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Southwest Power Pool
BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING
Marriott City Center, Denver, Colorado
July 30, 2013
- Summary of Action Items -
1. Approved Consent Agenda items:
a. Approve April 30 and July 1, 2013 minutes
b. Markets and Operations Policy Committee
i. RTWG: TRR093, TRR095, TRR096
ii. MWG: PRR 244
MPRR 117, 118, 120, 121, 122, 123, 124, 125, 128
iii. Staff: Transmission Service Waiver (KMEA)
Hays Plant-South Hays 115kV NTC Reevaluation and Possible Modification
c. Finance Committee
i. Auditor Engagement
2. Approved the Finance Committee’s recommendation that the Board of Directors approve to increase the Schedule 1-A admin fee cap to 39¢/MWh and authorize SPP staff to make the appropriate filings with FERC for approval.
3. Approved the Markets and Operations Policy Committee’s recommendations that the Board of
Directors approve its request regarding TRR091’s Backlog Clearing Process as approved by MOPC in the white paper in April 2013.
4. Approved the Markets and Operations Policy Committee’s recommendations that the Board of
Directors approve the 2013 ITP20 report as documentation of completion of the 20-Year Assessment of the ITP planning process specified in SPP OATT Attachment O Section III, and endorse the 2013 ITP20 plan as outlined in the 2013 ITP20 report.
5. Approved the Markets and Operations Policy Committee’s 2015 ITP10 recommendation that the Board of Directors approve the development of a resource plan for three Futures: Business as Usual, Decreased Base Load Capacity, and Increased Input Prices and reevaluate at the October meeting.
6. Approved the Markets and Operations Policy Committee’s recommendation that the Board of
Directors approve two key assumptions for 2015 ITP10 study: 1) the inclusion of 50/50 HPILS loads and Board approved HPILS NTCs; 2) directed MOPC to treat HVDC facilities as a sensitivity case and inclusion in the study would depend upon further examination.
7. Approved the Markets and Operations Policy Committee’s recommendation that the Board of
Directors approve MPRR 133 giving Staff, working with the RTWG Chair, latitude to update language to allow Staff the flexibility to decline nominating ARRs. The implementation of the appropriate software for the distribution of the net of the “carve-out” would trigger a resettlement from the default distribution through RNU back to the start of the Market.
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8. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors provide an advisory vote to the SPP RE that PRC-006-SPP-1 be withdrawn from FERC consideration as a Regional Standard due to the fact that NERC PRC-024-1 has been approved by NERC and is waiting on FERC approval.
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MINUTES NO. 153
Southwest Power Pool
BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING
Marriott City Center, Denver, Colorado
July 30, 2013
Agenda Item 1 - Administrative Items
SPP Chair Mr. Jim Eckelberger called the meeting to order at 8:00 a.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy:
Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Ricky Bittle, Arkansas Electric Cooperative Mr. Julian Brix, director Mr. Nick Brown, director Mr. Phil Crissup, Oklahoma Gas and Electric Mr. Scott Heidtbrink, proxy for Mr. Mike Deggendorf, Kansas City Power and Light Mr. Mo Doghman, Omaha Public Power District Mr. Jim Eckelberger, director Mr. Kelly Harrison, Westar Energy Ms. Cindy Holman, Oklahoma Municipal Power Authority Mr. Rob Janssen, Dogwood Energy Mr. Tom Kent, Nebraska Public Power District Mr. Jeff Knottek, City Utilities of Springfield Mr. Brett Kruse, Calpine Energy Services Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Kevin Smith, Tenaska Mr. Stuart Solomon, American Electric Power Mr. Noman Williams, Sunflower Electric Power Corporation Mr. Mike Wise, Golden Spread Electric Cooperative
There were 117 persons in attendance either in person or via phone representing 34 members (Attendance List - Attachment 1). Mr. Nick Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Agenda Item 2 – Board Reports
President’s Report
Mr. Nick Brown provided the President’s Report (President’s Report – Attachment 3). Mr. Brown stated that on July 18, 2013 FERC issued an order regarding SPP’s Order 1000 Compliance filing. Of the several items that may require a request for rehearing, it was disappointing that the request for Right of First Refusal (ROFR) was rejected. In an earlier order, the Commission had approved the ROFR. There were two dissenting votes, which everyone was encouraged to read. SPP will continue to analyze the order. In April, SPP agreed to accept a settlement from FERC for an event that took place in December 2007, neither admitting nor denying fault. The July 10, 2013 Order required SPP to pay a $50,000 fine with half to NERC and half to the Treasury. SPP marked one year on the new campus on July 16. SPP was recently notified that the facility meets LEEDS Gold status. The building has had a positive impact on the budget in that we no longer pay $1 million per year in rent for office space and no longer need to rent meeting space.
