a market generator, which is a JOU, was correctly modeled.

2.2.7.3.4.3. Verified Iatan, a JOU, which is partially in the market (two owners) and partially out of the market, was correctly modeled.

2.2.7.3.5. The MOS solves for forecasted load first and then if possible an activated contingency.

2.2.7.3.6. If a balancing area has not offered enough energy to solve for the forecast load (five-minute dispatch), the MOS will dispatch units beyond its offered energy limit, and the balancing authority NSI continues to change. This is a signal to the balancing authority to obtain energy (purchase energy or start a unit).

2.2.7.3.7. The A and B redundant MOS is designed for a seamless auto failover.


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2.2.7.3.8. Congestion Management 2.2.7.3.8.1. Verified external coordinated flowgate — Issued a TLR, it was

manually entered into MOS and bound. 2.2.7.3.8.2. Verified temporary coordinated flowgate creation — Created a

temporary flowgate and market flow transfer from SPP to IDC took place in less than 48 hours.

2.2.7.3.8.3. Verified new constraint creation (manual constraint entry) — A manual constraint was created in MOS and bound in the SPP market system.

2.2.8. Verify Out of Order Merit Energy (OOME) 2.2.8.1.Verified the tool and how to send out a manual redispatch instruction. 2.2.8.2. A manually entered instruction is sent to the member from this tool, and a

separate XML message is sent to the balancing authority for a single 15-minute period. If additional intervals are needed, the resource plan will be adjusted in MOS to allow the base point to reflect the out of order merit energy dispatch instruction.

2.2.8.3. If OOME is needed for a future interval, the MOS base point is overwritten and used.

2.2.8.4. It is the responsibility of the balancing area to adjust its schedules or its resource plan for the change.

2.2.9. Real-Time Operations Scheduling System (RTO_SS) 2.2.9.1.Verified the RTO_SS will be performing the inadvertent calculations. 2.2.9.2. Verified on an hourly, daily, and monthly basis the on- and off-peak

schedule will be displayed. 2.2.9.3.The balancing authority check outs are displayed and verified in this tool. 2.2.9.4. The system is responsible for sending out the three SPP NSI values for

each balancing area. This is being sent out for the SPP market parallel operations.

2.2.9.5.Schedule adjustments due to IDC and CAT should be processed through this tool.

2.2.9.6. The market participants need to choose how their JOUs are handled in the SPP market, either as a pseudo tie or as a dynamic schedule.

2.2.10. Reserve Sharing System (RSS) 2.2.10.1. Coming out of a RSS event occurs when the schedules from the RSS

expire. No more than 59 minutes in a RSS event. 2.2.10.2. Resource plans, load, and reserve requirements are monitored hourly. 2.2.10.3. RSS is managed by the reliability coordinator. Schedules feed into

RTO_SS, which is then fed to MOS. 3. Operator Training — Review content and records.

3.1. Training Plan 3.1.1. Had a very detailed program model that includes competency-based training.

3.1.1.1. Job task analysis is being created for the new market role and will be maintained.

3.1.1.2. Training curriculum for the market operators are planned to be included in the formal SPP operations training plan in the future.


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3.1.2. Record keeping is done with an access database. 3.1.3. Verified with the training department that the reliability coordinators, operations

engineers, and market operators have received the critical market tool training needed to operate the market tools. Individual tool verification is being conducted by the training department.

4. Operator Market Process and Procedures

4.1. Market Reversion 4.1.1. This plan is active for four weeks after the SPP market implementation loss of

primary site for market.

4.2. Operational Procedures 4.2.1. Process for next-day security assessment has not been finalized. 4.2.2. Off-line generation contingency analysis is performed for seven days into the

future and is run twice a week. 4.2.2.1. SPP is working toward adding generation contingency to the on-line study

capabilities in its control room. No time frame is in place for getting this accomplished at this time.

4.2.3. The ability to move the market to dispatch around a double contingency or N-2 scenario was discussed. There is no specific procedure written around this situation for the SPP market.

4.3. Failure Modes

4.3.1. ICCP — Failure of ICCP is covered in the Market Operator Process Manual, Market Operator Responsibilities, Section 3, paragraphs 3.4.5 – 3.4.8. This covers the market operator side of the failure.

4.4. Market Operation System (MOS) 4.4.1. MOS database servers are configured using clustering technology in a dual-node

environment. MOS uses dual web servers and application servers for the market user interface to the market participants. SPP also uses dual-load balance technology for the web and application servers. For the analytical engines, SPP has six servers running two applications per server. SPP can loose a single server and still function.

4.4.2. SPP covers real-time balancing (RTB) studies not solving for one to six intervals,

(five minutes to thirty minutes) in the market operations procedure. The SPP procedure is to advise the balancing authorities to revert back to actual/scheduled NSI operation if the studies have failed to solve for 30 minutes unless there is a reliability concern. SPP will convert back to NSI earlier in the case of a reliability concern. SPP would also use this procedure for loss of its state estimator if it affected the RTB cases not solving. If the loss of ICCP data, RTO_SS, market flow calculator, or STLF/MTLF caused the RTB cases to fail or solve with incorrect solutions, SPP would follow the same procedure. This is based on the protocols. SPP will advise the shift engineer of the data failure and take care of


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notifying the market participants to return to market NSI at a specific time in the future. The shift engineers are tasked to resolve the data problem.

4.5. RTO_SS ⎯ not verified 4.6. State Estimator (SE)

4.6.1. Failure of SE is covered in the Market Operator Process Manual, Market Operator Responsibilities, Section 3, paragraphs 3.4.5 – 3.4.8. This covers the market operator side of the failure.

4.7. Market Flow

4.7.1. Failure of market flow calculator is covered in the Market Operator Process Manual, Market Operator Responsibilities, Section 3, paragraphs 3.4.5 – 3.4.8. This covers the market operator side of the failure.

4.8. Curtailment and Adjustment Tool (CAT)

4.8.1. The servers for this tool are redundant and vendor hosted. 4.8.2. If the IDC is unable to send the market flow relief responsibility, the value would

be entered manually into CAT. 4.9. Short-Term and Mid-Term Load Forecast (STLF/MTLF)

4.9.1. If STLF fails or is of bad quality for real-time balancing (RTB) solutions, SPP utilizes MTLF hourly data for the five-minute RTB studies.

4.9.2. If MTLF fails or has bad data, SPP utilizes back to participant and/or hourly data for the five-minute RTB studies.


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Appendix A Evaluation of SPP Inadvertent Processes under SPP Market Design

NERC Reliability Standard: BAL-006

Requirement Number Description Comments

R1 Calculate and Record Hourly Inadvertent

SPP has the processes to calculate and record inadvertent hourly, daily on-peak and off-peak, and monthly on-peak and off-peak for each member balancing authority from net schedules and net actual tie flows.

R2 Include all AC tie lines in inadvertent process and take into account JOUs.

Each balancing authority is responsible to include all AC tie lines in the net actual tie flow provided to SPP. JOUs are included in the inadvertent process as Pseudo Ties or Dynamic Schedules.

R3 Common MWH meters and hourly readings obtained

Each balancing authority is responsible to ensure common MWH meters and to include all AC tie lines in the net actual tie flow provided to SPP.

R4.1.1 Agree daily for hourly values of Net Scheduled Interchange

SPP has processes and procedures in place to verify hourly net scheduled interchange with all balancing authorities.

R4.1.2 Agree daily for hourly values of Net Actual Interchange

Each CA is responsible to verify hourly values for net actual interchange.

R4.2 Use agreed to Net Scheduled Interchange and Net Actual Interchange to compute monthly inadvertent On-Peak and Off-Peak

SPP processes use verified net scheduled interchange and verified net actual interchange data supplied from the member balancing authorities.

R4.3 After-the-fact corrections with agreement with other balancing authorities reflected in inadvertent accumulations

SPP processes use verified net scheduled interchange and verified net actual interchange data supplied from the member CA's. After-the-fact corrections can be made per procedure in the SPP RTO Scheduling Process Manual Version 2.2.


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Requirement Number Description Comments

R5 Disagreements between balancing authorities for Net Scheduled Interchange or Net Actual Interchange has report and dispute resolution process

Process and procedure for dispute resolution is detailed in the SPP RTO Scheduling Process Manual Version 2.2.


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Waiver Request - RTO Inadvertent Interchange Accounting

Waiver Content Section Description Comments

Explanation SPP able to manage any financially settled net imbalance with the Interconnection

SPP has the processes to balance inadvertent with the interconnection after financially settling within the SPP Market.

Continued Responsibilities

Member balancing authorities aware of their inadvertent accounting responsibilities post SPP market implementation

SPP may need to notify their Market members of their need to continue inadvertent accounting as they do today.

SPP daily verifies Scheduled Net Interchange and resolves differences within NERC Reliability Standard time frames

SPP processes in place to resolve differences (SPP RTO Scheduling Process Manual Version 2.2)

New Responsibilities

SPP has process in place to financially settle inadvertent with market members

SPP COS (Commercial Operation System) was developed to provide the inadvertent financial settlement function.

SPP calculates net inadvertent balance with Interconnect

SPP RTO_SS system maintains the inadvertent balance with the Interconnect with the SPP boundary.