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Mr. Brown announced that Southwest Power Pool had been selected as one of twelve companies that make up the inaugural class for Arkansas Business' Best Places to Work in Arkansas. Arkansas Business partnered with the internationally renowned Best Companies Group and the Arkansas Society of Human Resource Management to bring the Best Places to Work program to the state. Mr. Brown reported that SPP is on budget showing 3% below on revenues and 3% below on expenses. SPP will not fill eight positions budgeted for 2013.
Mr. Brown referred to the SPP Metrics included in the background material and asked Mr. Carl Monroe to provide commentary and answer any questions.
Mr. Brown announced this to be Ms Cindy Holman’s last meeting with SPP as she will retire on July 31, 2013, from Oklahoma Municipal Power Authority and thus from the SPP committees she serves. He presented Ms. Holman with a resolution and thanked her for her great service to SPP.
Regional Entity Trustee Report
Mr. John Meyers presented the Regional Entity Trustee report (RE Report – Attachment 4). The report included updates on:
New Definition of Bulk Electric System
Facility Ratings Alert
Transition from CIP Version 3 to Version 5
NERC “Blue Ribbon Panel” to review standards
Most Violated Standards
1Q SPP RE Region Misoperation Report
NERC Reports
Outreach Regional State Committee Report
Mr. Tom Wright (Kansas Corporation Commission) presented the Regional State Committee (RSC) report. Mr. Wright stated that it was the nature of the RSC to have a varying degree of knowledge due to turnover in members and terms. That being the case, the group took the opportunity to meet in Colorado Springs for an educational retreat between the NARUC and SPP meetings. Mr. Wright thanked and complimented staff on well presented material addressing the process improvement, Integrated Marketplace, Market Monitoring, and transmission planning.
Mr. Wright said the RSC met July 29. The group heard updates on Order 1000 Regional and Interregional,planning and processes, Long Term Financial Transmission Rights, Regional Cost Allocation Review, the Rate Impact Task Force, Integrated Marketplace and Integrated Transmission Planning. The RSC approved the Cost Allocation Working Group’s definition of “mandates” and “goals” for the treatment of renewable resources in planning. Oversight Committee Report
Mr. Larry Altenbaumer presented the Oversight Committee Report for Mr. Josh Martin, Committee Chair. The Committee met in Little Rock in June and heard quarterly reports from Internal Audit, Compliance, and Market Monitoring staff.
Internal Audit continues its regular audits, as well as its oversight role in the Integrated Marketplace initiative. Plans are to continue the focus on higher-risk areas, and particularly those that intersect with the Integrated Marketplace initiative.
The primary focus of Compliance has been the launch of the Regional Compliance Working Group, and preparations for SPP’s first comprehensive CIP audit, which was conducted during the last week of June/first of July. A Compliance Forum was held May 23; the next one will be held August 7-8 in Little Rock. These continue to be well-attended.
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The Market Monitoring Unit staff remains engaged in the Integrated Marketplace initiative, developing the various new metrics that will be necessary to monitor the new markets. Last year, SPP was awarded $1 million as part of FERC’s settlement with Constellation for market violations. The funds were to be used to support or enhance market monitoring efforts. Earlier this month, SPP received approval for its proposal for use of these funds and will proceed accordingly.
The committee also heard briefings for each department’s 2014 budget, and updates to strategic plans.
The Oversight Committee’s next scheduled meeting is September 26 in Chicago. Human Resources Committee Report
Ms. Phyllis Bernard stated that there was no formal Human Resources Committee report. The group will hold its annual retreat September 10 - 11 in Little Rock at the SPP Corporate Campus. Ms. Bernard also reiterated Mr. Brown’s remark that Southwest Power Pool was chosen in the inaugural class of the twelve best places to work in Arkansas. Corporate Governance Committee Report
Mr. Nick Brown presented the Corporate Governance Committee report. Mr. Brown announced that nominations are open for several committee vacancies including:
Members Committee, a mid-term Municipals opening (election in October)
TO vacancy on the SPC effective December 1 (appointed by CGC with Board approval)
IOU vacancy on CGC effective December 1 (IOU members will select)
Municipals vacancy on CGC effective August 1 (Muni members will select) He asked that nominations be submitted to either himself or Ms. Stacy Duckett. The Committee submitted a filing regarding withdrawal obligations for transmission expansion costs. At the next meeting on August 29, the group will review services versus fees to ensure equity, review scopes of Board committees and discuss cost allocation for an entity joining SPP. Agenda Item 3 – Consent Agenda
Mr. Eckelberger presented the following Consent Agenda items for approval (Consent Agenda – Attachment 5):
a. Approve April 30 and July 1, 2013 minutes
b. Markets and Operations Policy Committee
ii. RTWG: TRR093, TRR095, TRR096
iii. MWG: PRR 244
MPRR 117, 118, 120, 121, 122, 123, 124, 125, 128
iv. Staff: Transmission Service Waiver (KMEA)
Hays Plant-South Hays 115kV NTC Reevaluation and Possible Modification
c. Finance Committee
v. Auditor Engagement
Mr. Eckelberger asked for requests to remove any items from the Consent Agenda or a motion to approve. Mr. Julian Brix moved to approve the Consent Agenda items; Mr. Harry Skilton seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.
SPP Board of Directors/Members Committee Minutes July 30, 2013
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Agenda Item 4 – Integrated Marketplace Report
Mr. Bruce Rew provided the Integrated Market report (IM Report – Attachment 6). Mr. Rew gave an overview of the first seven weeks of market trials and discussed preparation for parallel operations and final steps for Go-Live and post Go-Live. Concerns were raised regarding the number of entities engaged, JOAs and seams issues, and post market enhancement for combined cycle. Following discussion, it was suggested to set deadlines for participants’ engagement and testing, be more diligent regarding seams and develop a plan for enhancements following market Go-Live. Agenda Item 5 – Strategic Planning Committee Report
Mr. Ricky Bittle provided a Strategic Planning Committee report. The Committee reformed the SPCTF on Order 1000 to address the recent order (SPCTF Order 1000 – Attachment 7). He reviewed the Order timeline, Order findings and outlined SPCTF recommendations. The group recommends that SPP seek rehearing and clarification (due on August 18) on the following issues:
Rehearing
Mobile-Sierra
Byway funding
Removal of exemption on existing rights-of-way
Inclusion of Aggregate Study projects
State Right of First Refusal (ROFRs)
Clarification
Approved Aggregate Study NTCs prior to January 2015
It was the consensus that SPCTF should proceed with the recommendations as presented. The SPCTF plans to schedule meetings to develop policy guidance for the compliance filing, begin dialogue with the RSC, CAWG on cost allocation and state ROFRs, and understand implications for the ITP10 that will yield NTCs in January 2015. Agenda Item 6 – Finance Committee Report
Mr. Harry Skilton presented the Finance Committee Report (FC Report – Attachment 8). Mr. Skilton addressed activities of the Committee regarding: Pension Fund Management, Auditor Engagements, Schedule 1-A Administrative Fee Cap, CFTC Exemption and Aviation Strategy. The Schedule 1-A administrative fee cap was set when the tariff was implemented. As SPP adds services, SPP’s costs have risen but also have resulted in significant benefits to the SPP region. The administrative fee continues to grow but SPP’s forecast indicates costs/MWh will level off and slightly decline in the foreseeable future, assuming no new services are added. The Committee wants to raise the current 35¢/MWh cap to cover forecasted costs and recommends the following:
The Finance Committee recommends the SPP Board of Directors approve an increase the Schedule 1-A admin fee cap to 39¢/MWh and authorize SPP staff to make the appropriate filings with FERC for approval. Mr. Harry Skilton moved for approval; Mr. Larry Altenbaumer seconded. The Members Committee voted in unanimous approval. The Board voted; the motion passed.