SPP reports to NERC its inadvertent interchange

SPP reports its inadvertent interchange to NERC (SPP RTO Scheduling Process Manual Version 2.2)

SPP provides AIE data to its balancing authorities

SPP provides this data through the RTO_SS system. Information required by RTO_SS from the COS to complete the data needed for the AIE surveys is 95% complete.


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Waiver Content Section Description Comments

New Responsibilities (Continued)

SPP has process in place for member scheduling inadvertent to reduce inadvertent accumulations outside of SPP market members

SPP has a process in place to manage inadvertent payback between market members and between market members and the Interconnect (SPP RTO Scheduling Process Manual Version 2.2)

Use agreed to Net Scheduled Interchange and Net Actual Interchange to compute monthly inadvertent On-Peak and Off-Peak

SPP RTO_SS uses verified data for inadvertent computations.

SPP reporting of inadvertent accumulations to NERC and record retention

Data is retained in a relational database in current, historical and archived data bases.

SPP has procedures in place for the payback of inadvertent to the interconnect

SPP has a process in place to payback inadvertent payback between market members and between market members and the interconnect (SPP RTO Scheduling Process Manual Version 2.2)


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Area Interchange Error Reporting

Description Comments SPP process for AIE reporting Data required for the reporting on AIE surveys is maintained in RTO_SS and is readily

accessible by the SPP market members.

Lighting the past … powering the future.

415 N. McKinley, 140 Plaza West Little Rock, AR 72205-3020 501-614-3215 • Fax: (501) 664-9553 Lanny Nickell Director, Operations September 8, 2006 James D. Castle Chairman, NERC Operating Reliability Subcommittee Manager of Operations New York Independent System Operator 3890 Carman Road Schenectady, NY 12303 Dear Mr. Castle: During the May 2006 NERC Operating Reliability Subcommittee (ORS) meeting, Southwest Power Pool (SPP) was asked to provide a written response to the Technical Verification Team Report on SPP Market Readiness. The purpose of this letter is to provide the requested response.

According to the report presented to the ORS by Ms. Julie Pierce, the Team indicated three areas in which the SPP should make considerations. Those areas were as follows: tools and process improvements, training, and real-time situational awareness. Each of these areas is addressed below.

Tools and Process Improvements

Operational Process Flow -- SPP has taken the concerns of the Team regarding “operational process flow of a congestion management event” very seriously. SPP has developed process flows between the Market Operations Desk, Shift Engineer Desk, and the Reliability Coordination Desk. Operators and engineers have been training on these processes primarily during the weekly live deployment tests which occur with market participants. These tests have allowed for the SPP personnel to fully understand their roles and responsibilities in day-to-day operational situations. In addition to standard processes (e.g., congestion management), SPP has identified thirty-seven abnormal scenarios on which the operators and engineers are being trained. SPP has included these processes and procedures in the appropriate operational manuals and has incorporated them into the appropriate training plans. Effective Limit Calculator -- SPP has implemented code changes which will automate the effective limit calculator process during congestion management. The new code has been tested and is being utilized in SPP’s live deployment tests.

Lanny Nickell 2 September 8, 2006

Balancing Authority (BA) Ability to Use Market NSI -- During recent deployment tests, SPP has verified that each market BA can utilize the market NSI as deployed by SPP. Each BA has confirmed that they can switch in or out of following the market NSI signal in their ACE equations when needed. This ability is also being tracked via a stakeholder metrics task force looking at the SPP Market deployment tests.

Market System Model Updates – SPP Staff is finalizing the process for market system model updates. The final process will be completed in late-September 2006. This plan will document necessary downtimes and potential impacts of model updates and will control all model changes. System model updates are subject to tightly controlled change management policies.

Job Task Analysis and Job Role Evaluations – As the result of early deployment tests and other testing scenarios, SPP determined that additional operators were needed to handle the work load on the Market Operations Desk. As a result of the evaluations, SPP has hired four (4) additional operators to bring the operator staffing for the Market Operations Desk to a total of ten full-time operators. This staffing level will allow the market desk to have two (2) operators on duty 24x7. Additionally, SPP has a staff of six “floating operators” which have knowledge of all desks and serve as back-up during extraordinarily busy times or in the case of the loss of a staff person.

Review of Auto-Approval of Market Dispatch – SPP has reviewed the current auto-approval of market dispatch and feels that there are sufficient safeguards in place in the event of dispatch anomalies. One such safeguard is the ability for the market operator to drive the dispatch via a system offset value to guard against possible load forecast inaccuracies. Additionally, market operators have been trained to manually override the Energy Imbalance component of the SPP NSI instruction in the event of dispatch solution anomalies. Market participants, via various metrics task forces, are also reviewing that this process is satisfactory. SPP plans to add a future enhancement that will provide the market operators the ability to manually execute a market dispatch solution.

Modeling of Generation Contingencies – SPP currently performs generator contingency analysis in offline models as part of day-to-day operational planning. The market system is designed to handle interaction with the SPP Reserve Sharing Group software (RSS) and provide appropriate re-dispatch for during reserve sharing events. Unit contingencies which may cause thermal or voltage concerns can be modeled by proxy constraints in the market system.

Manual Intervention of Market Dispatch – The SPP Market System allows for SPP Market Operators to manually intervene into the market dispatch. Procedures, roles, and responsibilities for scenarios when this may be required have been documented in the appropriate operational manuals and operators have been and will continue to be trained as necessary.


Training

Site Visits – The Team recommended that SPP Market Operations Staff visit with other market entities (e.g., MISO and/or PJM). The Manager of Market Operations, Mr. Sam Ellis, and the SPP Market Operators spent two days at the Midwest ISO during the week of July 24, 2006. The primary purpose of the visit was to allow the SPP Market Operators to gain an understanding of the day-to-day situations they will be faced with during market operations. The visit provided the Market Operators an opportunity to see the real time market in action, specifically how decisions were made to enter Load Offsets how the offsets were entered and what the results of the studies were with each set of offsets. They were able to observe and understand the interaction between TLR processes and market operations and the impacts of one on the other. They also experienced hands-on operation of the MISO DTS. They made changes to data and viewed the results of those changes in the system. This experience gave the operators a better understanding of why manual inputs to the market are needed and how they can improve the operation of the Market. The Market Operators also were able to see how the charts and graphs at MISO allowed the Operator to better understand what the market was doing and how to control it. Abnormal Scenario Training – As mentioned above, SPP Staff has evaluated approximately 40 abnormal operating scenarios and is training operations center personnel on these scenarios. Many of the scenarios have been encountered during the deployment tests (e.g., tool failure scenarios). In addition, there are plans to include additional scenarios during future deployment tests. Lastly, these scenarios have been incorporated in the standard training regimen for appropriate operations personnel. Training personnel are working with the DTS group to integrate market scenarios into simulations to provide a holistic approach to scenario training.

Additional Training Personnel – SPP has obtained approval from the SPP Board of Directors to hire two additional training personnel. The training department is in the process of filling these positions.

Real-Time Situational Awareness

Graphs for load, generation, schedule, and dispatch trending – SPP has developed and is refining various trending tools for the efficient display of pertinent information. Awareness of the need for several of these graphs came from visiting with other market entities and questioning their operating personnel on the use and effectiveness of each display. The necessary displays have been specified and developed. Further deployment tests will aid in refining these graphs and identifying any additional information the market operators and reliability coordinators feel is relevant and necessary for display. SPP has implemented these displays via third-party software and customized database queries.


SPP has taken the recommendations of the readiness review seriously and has implemented several valuable changes in response to these recommendations. Additionally, SPP Market Participants have placed considerable effort into the development of and measurement against various metrics around the SPP Market Implementation. These stringent metrics address reliability of systems, operational issues, and various other market related activities. Finally, SPP sincerely appreciates the efforts of all those involved and acknowledges the tremendous benefit realized from those efforts. If you require further clarification of any aspect of the SPP Market, please do not hesitate to contact me. Sincerely, Lanny Nickell Director, Operations Cc: NERC Verification Team for SPP Market Readiness

ATTACHMENT III

Gestalt, LLC

Independent Assessment of SPP Market Readiness Metrics

Status Report

December 21, 2006

Readiness Metrics Reporting Summary

• Reporting period December 1, 2006 through December 20, 2006There are 27 Go-Live Metrics being trackedThere have been several deployment tests during this period.Planned outages occurred on 12/15 and 12/16 and monitoring of affected metrics suspended during these periods

• Trend over last two weeks has been consistent and stable in all areas

24 of 27 metrics consistently passing; Three metrics did not pass as of this report:

Metric 26.9 Short term load forecast meeting 1% accuracy standard– The load forecast did meet the 2% accuracy metric (Metric 26.9b)

Metric 26.5 Real time calculations run 7 days consecutively– A planned outage exceeding the 1 hour limit caused this metric to

fail; as of today, the system has passed 4 days in a row.Metric 21.44 submission of interchange data for settlements

– Metric measures submission of data by market participants to SPP– Over the past two weeks, two market participants have consistently

failed to submit their interchange data to SPP

• Total number of open issues is trending downward

24

3

0

5

10

15

20

25

30

12/20/2006

#Met

rics

Pass Fail Update Pend

Comments on current status and trends on Tier 1 Metrics

Metric # Readiness Metric Current Status

14 Day Trend

30-Day Trend Comments

Tier 1 Metrics - Monitored Daily

18.75At least 90% of the online market footprint generation remains within 10% of deployment instructions (or 5 MW, whichever is greater) for at least 85% of the time Results from deployment tests since 12/10/06

18.78Dispatch instructions that relieve a constraint have been sent out within 15 minutes of reporting the constraint (if applicable) Results from deployment tests since 12/10/06

26.3 At least 97.5% of Hour Ahead Balancing Studies solve within 30 minutes

26.3a Day Ahead SFT process completed and results communicated to relevant participants

26.4 At least 99% of 5-minute Real-time Balancing studies solve in less than 5 five minutes

26.5 No more than 3 Real-time Balancing studies fail in a row or use stale data

26.5a Metrics 26.4 and 26.5 pass for at least 7 days consecutively.