Agenda Item 7 – Markets and Operations Policy Committee Report
Mr. Rob Janssen provided the Markets and Operations Policy Committee report (MOPC Report – Attachment 9). Mr. Janssen gave an overview of the following action items and recommendations for approval:
SPP Board of Directors/Members Committee Minutes July 30, 2013
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RTWG – TRR091
This is the first stage of Aggregate Study improvements, the Backlog Queue Clearing Process, as approved in white papers by the MOPC and the Board of Directors in April 2013 (TRR091 Recommendation – Attachment 10). MOPC approved tariff language and requested that the Board of Directors approve TRR091. Mr. Julian Brix moved to approve; Ms. Phyllis Bernard seconded. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Following approval, direction was requested on the timing of a FERC filing. Due to the fact that the Backlog Clearing Process can only be implemented on the Active Study between iterations, it was suggested to set an aggressive timeline with an effective date prior to October 15 in order to implement in the next gap between iterations. This would require a filing in the next two weeks. It was the consensus to meet this timeline and avoid delaying until the next round of studies. ESWG – ITP20 and ITP10
Mr. Alan Myer provided background on the 2013 ITP20 Report (ITP20 Recommendation – Attachment 11) and asked that the Board of Directors approve the report as documentation of completion of the 20-Year Assessment of the ITP planning process specified in SPP OATT Attachment O Section III. MOPC further recommends the Board endorse the 2013 ITP20 plan as outlined in the 2013 ITP20 report. Mr. Larry Altenbaumer moved to approve the 2013 ITP20 report and plan as requested; Mr. Harry Skilton seconded. The Members Committee voted in favor with Mr. Jeff Knottek voting against. The Board voted; the motion passed. Mr. Myers then provided background on the 2015 ITP10 (ITP10 Recommendation – Attachment 12), Strategic Planning scenarios and drivers, and proposed futures. He noted that the ESWG had recommended the adoption of three Futures (Business as Usual, Decreased Base Load Capacity, and Increased Input Prices). He reported that MOPC had a lengthy dialogue about the third Future and after debate voted to only approve two Futures (Business As Usual and Decreased Baseload Capacity). Following much discussion, the recommendation was revised to develop a resource plan for three Futures: Business as Usual, Decreased Base Load Capacity, and Increased Input Prices and reevaluate at the October meeting. Mr. Larry Altenbaumer moved to approve the revised recommendation; Ms. Phyllis Bernard seconded. The Members Committee voted in favor with Mr. Mike Wise and Mr. Jeff Knottek in abstention. The Board voted; the motion passed. Mr. Janssen reviewed and requested approval of two 2015 ITP10 key assumptions:
Approve the inclusion of 50/50 HPILS loads and Board approved HPILS NTCs in the 2015 ITP10 Study.
Approve inclusion of new HVDC facilities in the 2015 ITP10 study if they have executed Transmission – Transmission Interconnection Agreement (both ends) and flows across the facilities being based on firm transmission service. Following discussion, the motion regarding HVDC facilities was revised to direct MOPC to view this as a sensitivity case and inclusion in the study would depend upon further examination.
Mr. Nick Brown moved for approval as revised; Mr. Julian Brix seconded. The Members Committee voted in favor with Mr. Mike Wise and Mr. Jeff Knottek in abstention. The Board voted; the motion passed.
MWG – MPRR133
Mr. Richard Ross provided background regarding MPRR133, the GFA Carve Out (MPRR133 Recommendation – Attachment 13). SPP received three directives from FERC in the October 18, 2012 Marketplace Order:
Begin settlement negotiations with protesters who are parties to GFAs
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File an informational filing 90 days after issuance of the order
After informational filing, SPP may commence a stakeholder process to finalize a Carve Out proposal for the GFAs that: o Have not been integrated into the Integrated Marketplace and which merit a Carve Out
MWG approved a GFA Carve Out design on June 19, 2013 and recommended the following:
Approve MPRR133 giving Staff, working with the RTWG Chair, latitude to update language to allow Staff the flexibility to decline nominating ARRs. The implementation of the appropriate software for the distribution of the net of the “carve-out” would trigger a resettlement from the default distribution through RNU back to the start of the Market. Following considerable discussion, Mr. Julian Brix moved for approval; Mr. Larry Altenbaumer seconded. The Members Committee voted in favor with Mr. Mo Doghman, Mr. Tom Kent and Mr. Rob Janssen against, and Mr. Kevin Smith in abstention. The Board voted; the motion passed.
SPCWG - UFLS Standard Removal
Mr. Janssen provided background regarding the removal of the UFLS Regional Standard (UFLS Standard Recommendation – Attachment 14). The MOPC recommendation is:
The Board of Directors provide an advisory vote to the SPP RE that PRC-006-SPP-1 be withdrawn from FERC consideration as a Regional Standard due to the fact that NERC PRC-024-1 has been approved by NERC and is waiting on FERC approval. Mr. Harry Skilton moved for approval; Mr. Larry Altenbaumer seconded. The Members Committee voted in unanimous approval. The Board voted; the motion passed.
Due to time constraints, Mr. Janssen ended his report. Additional MOPC informational items can be found in the attached report. Agenda Item 8 – Future Meetings
Mr. Eckelberger reminded the group the next SPP Board of Directors meeting will include the Annual Meeting of Members and be held on October 29, 2013 in Little Rock (Future Meetings – Attachment 15). Adjournment
With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 3:28 p.m. Stacy Duckett, Corporate Secretary
Relationship-Based • Member-Driven • Independence Through Diversity
Evolutionary vs. Revolutionary • Reliability & Economics Inseparable
Southwest Power Pool
BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING
July 30, 2013 Marriott City Center, Denver, Colorado
• A G E N D A •
8:00 a.m. – 3:00 p.m. Mountain Daylight Time
1. Call to Order and Administrative Items .................................................................... Mr. Jim Eckelberger
2. Board Reports
a. President’s Report .............................................................................................. Mr. Nick Brown b. Regional Entity Trustees Report ......................................................................... Mr. John Meyer c. Regional State Committee Report .................................................... Commissioner Tom Wright d. Federal Energy Regulatory Commission Report ............................................ Mr. Patrick Clarey e. Oversight Committee Report .............................................................................. Mr. Josh Martin f. Human Resources Committee Report .......................................................... Ms. Phyllis Bernard g. Corporate Governance Committee Report ......................................................... Mr. Nick Brown
3. Consent Agenda ....................................................................................................... Mr. Jim Eckelberger
a. Approve April 30 and July 1, 2013 minutes
b. Markets and Operations Policy Committee
i. RTWG: TRR093, TRR095, TRR096
ii. MWG: PRR 244
MPRR 117, 118, 120, 121, 122, 123, 124, 125, 128
iii. Staff: Transmission Service Waiver (KMEA)
Hays Plant-South Hays 115kV NTC Reevaluation and Possible Modification
c. Finance Committee
i. Auditor Engagement
4. Integrated Marketplace Report ......................................................................................... Mr. Bruce Rew