This metric had passed for 4 consecutive days until a 5 hour planned outage occurred on 12/15 and 12/16. The system has passed for 4 consecutive days as of 12/21/06.

26.60 Market Operations Portal functionality is available at least 99.5% of the time

26.7 State Estimator has ninety-seven percent (97%) availability of five (5) minute solutions

26.7aState Estimator should not have more than 3 consecutive 5 minute periods of an Invalid Solution

26.8State Estimator solves 90% of the time with Mismatch level lower than 50 MW and with high accuracy

26.8aState Estimator solves 90% of the time with Mismatch level lower than 25 MW for Market footprint

26.8bState Estimator solves 90% of the time with high accuracy (SE MW within 5% of the base rating or < 50 MW (larger of 2 values is target)) for 90% of the selected substations

26.8cState Estimator solves 90% of the time with high accuracy (SE MW within 5% of the base rating or < 50 MW (larger of 2 values is target)) for 50 largest units

26.9 Short term load forecast solves 97% of time with high accuracy (+/- 1%)Metric has passed on average 89% of the time over last two weeks.

26.9a Short term load forecast solves 97% of time with high accuracy (+/- 2%) for BA regions

26.9b Short term load forecast solves 97% of time with high accuracy (+/- 2%) for the entire region

26.10 ICCP availability of 99.5%

26.11 Real-Time EIS Calculations successful ninety-nine percent (99%) of five (5) minute solutions

26.12Market Flow Calculations successful ninety-seven percent (97%) of fifteen (15) minute solutions

Comments on current status and trends on Tier 2 Metrics

Tier 2 Metrics

18.1 100% of Market Control Areas Participate in each deployment test

18.2Market Participants representing at least 80% of Market Footprint Generation participate in final Deployment Control Tests

21.42At least 80% of Market Assets have meter data submitted for each settlement statement produced during the Final Trials testing cycle

21.43At least 80% of Market Loads have meter data submitted for each settlement statement produced during the Final Trials testing cycle

21.44All Control Areas submit Interchange Meter data for each settlement statement produced during the Final Trials testing cycle

Two companies have consistently failed to submit their interchange data to SPP over the period.

21.46Initial, Final, and Resettlement Statements are validated and posted for each Operating Day of the Final Trials testing cycle

21.47Invoices that contain all Settlement Statements from the testing cycle are published in accordance with required timelines during the Final Trials testing cycle

Concluding Remarks

• The SPP systems have consistently met or exceeded the readiness metrics since the completion of the software and hardware fixes implemented to address the system stability issues identified in October.

• Results from recent deployment tests demonstrate that the staff and systems are able to execute the procedures necessary to operate the power system and EIS market.

• There are only a few remaining items on the Go Live issues list to be resolved. Plans are in place to address each of these items prior to the proposed February 1, 2007 Go-Live date.

• Continued parallel operations and deployment tests will only contribute to the staff’s experience and confidence with operating the power system under the EIS market.

ATTACHMENT IV

Southwest Power Pool Market Transition and Reversion

Overview Version 2.0

MAINTAINED BY Southwest Power Pool, Inc.

PUBLISHED: 3/2/06 LATEST REVISION: 12/21/06

Copyright © 2006 by Southwest Power Pool, Inc. All rights reserved.

Revisions

Revision Date

Posted Date

Effective Description of Modification0.1 5/24/2005 Initial draft presented to MITF 0.2 5/31/2005 Draft presented to MWG for

comment 0.3 10/20/2005 Staff review 0.4 12/14/2005 Second round of staff review 0.5 1/12/2006 Third round of staff review 0.6 1/13/2006 Fourth round of staff review 1.0 1/13/2006 Distributed for stakeholder input via

MITF 1.1 1/25/2006 Incorporate feedback from MITF

and internal SPP review for presentation to MWG

1.2 2/27/06 Incorporate feedback from MWG 1.3 3/2/06 Incorporate feedback from MWG

and ORWG and related emails 1.4 5/17/06 Updates to reflect October 1st, 2006

implementation date 1.5 8/2/06 Updates to reflect November 1,

2006 implementation date 2.0 12/13/06 Updates to reflect February 1st,

2007 implementation date, updates to revisions from the ORWG and various cleanup based on project progress.

Market Transition and Reversion Overview, 12/22/2006 ii

1 INTRODUCTION ...........................................................................................1

1.1 OBJECTIVES .............................................................................................1 1.2 TERMINOLOGY ..........................................................................................1

2 TRANSITION COMMUNICATIONS PLAN....................................................2

2.1 STRATEGY................................................................................................2 2.2 RESPONSIBILITIES .....................................................................................2 2.3 STAKEHOLDERS ........................................................................................2 2.4 TOOLS AND TACTICS .................................................................................3 2.5 MESSAGE MATRIX.....................................................................................5 2.6 MARKET PARTICIPANT CONTACTS CHART ...................................................7

3 MARKET TRANSITION RISK ASSESSMENT .............................................8

3.1 ENTRY CRITERIA.......................................................................................8 3.2 TRANSITION ISSUES ESCALATION PLAN.......................................................9

4 TRANSITION TIMELINE OVERVIEW.........................................................10

4.1 KEY ACTIVITIES.......................................................................................10 4.1.1 Plan Transition ..............................................................................10 4.1.2 Prepare Transition .........................................................................10 4.1.3 Practice Transition and Reversion.................................................10 4.1.4 Transition.......................................................................................10

5 SPECIAL ACTIVITIES FOR MARKET TRANSITION.................................12

6 TEMPORARY RULES FOR MARKET TRANSITION .................................13

7 REVERSION PLAN.....................................................................................14

7.1 SCOPE OF REVERSION ............................................................................14 7.2 REVERSION WINDOW ..............................................................................14 7.3 REVERSION PLAN VERSUS SYSTEM OUTAGE PROTOCOLS..........................15 7.4 RESPONSIBILITIES ...................................................................................15

7.4.1 SPP ...............................................................................................15 7.4.2 Balancing Authorities.....................................................................15 7.4.3 Participants....................................................................................15

7.5 COMMUNICATION DURING REVERSION ......................................................15 7.6 RECOMMENCEMENT OF MARKET OPERATIONS ..........................................16

8 MARKET TRANSITION TIMELINE.............................................................17

9 REVERSION PLAN TASKS........................................................................18

10 GLOSSARY.............................................................................................19

Market Transition and Reversion Overview, 12/22/2006 iii

1 Introduction This document describes the methods, procedures and roles used to bring Southwest Power Pool’s (SPP) energy imbalance market online for the purpose of performing financial settlement of imbalance energy. Initial drafts of this document provide an overview of the approach. Details impacting Market Participants will be incorporated as proposed by the SPP Market Implementation Task Force (MITF) and approved by the Market Working Group (MWG) as well as to reflect changes required by SPP’s regulatory authorities.

1.1 Objectives The objectives of this document are as follows:

• Provide the market operations commencement communications plan • Relate the market metrics and associated transition entry criteria to the

market transition process • Outline the process and timeline for transitioning SPP market systems into

financially binding energy imbalance settlements • Outline the respective roles of Market Participants and Balancing Authority

operators during the transition period • Define the criteria and decision process that would be used in determining

whether reversion out of the market is necessary • Outline the respective roles of Market Participants and Balancing Authority

operators should reversion out of the market become necessary

1.2 Terminology This document will generically refer to particular points in time related to the transition using a notation to describe relative times. Terms that describe the transition schedule are as follows:

• TD (“transition day”) shall refer to the first operating day during which settlements shall be financially binding in SPP. This is scheduled to occur on February 1, 2007. “TD-1 day” shall refer to the calendar day prior to the first day of market operations, and “TD-2 days” shall refer to the second calendar day prior to the first day of market operations, etc.

• TH (“transition hour”) refers to the first operating hour during which settlements shall be financially binding in SPP. This is the operating hour ended 0100 Central Prevailing Time on February 1, 2007. “TH-1 hour” shall refer to the hour prior to the first hour of market operations to that operating and “TH-2 hours” shall mean two hours prior to the operating hour, etc.