5. Strategic Planning Committee Report .............................................................................. Mr. Ricky Bittle
6. Finance Committee Report ............................................................................................ Mr. Harry Skilton
7. Markets and Operations Policy Committee Report ....................................................... Mr. Rob Janssen
a. RTWG: TRR091
b. ESWG: 2013 ITP20 Plan
2013 ITP10 Futures and Key Assumptions
c. MWG: MPRR133
d. SPCWG: Removal of the UFLS Regional Standard
Relationship-Based • Member-Driven • Independence Through Diversity
Evolutionary vs. Revolutionary • Reliability & Economics Inseparable
8. Future Meetings ........................................................................................................ Mr. Jim Eckelberger
RSC/BOD/RET – October 28-29 ................................................ Little Rock BOD – December 10 ......................................................................... Dallas 2014
RET/RSC/BOD - January 27-28 ....................................................... Austin
RET/RSC/BOD - April 28-29 ............................................... Oklahoma City
BOD - June 9-10 ....................................................................... Little Rock
RET/RSC/BOD - July 28-29 ............................................................ Omaha
RET/RSC/BOD - October 27-28 ................................................ Little Rock
BOD - December 9 ............................................................................ Dallas
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Subject: FW: SPP Board Meeting
From: Deggendorf Michael [mailto:[email protected]] Sent: Monday, July 08, 2013 4:59 PM To: Stacy Duckett Cc: Heidtbrink Scott; Buffington, Denise Subject: SPP Board Meeting Stacey, I wanted to notify you that I will be giving my proxy to Scott Heidtbrink for the upcoming SPP Board meeting in Denver. I will be attending the SPC. Thanks, Mike
To: SPP Officers / Directors / ManagersFrom: Sheri Dunn / Cindy GoodwinDate: July 23, 2013RE: June 2013 Financial Package
Page1). Financial Commentary: Full-Year Actual / Forecast to Budget Variances 1
2). 3
3). Income Statement Actual Results Overview: Current Month Actual compared to Forecast, YTD Actual compared to Budget and YTD Actual compared to Prior Year
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4). Balance Sheet: Current Month compared to Ending Prior Year 5
6). 6
7). Headcount Analysis: Current Month Actual compared to Budget and Final Forecast compared to original Budget
13
8). Job Tracker: List of current open positions as tracked by Human Resources 14
Memorandum
Financial Forecast Overview: Full-Year Actual / Forecast by month compared to Budget and Prior Year
Capital Projects Summary: Current year and future projections compared to total project Budget
Attached are the June 2013 monthly financial reports.
2013 FY 2013 FY Fav/(Unfav)Forecast Budget Variance
Revenues $142,143 $147,015 ($4,872) (3.3%)
Expenses 157,682 162,625 4,943 3.0%
Net Income/(Loss) ($15,539) ($15,610) $71 0.5%
2013 FY 2013 FY Fav/(Unfav)Forecast Budget Variance
Tariff Administration Service $112,981 $113,799 ($818) (0.7%)
Fees & Assessments * 25,015 28,211 (3,196) (11.3%)
Contract Services Revenue 424 721 (298) (41.3%)
Miscellaneous Income 3,723 4,284 (561) (13.1%)
Total Revenue $142,143 $147,015 ($4,873) (3.3%)
* Breakdown of Fees & Assessments:Annual Non-Load Dues $438 $402 $36 9.0%
NERC ERO Regional Entity Rev 10,269 11,515 (1,246) (10.8%)
FERC Fees & Assessments 14,307 16,294 (1,987) (12.2%)
Total Fees & Assessments $25,015 $28,211 ($3,196)
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2013 Financial CommentaryJune 30, 2013(in thousands)
Summary
Revenue
Tariff Administration Service revenue budget assumed a minimal amount of growth in load history over Jul-2011 thru Aug-2012. Current projections reflect a slight decrease in network and point-to-point service (0.7%), and revenues are expected to be below budget by $818K.
NERC ERO Regional Entity revenue is based on expenses incurred by the Regional Entity (RE), which trail budget ($1.2M).
FERC Schedule 12 revenues are billed a month in arrears and based on network transmission. The budget assumed a 3% increase over actual Schedule 12 revenues from Aug-2011 thru Jul-2012. Subsequent to completion of the budget, the 2013 Schedule 12 ratewas adjusted down from $0.072 in 2012 to $0.064 for 2013. The forecast has been adjusted with the lower rate, and the expected full-year impact is a $2.0M shortfall compared to the budget.
Contract Services Revenue budget includes revenue for OVEC ($376K) and Entergy Regional Service Committee (ERSC) ($345K). Removal of the ERSC revenues from the forecast created an unfavorable variance in revenue; however, ERSC expenses were also removed from the forecast ($280K). The net ERSC revenue/expense variance is $65K unfavorable for the year. OVEC revenues are forecast at $46K higher than budget, as the contract was renewed at a higher rate beginning in April 2013.
Miscellaneous Income primarily consists of revenues associated with billable resource time related to various studies and other non-recurring income items. The budget assumed costs of the Order 1000 program would be recovered by SPP; however, the revenue has been removed from the forecast pending further notification from FERC ($650K). Revenue for Engineering studies trail budget by $491K.
Partially offsetting the unfavorable variances in Miscellaneous Income are reimbursements for ICT transition services and ICT studies ($349K), ARS reimbursements ($141K), sales tax rebates ($82K) and map sales ($6K), which were not considered in the budget.
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2013 Financial CommentaryJune 30, 2013(in thousands)
2013 FY 2013 FY Fav/(Unfav)Forecast Budget Variance
Salary & Benefits $78,121 $77,363 ($758) (1.0%)
Assessments & Fees 14,699 16,340 1,641 (10.0%)
Communications 3,834 4,427 593 13.4%
Maintenance 10,972 10,476 (496) (4.7%)
Outside Services 15,248 16,003 754 4.7%
Administrative 4,336 5,014 677 13.5%
Travel & Meetings 3,155 4,200 1,045 24.9%
Depreciation & Amortization 19,725 20,296 571 2.8%
Other Expenses 7,592 8,508 915 10.8%
Total Expense $157,682 $162,625 $4,943 3.0%
Expense
Salaries & Benefits are projected to be unfavorable to budget by $758K. The budget assumed a vacancy rate of 6% (based on historical vacancy levels); however, the forecasted vacancy rate is closer to 3%.
Communications & Maintenance is favorable to the budget mainly due to lower Communications expense ($593K). Voice Circuits / SPPnet frame were budgeted in 2013 based on estimated growth in Market Participants, which has shown no increase to date. The monthly forecast has been adjusted based on trailing three month actual numbers. Maintenance exceeds budget by $465K, which relates to items incurred at an earlier date than assumed in the original budget (AIMMS/CPLEX license and rentals, and CMT and Netezza Box maintenance). The current full-year maintenance forecast is expected to be within 5% of budget.
The Outside Services forecast has been reduced in the following areas:
Legal - Removed contingency - SPP determined not to appeal multiple state commission orders in Entergy dockets ($545K)Administration - Order 1000 start-up costs, pending further notification from FERC ($236K)Corporate Services - On-site medical clinic delay, removal of equipment set-up contingency ($266K)Regional Entity - 10% reduction reflecting cost containment efforts ($416K)Engineering - Studies consulting expense trailing budget ($357K)
Unbudgeted adhoc consulting projects partially offset the favorable variances noted above ($480K). Additionally, outside consulting expense has been added in the Project Management department ($271K). The budget considered all contract project manager costs would be capitalized within the Integrated Marketplace project; however, several contract project managers are working on non-Integrated Marketplace, non-capital projects, and their costs are currently expensed as staff augmentation. IT staff augmentation also contributes to the offset ($270K).
The favorable Administrative expense variance is mainly attributed to utilities and office expenses. The majority of the difference is in utilities ($497K). The utilities expenses were loaded evenly across all months in the budget, and therefore the favorable variance will potentially decrease as utility costs rise during the summer months. Office expense is under budget by $328K. This variance may also potentially be offset due to the relocation of the Integrated Markets team (80+ resources) to the Maumelle facility thru March 2014. Future forecasts will be adjusted as trends of these expenditures become clearer. Miscellaneous eqiupment purchases exceed budget and partially offset the favorable Administrative variance ($112K). These are miscellaneous asset purchases under $1K, which are expensed as they do not meet the $1K capital threshold.