Market Transition and Reversion Overview, 12/22/2006 1

2 Transition Communications Plan SPP staff will take a formal approach to communicating with participants and other stakeholders throughout the transition process. This plan will be implemented in support of the Market Transition and includes different processes in the event of an emergency or reversion. This approach defines the specific roles, functions, and tools and will be tested in the Transition Walk-Through exercise.

2.1 Strategy Foster an effective transition (or reversion) with prompt, accurate, and timely communication to Market Participants and other key stakeholders.

2.2 Responsibilities • Coordinate communications with SPP Customer Relations staff and

Market Participant communications key contacts (as designated by the Market Participant)

o Customer Relations staff should gather, create, and maintain the various contact lists

o Customer Relations staff will analyze service requests and identify opportunities for FAQ updates

o Communications staff will coordinate critical high-level announcements with Market Participants’ communications designee(s)

• Craft and disseminate information using predetermined modes of communications (email, Alert, e-Newsletter, website, phone call/conference, etc.)

• Coordinate media relations activities including news releases, response to inquiries, tracking, and archiving

• Communicate urgent information in the event of an emergency during the transition period

2.3 Stakeholders SPP must gather contact information for the following stakeholders. This information will be collected and maintained by SPP’s customer relations staff.

• Market Participants • Executives: SPP, Market Participants, etc. • Balancing Authority and First Tier Operations • SPP Market Project Team • SPP Organizational Groups

o Board of Directors o Market Operations and Policy Committee o Market Working Group o Market Implementation Task Force o Settlements Data and Metering Task Force


o Regional Tariff Working Group o Market Operations Readiness Tools Task Force o Operating Reliability Working Group o Critical Infrastructure Protection Task Force

• Other SPP employees • NERC, FERC, and State Regulatory Authorities • Bond Raters and Analysts • Media

2.4 Tools and Tactics 1. Contact Lists 2. Email Exploder Lists 3. Open Line for Reliability Information

a. SPP will host a teleconference for Balancing Authorities for at 0000 TD-1 through approximately 1200 TD. Balancing Authorities should be dialed in continuously and use this for two-way communication related to issues around the market transition. Only Balancing Authorities and reliability authorities authorized to receive sensitive information may participate in this call.

4. Open Line for Market Participants and Other Stakeholders a. SPP will host a teleconference for Market Participants and other

stakeholders from 0000 TD-1 through approximately 1200 TD. Market participants may dial in continuously or as needed for two-way communication related to the market transition. Any stakeholder may participate in this process; however, SPP will require that participants register with them beforehand.

5. Periodic Status Update Teleconferences a. SPP will host teleconferences at the following scheduled times.

Additional teleconferences may be scheduled as needed. i. Daily (including weekends) at 1500 TD – 6 through TD + 7

1. Discuss issues related to market operations ii. Monday through Friday TD+8 to TD+14

1. Discuss operations issues and transition to discussion of settlement issues

iii. The first Monday and Wednesday after TD+14 b. SPP will publish a meeting summary after conclusion of

teleconferences. 6. Third-party Communications Distribution: Message911 (backup purposes)

a. Email, voicemail 7. Market Update e-Newsletter and Market Alerts

a. After each Go / No Go meeting, SPP will communicate, via the Market section of its website and via the Market Operations Announcements and Settlements Announcements email lists, a final determination of whether or not market operations will commence as scheduled.

8. Direct Telephone Calls



9. Audio and Net Conferences 10. Website - spp.org

a. A special market transition page on SPP.org will be updated with documents and announcements concerning the transition process, including the Go / No Go materials.

11. News Releases 12. Message Matrix

2.5 Message Matrix Single Market Participants Multiple Market Participants / Don't Know

Primary Secondary Email List

Type of Message Sender

Contact Type Contact Type Market

Operations Announcements

Settlements Announcements

Market Monitoring

Announcements Reve

Announc

System Issues and Announcements

Market Operations Desk X X

Functional Issues and Announcements

Market Operations Desk

- Resource Plans


Real Time 24 Hour POC / Primary POCs / Generation Dispatch Desk

Real Time 24 Hour POC / Secondary Contacts / Generation Dispatch Desk X

- Offer Curves Market Operations Desk

Real Time 24 Hour POC / Primary POCs / Hourly Trading Desk

Real Time 24 Hour POC / Secondary Contacts / Hourly Trading Desk X

- A/S Capacity Plans


Real Time 24 Hour POC / Primary POCs / Generation Dispatch Desk

Real Time 24 Hour POC / Secondary Contacts / Generation Dispatch Desk X

- Load Forecasts

Market Operations Desk X

- Registration & Modeling


Primary Point of Contact

Secondary Point of contact X

- Settlements Settlements Settlements N/A X - Invoicing Accounting Invoicing N/A X - Financial Accounting Financial Transfer N/A X


Market Transition and Revers

Transfer - Credit Credit Credit N/A X

- Metering Settlements Metered Data Submission N/A X

- Market Scheduling Scheduling Desk X - Market Monitoring IMM X X

- Pricing / LIPs Settlements or Operations Settlements N/A X

- Offer Caps IMM

Real Time 24 Hour POC / Primary POCs / Hourly Trading Desk

Real Time 24 Hour POC / Secondary Contacts / Hourly Trading Desk X X

Transition Operations Primary Point of Contact

Secondary Point of Contact X X

Reversion Market Operations Desk

Primary Point of Contact

Secondary Point of Contact X X X X

Press Releases Communications Communications Manager N/A

Executive Issues Communications MOPC POC N/A

Communication Method (in order):

Work Phone #, Cell Phone #, Pager, email Communication Method:

Email for Primary; Backup as Appropriate

ion Overview, 12/22/2006 6

2.6 Market Participant Contacts Chart

Southwest Power Pool Market Participant Point of Contact Chart

7/25/06

Contact Type Market

Operations

Settlements

Market Monitoring Reversion

Primary Point of Contact • • • • Secondary Point of Contact • • • • Project Manager (SPP EIS Market) • • • •

MOPC POC • • • • MOPC POC • • • • Metered Data Submission •

Metered Data Submission •

Metered Data Submission •

Market Operations •

Resource Data Exchange • •



Real Time 24 Hour POC •

Primary Contact

Generation Dispatch Desk •

Hourly Trading Desk • •

Shift Supervisor Desk •

Secondary Contact

Generation Dispatch Desk •

Hourly Trading Desk • •

Shift Supervisor Desk •

Control Area Supervisor POC •

3rd Party Scheduler •

Settlements • •

Invoicing •

Billing •

Credit •

Financial Transfer •

MITF Representative • • • • MITF Representative • • • • Communications Manager • • ICCP Data Exchange • Operational Network Model • Vendor • • • •


3 Market Transition Risk Assessment In order to minimize the risk of problems during the transition, certain criteria have been established that must be satisfied before the commencement of the transition process. As part of the transition planning effort, a market reversion plan is included to smoothly revert out of the new market activities. The goal of this plan is to restore the functions and activities that SPP supports to the level at which they operated just prior to the market transition.

3.1 Entry Criteria Several factors will be assessed as part of making the determination of whether or not to proceed through the market transition process. The entry into the transition process will be governed by the Go / No Go Process which consists of a Go / No Go Advisory Team and Go / No Go input information. The Go / No Go Advisory Team will consist of the Chairs, or their designees, of the following SPP groups: MOPC ORWG MWG MITF MOTRTF SPP Staff BOD RSC SPC The Go / No Go input information will be comprised of information from the following sources:

• Grid operations information • Metrics information from the current Tier 1 metrics as it is currently tracked

(which is comprised of both systems and market operations indicators) • Transition plan progress information based on progress against the

transition work plan SPP will also have additional criteria that might also be considered during the transition period. The criteria are intended to capture items upon which the market transition may pose unacceptable risk on the bulk electric system. The criteria will generally address:

• Risks imposed by severe weather or other acts of God • Extreme congestion, unusual demand patterns, or other issues with

the bulk electric system • SPP market systems providing solutions with anomalous results


• Other technical or process issues not previously identified

3.2 Transition Issues Escalation Plan If an urgent issue arises during the transition period that cannot be promptly resolved utilizing normal communication channels, SPP executives or participant executives may be contacted to assist in resolving the issue. Other market participation issues may be dealt with using pre-established procedures available through dispute resolution options found within any applicable tariffs, etc.


4 Transition Timeline Overview SPP has formulated a detailed work plan to manage its role in the transition process. Participants are encouraged to create similar work plans for their organizations and include SPP milestones impacting them in their plans. To facilitate integration of the document into other workplans, SPP will provide the document as a Microsoft Excel workbook.

4.1 Key Activities SPP’s work plan tasks are grouped into the following categories that represent the major phases of the transition process:

• Plan for Transition • Prepare for Transition • Practice Transition • Transition • Post Transition

4.1.1 Plan Transition Tasks associated with transition planning include soliciting stakeholder input via the MITF, MWG, ORWG and MOPC on transition and reversion processes and finalizing the approach and transition timeline documentation.

4.1.2 Prepare Transition Tasks associated with transition preparation include configuring system parameters, initializing data, and preparing final staffing plans to support system go-live. Although some of these tasks may be executed early, the bulk of them will be performed during the period TD-28 through TD-6.

4.1.3 Practice Transition and Reversion SPP will conduct both an internal talk-through and a practice transition during system-wide live deployment tests. System outage and reversion plans will also be practiced during this time. Although participants will be involved by virtue of responding to SPP’s deployment signal as part of these practice sessions, participants will not have a role in other transition activities. SPP will conduct a walk-through with external participants prior to Transition. During the last system-wide live deployment test, SPP will conduct a practice transition and market reversion with full participant involvement. Participant involvement in both of these is required.

4.1.4 Transition The transition period is the period between when SPP’s market systems are available to accept production data (TD-6) and the time when financially binding market settlements apply (TH). As this phase begins, SPP will provide a status


report in support of a “go/no-go” decision, and communications will ramp up throughout the period culminating in hourly checkpoints during the few hours before and after TH. TH will be scheduled to begin at midnight. If a decision is made to delay TD beyond February 1, 2007, midnight will continue to be used as the TH. Throughout this phase SPP will be operating in parallel to all current operations and will monitor and address issues as they arise. As a strategy to mitigate risk around TH, SPP will ensure the data is sufficient for systems to operate. As a result, participants must enter preliminary production data prior to the deadlines allowed during the market timeline established in the protocols.


5 Special Activities for Market Transition To ensure a smooth transition, participants must adhere to a special timeline for the period TD-6 through TD+1. This timeline is distinct from the timeline outlined in the market protocols. This requirement is temporary yet necessary to minimize risks and ensure a smooth transition to financially binding settlements. Tasks associated with the transition appear on the Market Transition Timeline. Following are some key activities addressed in the transition plan:

a) SPP will begin sending out market solution data at least 24 hours prior to TH. Although Market Participants and Balancing Authorities will be receiving deployment instructions and Energy Imbalance NSI, they should not control to these instructions until specified on the Market Transition Timeline. Market Participants and other stakeholders should monitor the operation of various SPP market systems and raise any issues to the SPP Transition Coordinator.

b) Balancing Authorities, Reliability Coordinators, and JOA parties will begin utilizing market processes on TH-4 hours.

c) Market Participants will begin following SPP deployment instructions on TH-3 hours.

d) Resource plans for TD must be entered no later than TD-6 for SPP market resources. This process should continue daily such that, on TD-5, the resource plans for TD+1 day have been entered.

e) Offer curves for TD must be entered no later than TD-6 for SPP market resources.

f) Ancillary service capacity plans for the TD must be entered no later than 1100 on TD-1. Plans must be valid no later than 1300 on TD-1.

g) By 1300 on TD-1, resource plans and offer curves for TD should be up to date. Any changes occurring after this point should be only those that reflect unanticipated status changes for resources

h) Participants should have schedules entered into the appropriate tools to the extent possible by 1300 on TD-1. Schedules for TH must be entered no later than 2330 on TD-1

i) Participants should plan to have key staff on hand to anticipate and resolve market operations issues.

Although participants must submit data early, they may continue to update and change data in accordance with the regular market timelines.


6 Temporary Rules for Market Transition SPP staff will request assistance from stakeholders (e.g. the ORWG) in the identification and mitigation of market transition risks that could compromise system reliability. As a result, the reviewers may propose special rules around the transition from pre- to post-market operations. These may include (1) making a certain level of energy available to the SPP market around the transition time, (2) requirements to make offer curves consistent with unit operations just for transition, and (3) requirements or guidelines for additional operating and/or regulation reserves. During the 12/12/06 ORWG (Operations Reliability Working Group) meeting, the ORWG elected to require SPP’s reserve requirement to be increased to be the two largest units in the RSG (Reserve Sharing Group) footprint for the first 3 days of market operations.


7 Reversion Plan The main goal of SPP’s reversion planning activities is to reverse the market transition and utilize the business processes in place just prior to the market transition for a variety of reasons. Since the FERC has required other RTOs to have such plans in place, SPP has prepared a plan than can be utilized for this purpose. Beginning three hours prior to and continuing for at least four weeks after market go-live, SPP and participants must be prepared to implement the market reversion plan. This section details the steps taken if a situation arises that necessitates reversion to pre-market systems and processes. The reversion plan would be implemented in the event that: (1) SPP's ability to reliably and accurately dispatch and settle the market in accordance with the tariff and other applicable business rules (such as the protocols) is compromised; and (2) there is no viable work-around that can be implemented until the underlying system functionality is resolved. In the event a reversion plan is executed SPP will make any filings as necessary and required by any regulating authority. Instructions and other vital information regarding reversion will be sent out via the Reversion email exploder.

7.1 Scope of Reversion The scope of reversion is limited since most of SPP’s existing business processes are not impacted by the market implementation. There are several major items that must be addressed within the reversion plan.

• Market participants must return to scheduling practices in place just prior to the market transition and disregard SPP-issued deployment signals. Market participants must be able to FTP resource plan information in parallel with market system resource plan submissions throughout the reversion window.

• Balancing Authorities must revert to NSI signals in place prior to the market transition and disregard the new NSI signals related to energy imbalance deployment. SPP will maintain the original NSI signals during the reversion window.

• SPP will revert to congestion management processes in place just prior to the market transition.

7.2 Reversion Window The reversion window is four weeks from TD.


7.3 Reversion Plan versus System Outage Protocols SPP’s market protocols anticipate brief system outages. SPP anticipates that it will implement its system outage plan prior to making a reversion determination.

7.4 Responsibilities During the reversion window it is crucial that SPP, Market Participants and Balancing Authorities maintain existing data and business processes to the fullest extent possible to facilitate a smooth reversion.

7.4.1 SPP SPP will maintain existing systems and business processes throughout the reversion window and, to the fullest extent possible, keep them online and in production. Also during that time, SPP will continue to provide participants and Balancing Authorities data necessary for activities in place prior to the market transition.

7.4.2 Balancing Authorities During the reversion window Balancing Authorities must continue to accept the RTO_SS one-minute NSI values provided by SPP via ICCP. Balancing Authorities receiving alternate feeds of scheduling data should continue to receive that data and, to the fullest extent possible, keep the systems that utilize that data online and in production. In the event of reversion, Balancing Authorities should be able to disregard the 4-second Energy Imbalance NSI signal and be prepared to utilize the one-minute RTO_SS NSI should it be necessary to do so.

7.4.3 Participants During the reversion window Market Participants must be prepared to operate as they did prior to the market transition. They must maintain the ability to: (1) resort to bilateral arrangements for receiving energy imbalance service and (2) to operate at bilaterally scheduled amounts without regard to SPP’s deployment instructions. Market Participants must maintain any systems necessary to support their operations prior to the market transition and, to the fullest extent possible, keep these systems online and in production.

7.5 Communication During Reversion SPP will utilize the following process if a market reversion becomes necessary:

• Reversion email exploder: messages will be sent to SPP market email lists.

• Text Posting to SPP’s OASIS • Text Posting on the Market Portal (if systems are available) • Text Posting on spp.org transition page


• Operator Notification via the Market Portal (if systems are available) • Notification of Balancing Authorities utilizing SPP’s satellite phone

system • Notification of Market Participants utilizing 24-hour contact

information provided to SPP in MP Contacts Chart • Notification of NERC and other Reliability Coordinators via the NERC

RCIS • Joint Operating Agreement parties via telephone

Communications issued by SPP will include reversion instructions and the time those tasks will occur.

7.6 Recommencement of Market Operations Any recommencement of Market Operations after a reversion will be treated as a new market implementation and require issuance of an associated market implementation schedule, after receipt of stakeholder input.


8 Market Transition Timeline


ID Task Name Duration Start Finish

1 Production Transition (Planning Tasks) 273 days Fri 1/13/06 Wed 1/31/072 Net Scheduled Interchange (4-Second RTO_SS NSI) 101 days Fri 1/27/06 Fri 6/16/06

3 Transition to 4-second RTO_SS NSI 71 days Fri 6/23/06 Mon 10/2/06

4 Prepare Transition Communications 273 days Fri 1/13/06 Wed 1/31/075 System Changes Freeze Date (Production Market System) 0 days Fri 1/5/07 Fri 1/5/07

6 Prepare Go / No Go Packet 0 days Fri 12/22/06 Fri 12/22/06

7 Review Go / No Go Packet with MWG 0 days Fri 1/13/06 Fri 1/13/06

8 Prepare / confirm contact lists as outlined in the communications plan 147 days Wed 3/1/06 Thu 9/21/06

9 Hold MITF meeting to review final details of cutover and transition 0 days Thu 1/18/07 Thu 1/18/07

10 Confirm control area and first tier operations contacts for transition (24x7) 0 days Wed 1/31/07 Wed 1/31/07

11 Confirm market participant operations contacts for transition (24x7) 0 days Wed 1/31/07 Wed 1/31/07

12 Confirm NERC / FERC / State Regulator contacts for transition 0 days Wed 1/31/07 Wed 1/31/07

13 Confirm executive contacts for all market participants for transition (24x7) 0 days Wed 1/31/07 Wed 1/31/07

14 Assemble SPP Staff contacts for transition (24x7) 0 days Wed 1/31/07 Wed 1/31/07

15 Reserve and distribute cutover conference call information 0 days Wed 1/24/07 Wed 1/24/07

16 Prepare SPP 0 days Fri 12/22/06 Fri 12/22/0617 Develop reversion and go / no go templates. 0 days Fri 12/22/06 Fri 12/22/06

18 Prepare Participants 10 days Fri 1/5/07 Thu 1/18/0719 Re-Distribute transition plan to neighboring control areas for feedback 6 days Fri 1/5/07 Fri 1/12/07

20 Finalize the participant review and confirmation of the transition plan through the MITF. 0 days Thu 1/18/07 Thu 1/18/07

21 Production Reversion (Planning Tasks) 340 days Tue 9/27/05 Mon 1/15/0722 Develop criteria for implementing reversion 1 day Fri 12/29/06 Fri 12/29/0623 Develop reliability criteria for implementing reversion 1 day Fri 12/29/06 Fri 12/29/06

24 Develop process and documentation trail for implementing reversion 1 day Fri 12/29/06 Fri 12/29/06

25 Determine regulatory filing plan for reversion 1 day Fri 12/29/06 Fri 12/29/06

26 Prepare communications 68 days Thu 8/31/06 Mon 12/4/0627 Develop communications scripts for reversion press release 16 days Thu 8/31/06 Thu 9/21/06

28 Develop communications scripts for reversion email to exploder lists 3 days Thu 11/30/06 Mon 12/4/06

29 Develop communications scripts for reversion message on portal 3 days Thu 11/30/06 Mon 12/4/06

30 Review communications scripts with communications department 17 days Thu 8/31/06 Fri 9/22/06

31 Socialize reversion criteria and true-up process 0 days Mon 1/15/07 Mon 1/15/07

1/5

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Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 22005 2006 2

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Energy Imbalance MarketTransition Schedule: Fri 12/22/06

© 2006 Accenture LLP. All Rights Reserved. Page 1 of 6

Project: Transition Task List External.mDate: Fri 12/22/06


32 Review criteria and post-reversion processes with MITF 0 days Mon 1/15/07 Mon 1/15/07

33 Review criteria and post-reversion processes with MWG 0 days Mon 1/15/07 Mon 1/15/07

34 Review criteria and post-reversion processes with ORWG 0 days Mon 1/15/07 Mon 1/15/07

35 Develop detailed reversion plans (for systems) 324 days Tue 9/27/05 Fri 12/22/0636 Confirm the approach for reverting out of MOS 5 days Fri 12/15/06 Fri 12/22/06

37 Confirm the approach for reverting out of CAT and the IDC 26 days Mon 9/11/06 Mon 10/16/06

38 Confirm the approach for reverting out of JOA 133 days Mon 2/27/06 Wed 8/30/06

39 Create approach for indicating unavailability of energy imbalance NSI (assess whether R 31 days Fri 11/3/06 Fri 12/15/06

40 Confirm the approach for reverting out of MFC 174 days Tue 4/18/06 Fri 12/15/06

41 Confirm the approach for reverting out of NNL 2 days Mon 2/27/06 Tue 2/28/06

42 Confirm that there are no impacts for reverting out of RSS 2 days Mon 2/27/06 Tue 2/28/06

43 Confirm that there are no impacts for reverting out of RTO_SS and NLS (including susp 26 days Mon 8/28/06 Mon 10/2/06

44 Confirm the approach for reverting out of COS 214.5 days Mon 2/27/06 Fri 12/22/06

45 Confirm the approach for reverting out of MMA 110 days Tue 9/27/05 Mon 2/27/06

46 Confirm that there are no impacts for reverting out of CMS 2 days Mon 2/27/06 Tue 2/28/06

47 Confirm that there are no other finance impacts 2 days Mon 2/27/06 Tue 2/28/06

48 Confirm the approach for reverting out of OPS1 (including resource plans submissions) 81 days Fri 2/10/06 Fri 6/2/06

49 Confirm the approach for reverting out of EMS 129 days Tue 6/27/06 Fri 12/22/06

50 Confirm the approach for settling losses 13 days Wed 8/30/06 Fri 9/15/06

51 Document reversion process 220 days Mon 2/27/06 Fri 12/29/0652 Document the reliability reversion process 220 days Mon 2/27/06 Fri 12/29/06

53 Document the NSI reversion process 133.5 days Wed 5/31/06 Mon 12/4/06

54 Update the inadvertent reversion payback process 116 days Mon 2/27/06 Mon 8/7/06

55 Production Transition 313 days Wed 1/18/06 Fri 3/30/0756 System Changes Freeze Date (Production Market System) 0 days Fri 1/5/07 Fri 1/5/07

57 Ask participants to continue submitting Resource Plans via FTP and MOS "until further notice 11 days Wed 1/10/07 Wed 1/24/07

58 TD - 2 Weeks 266 days Wed 1/18/06 Wed 1/24/0759 Prepare Systems for Transition 266 days Wed 1/18/06 Wed 1/24/0760 Add messages to SPP.org and Market Portal Pages 1 day Wed 1/18/06 Wed 1/18/06

61 Confirm Systems are Online and Operational using Production Verification Checklis 0 days Wed 1/24/07 Wed 1/24/07

62 Hold First Go / No Go Decision 0 days Wed 1/24/07 Wed 1/24/07

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63 Hold Go / No Go meeting with SPP and participants to confirm Go / No Go de 0 days Wed 1/24/07 Wed 1/24/07

64 Hold conference call to confirm Go / No Go and review portions of executive p 0 days Wed 1/24/07 Wed 1/24/07

65 Post Go / No Go decision to web site 0 days Wed 1/24/07 Wed 1/24/07

66 Participants Expected to be Using 4-Second NSI 1 day Wed 1/24/07 Wed 1/24/07

67 TD - 7 Days 1 day Thu 1/25/07 Thu 1/25/0768 Confirm Systems are Online and Operational using Production Verification Checklist 1 day Thu 1/25/07 Thu 1/25/07

69 Market Open for Submission of A/S Plans 0 days Thu 1/25/07 Thu 1/25/07

70 Market Open for Submission of Resource Plans 0 days Thu 1/25/07 Thu 1/25/07

71 Market Open for Submission of Offers 0 days Thu 1/25/07 Thu 1/25/07

72 Market Open for Submission of Load Forecasts 0 days Thu 1/25/07 Thu 1/25/07

73 Set uninstructed deviation lockout so resources are not locked out during the transition 0 days Thu 1/25/07 Thu 1/25/07

74 Announce commencement of transition via email distribution lists. 0 days Thu 1/25/07 Thu 1/25/07

75 Submit resource plans (via both FTP and market system) for TD - 2 day, TD - 1 day and 0 days Thu 1/25/07 Thu 1/25/07

76 Begin Parallel Period for Market Participants to FTP resource plans 0 days Thu 1/25/07 Thu 1/25/07

77 Submit offers for TD - 1 day and TD 0 days Thu 1/25/07 Thu 1/25/07

78 Manually validate that resource plans have been submitted for all resources for TD - 2 d 0 days Thu 1/25/07 Thu 1/25/07

79 Manually validate that offers have been submitted for all resources for TD - 1 day and T 0 days Thu 1/25/07 Thu 1/25/07

80 TD - 6 Days 1 day Fri 1/26/07 Fri 1/26/0781 Confirm Systems are Online and Operational using Production Verification Checklist 1 day Fri 1/26/07 Fri 1/26/07

82 Submit resource plans (via both FTP and market system) for TD + 1 0 days Fri 1/26/07 Fri 1/26/07

83 Manually validate that resource plans have been submitted for all resources for TD and 0 days Fri 1/26/07 Fri 1/26/07

84 Manually validate that offers have been submitted for all resources for TD and TD + 1 a 0 days Fri 1/26/07 Fri 1/26/07

85 TD - 5 Days 0 days Sat 1/27/07 Sat 1/27/0786 Confirm Systems are Online and Operational using Production Verification Checklist 0 days Sat 1/27/07 Sat 1/27/07

87 Send email reminder to continue to submit offers and resource plans according to the tr 0 days Sat 1/27/07 Sat 1/27/07

88 Submit resource plans (via both FTP and market system) for TD + 1 day 0 days Sat 1/27/07 Sat 1/27/07

89 Submit offers for TD + 1 day 0 days Sat 1/27/07 Sat 1/27/07

90 Manually validate that resource plans have been submitted for all resources for TD + 1 d 0 days Sat 1/27/07 Sat 1/27/07

91 Manually validate that offers have been submitted for all resources for TD + 1 day and a 0 days Sat 1/27/07 Sat 1/27/07

92 TD - 4 Days 0 days Sun 1/28/07 Sun 1/28/0793 Confirm Systems are Online and Operational using Production Verification Checklist 0 days Sun 1/28/07 Sun 1/28/07

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94 Send email announcement that offer curve submission timeframes revert back to norma 0 days Sun 1/28/07 Sun 1/28/07

95 Submit resource plans (via both FTP and market system) for TD + 2 days 0 days Sun 1/28/07 Sun 1/28/07

96 TD - 3 Days 1 day Mon 1/29/07 Mon 1/29/0797 Confirm Systems are Online and Operational using Production Verification Checklist 0 days Mon 1/29/07 Mon 1/29/07

98 Submit resource plans (via both FTP and market system) for TD + 3 days 1 day Mon 1/29/07 Mon 1/29/07

99 TD - 2 Days 1 day Tue 1/30/07 Tue 1/30/07100 Confirm Systems are Online and Operational using Production Verification Checklist 0 days Tue 1/30/07 Tue 1/30/07

101 Submit resource plans (via both FTP and market system) for TD + 4 days 1 day Tue 1/30/07 Tue 1/30/07

102 Post A/S obligations for TD - 1 day 1 day Tue 1/30/07 Tue 1/30/07

103 Submit A/S plans for TD - 1 day 1 day Tue 1/30/07 Tue 1/30/07

104 Validate RPV study and support modifications to TD - 1 day according to market timelin 1 day Tue 1/30/07 Tue 1/30/07

105 Perform Congestion Management study for TD - 1 day 1 day Tue 1/30/07 Tue 1/30/07

106 Validate with participants that they are receiving deployment instructions via their listene 1 day Tue 1/30/07 Tue 1/30/07

107 Submit resource plans (via both FTP and market system) for TD + 5 days 1 day Tue 1/30/07 Tue 1/30/07

108 Hold Second Go / No Go Decision 1 day Tue 1/30/07 Tue 1/30/07109 Hold conference call to confirm Go / No Go and review portions of executive packe 1 day Tue 1/30/07 Tue 1/30/07

110 Post Go / No Go decision to web site 1 day Tue 1/30/07 Tue 1/30/07

111 TD - 1 Day 1 day Wed 1/31/07 Wed 1/31/07112 Confirm Systems are Online and Operational using Production Verification Checklist 0 days Wed 1/31/07 Wed 1/31/07

113 Open conference lines for Market Participants 1 day Wed 1/31/07 Wed 1/31/07

114 Submit resource plans (via both FTP and market system) for TD + 6 days 1 day Wed 1/31/07 Wed 1/31/07

115 Post A/S obligations for TD 1 day Wed 1/31/07 Wed 1/31/07

116 Submit A/S plans for TD 1 day Wed 1/31/07 Wed 1/31/07

117 Validate RPV study and support modifications to TD according to market timeline 1 day Wed 1/31/07 Wed 1/31/07

118 Perform Congestion Management study for TD 1 day Wed 1/31/07 Wed 1/31/07

119 Hold Third (Final) Go / No Go Decision 0 days Wed 1/31/07 Wed 1/31/07120 Hold conference call to confirm Go / No Go and review portions of executive packe 0 days Wed 1/31/07 Wed 1/31/07

121 Post Go / No Go decision to web site 0 days Wed 1/31/07 Wed 1/31/07

122 TD - 4 Hours 30 Minutes 1 day Wed 1/31/07 Wed 1/31/07123 Reliability and Market Participant conference calls begin 1 day Wed 1/31/07 Wed 1/31/07

124 TD - 4 Hours 1 day Wed 1/31/07 Wed 1/31/07

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125 Perform reliability assessment involving control areas and other reliability coordinators t 1 day Wed 1/31/07 Wed 1/31/07

126 Notify NERC, JOA partners and their reliability coordinators to confirm SPP's intent to go 1 day Wed 1/31/07 Wed 1/31/07

127 TD - 3 Hours 1 day Wed 1/31/07 Wed 1/31/07128 SPP performs roll call readiness survey of all control areas 1 day Wed 1/31/07 Wed 1/31/07

129 Send communication announcing that this is the beginning of the period that the reversi 1 day Wed 1/31/07 Wed 1/31/07

130 Begin parallel operations period 1 day Wed 1/31/07 Wed 1/31/07

131 TD - 30 Minutes 1 day Wed 1/31/07 Wed 1/31/07132 Implement final IDC change orders in Production 1 day Wed 1/31/07 Wed 1/31/07

133 CAT Transition 1 day Wed 1/31/07 Wed 1/31/07

134 TD - 5 Minutes 1 day Wed 1/31/07 Wed 1/31/07135 Perform assessment to confirm resources are being deployed consistent with expectatio 1 day Wed 1/31/07 Wed 1/31/07

136 Confirm Go decision internally and externally 1 day Wed 1/31/07 Wed 1/31/07

137 IDC brought up with CO-189 and CO-193 Implemented 1 day Wed 1/31/07 Wed 1/31/07

138 Transition Day 30 days Mon 12/25/06 Fri 2/2/07139 Transition Hour + 1 Hour 1 day Thu 2/1/07 Thu 2/1/07

140 Begin using regular escalation plan for pricing / operational issues 1 day Thu 2/1/07 Thu 2/1/07

141 Begin using defined timeline for submission of offers and A/S Plans 1 day Thu 2/1/07 Thu 2/1/07

142 Begin using defined timeline for submission of resource plans, which should continue to 1 day Thu 2/1/07 Thu 2/1/07

143 Commence hourly checkpoints with all control areas to review operational issues 1 day Thu 2/1/07 Thu 2/1/07

144 Inadvertent Cleared 30 days Mon 12/25/06 Fri 2/2/07

145 TD + 1 Day 1 day Fri 2/2/07 Fri 2/2/07146 Purge non-binding LIP and SLIP data from SPP.org through 1/30 (retain 1/31 data) 1 day Fri 2/2/07 Fri 2/2/07

147 Send press release on successful market cutover 1 day Fri 2/2/07 Fri 2/2/07

148 MITF / MWG Technical and Issues Call 1 day Fri 2/2/07 Fri 2/2/07

149 ORWG Issues Call 1 day Fri 2/2/07 Fri 2/2/07

150 TD + 2 Days 1 day Fri 2/2/07 Sat 2/3/07151 Cease hourly checkpoints with all control areas to review operational issues 1 day Fri 2/2/07 Sat 2/3/07

152 MITF / MWG Technical and Issues Call 1 day Fri 2/2/07 Sat 2/3/07

153 ORWG Issues Call 1 day Fri 2/2/07 Sat 2/3/07

154 Close conference line 1 day Fri 2/2/07 Sat 2/3/07

155 Reset uninstructed deviation lockout period back to standard (6 intervals) 1 day Fri 2/2/07 Sat 2/3/07


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156 TD + 4 Days 1 day Mon 2/5/07 Mon 2/5/07157 Submit meter actual data to portal for TD by noon 1 day Mon 2/5/07 Mon 2/5/07

158 Continue to submit meter actual data by this deadline for all operating days going forwa 1 day Mon 2/5/07 Mon 2/5/07

159 TD + 5 Days 1 day Tue 2/6/07 Tue 2/6/07160 Post settlements to the portal 1 day Tue 2/6/07 Tue 2/6/07

161 Commence standard settlements processes and timelines 1 day Tue 2/6/07 Tue 2/6/07

162 TD + 7 Days 1 day Thu 2/8/07 Thu 2/8/07163 Create and distribute first invoice 1 day Thu 2/8/07 Thu 2/8/07

164 Commence standard invoicing process and timelines 1 day Thu 2/8/07 Thu 2/8/07

165 TD + 13 Days 1 day Wed 2/14/07 Wed 2/14/07166 Perform funds transfer for market participants owing money 1 day Wed 2/14/07 Wed 2/14/07

167 Commence standard funds transfer processfor participants owing money 1 day Wed 2/14/07 Wed 2/14/07

168 TD + 15 Days 1 day Fri 2/16/07 Fri 2/16/07169 Perform funds transfer for market participants owed money 1 day Fri 2/16/07 Fri 2/16/07

170 TD + 46 Days 1 day Mon 3/19/07 Mon 3/19/07171 Post final settlement to the portal 1 day Mon 3/19/07 Mon 3/19/07

172 TD + 49 Days 1 day Thu 3/22/07 Thu 3/22/07173 Create and distribute invoice for final settlement 1 day Thu 3/22/07 Thu 3/22/07

174 TD + 55 Days 1 day Wed 3/28/07 Wed 3/28/07175 Perform funds transfer for market participants owing money 1 day Wed 3/28/07 Wed 3/28/07

176 TD + 57 Days 1 day Fri 3/30/07 Fri 3/30/07177 Perform funds transfer for market participants owed money 1 day Fri 3/30/07 Fri 3/30/07

178 TD + 59 Days 1 day Fri 3/30/07 Fri 3/30/07179 Disable FTP for Resource Plans and Unit Commitment (ONLY for Market Participa 1 day Fri 3/30/07 Fri 3/30/07180 Ask MPs to discontinue submitting Resource Plans via FTP 1 day Fri 3/30/07 Fri 3/30/07

181 Disable FTP access for Resource Plan submission (ONLY Resource Plan submiss 1 day Fri 3/30/07 Fri 3/30/07


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9 Reversion Plan Tasks


Reversion Plan Checklist

Task ID Task1 Prepare Market for Reversion2 Implement communication plan for reversion

3SPP ensures that all coordination center desks are aware the reversion plan is going into effect via phone

4SPP posts on OASIS that the reversion plan is going into effect and suspends standards of conduct

5 SPP posts on Portal that the reversion plan is going into effect6 SPP posts on SPP.org that the reversion plan is going into effect

7SPP issues operator notification on MOS indicating reversion plan is going into effect

8 SPP issues press release indicating that the reversion plan is going into effect

9SPP issues email on SPP system status exploder list indicating that reversion plan is going into effect

10SPP notifies control areas (including first-tier) via emergency communications that reversion plan is going into effect

11 SPP notified market participants via emergency communications method

12SPP notifies reliability coordinators (via RCIS), NERC and JOA parties that market reversion is going into effect

13SPP notifies market participants that all energy imbalance needs must be met through bilateral arrangements

14SPP advises control areas, as appropriate, to utilize alternate means to get RTOSS NSI

15 Revert Out of the Market16 Revert17 Disable MP access to MOS MUI and API18 Disable notifications to Market Participants19 Instruct MPs not to control to ICCP notifications

20Loss Distribution Reversion - Turn on Loss Distribution schedule creation in RTO_SS

21Inadvertent Energy Reversion - Support Scheduling group in calculating ratio for inadvertent accumulation while market was in effect

22 IDC Reversion23 Add Stop Date/Time to SPP Market24 Enter new Book of Flowgates that does not contain SPP Zones.25 CAT Reversion26 Disable CAT to RTO_SS interface27 Disable IDC to CAT interface28 Disable CAT to DSS interface29 Settlements Reversion30 Disable MOS to COS interface

31NSI Reversion - Tell participants to stop controlling off of the EI NSI and start controlling off of the RTO_SS NSI

32

Add notes to LIP and SLIP pages on SPP.org stating that data is not financially binding after a certain date and time (the last interval ending for the market).

33Uncheck MOS Resource Plan flag in SDA DB (so EMS uses SPP (FTP) Resource Plans)

34 Post Reversion35 Settle for Market According to Reversion Decision

36SPP president, or his designate, determines cutoff period for financial settlement.

37Halt publication of settlement statements effective with the timeframe determined by SPP president

38 Halt invoicing effective with the timeframe determined by the SPP president39 Execute Alternate Inadvertent Payback Procedures

40 SPP to utilize alternate procedures for management of inadvertent payback.41 Submit Regulatory Documents42 SPP to inform regulatory authorities of reversion event

© 2006 Southwest Power Pooland Accenture LLP.

All Rights Reserved. 1 of 1

10 Glossary A/S Plans

Hourly plans that indicate which resources have capacity withheld to meet ancillary service requirements.

A/S Obligations

Information calculated by SPP that indicates the minimum amount of ancillary services requires.

Balancing Authority

Defined in the Open Access Transmission Tariff.

CAT / IDC

Curtailment Adjustment Tool/Interchange Distribution Calculator. Tools used by SPP and NERC respectively, that determine the amount of schedule curtailments necessary in managing transmission congestion.

Central Prevailing Time (CPT)

Clock time for the season of a year, i.e. Central Standard Time and Central Daylight Time.

Credit Management System (CMS)

SPP’s system for determining customer credit limits and collateral requirements.

Day Ahead Period (DA)

The time period starting at 0700 and ending at 1530 of the day prior to the Operating Day.

Deployment Interval

The interval for which SPP issues dispatch instructions for Energy Imbalance Service. The dispatch interval is currently 5 minutes.

Dispatch Instructions

Expressed as the value at the end of the Deployment Interval.

Distributed Generation

An electrical generating facility greater than 1 MW peak capacity which is connected to a distribution system.


Dynamic Schedule

A telemetered reading or value that is updated in real time and used as a schedule in the Automatic Generation Control/Area Control Error equation and the integrated value of which is treated as a schedule. Commonly used for “scheduling” jointly owned generation or remote load to or from another Balancing Authority.

Energy Imbalance Service (EIS)

EIS is an ancillary service used to compensate for differences between the scheduled and the actual withdrawal of energy or between the scheduled and the actual output of a generator.

Energy Management System (EMS)

The software system used by SPP for the real-time acquisition of operating data and operations.

Granular Schedule Validation

The process of defining whether schedule sources and sinks rever to valid market settlement locations.

Hour Ahead Period (HA)

The time period following the close of the Day-Ahead Period and ending at the thirty minutes before the Operating Hour.

ICCP

Inter-control-center communications protocol. The means by which real-time data is communicated between Balancing Authorities and SPP.

LDAP

Lightweight Directory Access Protocol. A database that stores information about market customers and their security levels.

Locational Imbalance Pricing (LIP)

The calculation of prices for Energy Imbalance Service at Settlement Locations using the state estimator and a security constrained economic dispatch concept. (e.g. The price to provide least-cost incremental unit of energy at that location).


Lodestar

The software that peforms hourly settlement calculations for SPP.

Market Operations System (MOS)

The real-time systems responsible for the operational aspects of ancillary service offers, deployment, and Locational Imbalance Pricing calculations.

Market Participants (MP)

Entities buying and selling services provided by SPP under its OATT. In Registration, Market Participant refers to the roles of GenCo, LSE and metering agent.

Market Power

The ability to cause prices to deviate from competitive levels by controlling the provision of generating or transmission capacity to the market, whether by “physical” withholding or “economic” withholding.

Megawatt (MW)

A measurement unit of the instantaneous demand for energy.

Metering Agent (MA)

An entity responsible for the acquisition of end-use meter data, application of losses, aggregation of meter data, application of data to Settlement Intervals and transfer of data to SPP. This entity can be a traditional utility entity or other competitive entity. The Market Participant registers their Metering Agent(s) with SPP.

Meter Participant

A Market Participant or their designated agent that is settled through the SPP energy market and is subject to the energy imbalance settlement process.

Metering Parties

All parties, identified in a transmission service agreement, that have a vested interest in the accuracy of the meter data. Typically this would include SPP, Balancing Authority Operator, Wire Facilities Owner(s), Meter Owner, and Meter Participant.

Meter Settlement Location

Defined in the Open Access Transmission Tariff (OATT).


Market Flow Calculator (MFC)

A tool that determines the impact that SPP’s market has on monitored transmission facilities.

Market Monitoring Application (MMA)

The application that tracks data needed by SPP’s market monitoring unit.

Market User Interface (MUI)

The portion of SPP’s market portal that manages data needed for real-time market functions.

Net Scheduled Interchange (NSI)

The algebraic sum of all energy scheduled to flow into or out of a Settlement Area during a Settlement Interval. NSI includes the ramp on a 4 second interval to achieve the Dispatch Instructions at the end of the Deployment Interval.

Node

A specific electrical bus location in the SPP EMS transmission model for which a settlement price is calculated.

North American Electric Reliability Council (NERC)

A non-profit organization whose mission is to ensure that the bulk electric system in North America is reliable, adequate, and secure.

Offer Curve

The Supply Curve is a set of price/quantity pairs that represents the offer to provide energy or curtail.

Operating Day (OD)

The daily period beginning at midnight for which transactions within SPP are scheduled.

Operating Hour (OH)

A 60 minute period of time during the Operating Day corresponding to a clock hour. This can also be expressed as the Hour Ending.

Portal

Internet interface between SPP’s computer systems related to market operations and settlement and the Market Participant.


Real Time Period

The time period following the close of the Hour Ahead Period during which SPP or the Balancing Authority operator balances the system by deployment of energy from Energy Imbalance Service, Regulation Service, Operating Reserve- Spinning, Operating Reserve- Supplemental.

Resources

Assets which are defined within the Market System which inject energy into the transmission grid, or which reduce the withdrawal of energy from the transmission grid, and may be discretely directed by the RTO or ISO. These Resources include generation and controllable load.

Resource/Obligation Type

Defined in the XML Document as Attachment XXX in the Protocols.

RSS

Reserve Sharing System. The system for sharing operating reserves within SPP.

RTO_SS

RTO Scheduling System. The tool that tracks scheduled transactions involving SPP’s market.

Self-Dispatched Resource

A Resource that is not available for dispatch by SPP to support Market Operations.

Settlement Area

A geographic area for which transmission interval metering can account for the net area load. A settlement area is typically a Balancing Authority, and must be completely contained in a single Balancing Authority

Settlement Interval

The period of time for which the market is financially settled. This period of time is coincident with scheduling granularity and Energy Imbalance Service price calculation intervals. The settlement interval is currently one hour.


Settlement Location

Locations defined for the purpose of commercial operations and settlement. A Settlement Location is the location of finest granularity for calculation of Imbalance Settlements. The data required must be at this level of granularity in schedules, meter data, and pricing.

Settlement Statement

A statement of the market and other tariff charges related to the Settlement for a Market Participant.

Siebel

SPP’s system for tracking customer information and requests.

SPP Region

The geographic area of the Transmission System for which SPP is the Transmission Provider.

State Estimator

The computer software used to estimate the properties of the electric system based on a sample of system measurements.

TD (“transition day”)

The first operating day during which settlements shall be financially binding in SPP. This is scheduled to occur on February 1, 2007. “TD-1 day” shall refer to the calendar day prior to the first day of market operations, and “TD-2 days” shall refer to the second calendar day prior to the first day of market operations, etc.

TH (“transition hour”)

The first operating hour during which settlements shall be financially binding in SPP. This is the operating hour ended 0100 Central Prevailing Time on February 1, 2007. “TH-1 hour” shall refer to the hour prior to the first hour of market operations to that operating and “TH-2 hours” shall mean two hours prior to the operating hour, etc.