Expenses related to the ERSC were inadvertently left in the budget and account for $244K of the overall favorable variance in Meetingsexpense, which trails budget $619K overall. Other major components of the variance are represented in various SPP Working Groupmeetings ($172K), Training ($148K), Regional Entity ($25K), and Regulatory ($34K). Corporate Services continues to analyze scheduled meeting expense projections and provides updated forecast estimates as available. Travel expenses trail budget aross various departments ($426K). Much of the variance is associated with Integrated Marketplace outreach meetings, which are not anticipated to involve any staff travel ($151K).
Depreciation trails budget year-to-date due to timing of capital purchases and completed projects being placed into service.
Other Expenses are composed of Regional State Committee (RSC) expenses; interest income / expense / capitalization; miscellaneous income / expense; and various other valuation adjustments. Due to their unpredictability, most items are not considered in the budget, including Interest Income, Other Income/Expense (457b adjustment) and valuation adjustments. These items are generally favorable in comparison to the budget. Capitalized Interest is impacted by the timing and amount of capital expenditures on significant projects and is expected to be within 1% of the original budget.
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Actual Actual Actual Actual Actual Actual Fcst Fcst Fcst Fcst Fcst Fcst FY 2013 FY 2013 Variance FY 2012 VarianceJan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 Forecast Budget Fav/(Unfav) Actual Fav/(Unfav)
IncomeTariff Administrative Service $9,657 $8,685 $9,571 $9,187 $9,510 $9,365 $9,717 $9,743 $9,298 $9,502 $9,244 $9,503 $112,981 $113,799 ($818) $92,230 $20,751Fees & Assessments 2,578 2,292 1,541 1,856 1,854 1,970 2,431 2,231 2,077 2,028 2,029 2,127 25,015 28,211 (3,196) 26,578 (1,564)Contract Services Revenue 31 60 4 36 40 36 36 36 36 36 36 36 424 721 (298) 22,687 (22,263)Miscellaneous Income 207 325 292 453 368 174 297 297 322 297 297 397 3,723 4,284 (561) 6,424 (2,701)
Total Income 12,473 11,363 11,409 11,532 11,770 11,546 12,480 12,306 11,733 11,862 11,606 12,062 142,143 147,015 (4,873) 147,919 (5,777)
ExpenseSalary & Benefits 6,286 6,457 6,397 6,523 6,321 6,636 6,447 6,458 6,671 6,546 6,590 6,789 78,121 77,363 (759) 72,262 (5,859)Employee Travel 122 177 168 158 233 153 206 191 214 241 171 156 2,188 2,614 426 2,245 57Administrative 338 175 524 265 177 535 351 319 257 849 241 306 4,336 5,014 677 3,720 (616)Assessments & Fees 1,362 1,362 1,362 1,362 1,362 611 1,213 1,213 1,213 1,213 1,213 1,213 14,699 16,340 1,641 14,977 278Meetings 36 19 149 80 84 124 85 60 114 113 55 47 967 1,586 619 983 16Communications 275 327 263 308 333 309 318 318 318 355 355 358 3,834 4,427 593 4,020 186Leases 73 73 76 84 10 20 14 12 12 12 12 12 409 386 (23) 1,690 1,281Maintenance 894 874 955 923 892 937 946 914 898 922 904 913 10,972 10,476 (496) 8,288 (2,684)Services 914 1,361 891 1,300 1,058 1,615 1,290 1,404 1,321 1,333 1,261 1,500 15,248 16,003 754 14,705 (544)Regional State Committee 9 28 14 9 25 12 47 22 29 22 22 54 293 344 52 455 162Depreciation & Amortization 1,327 1,552 1,774 1,633 1,661 1,651 1,675 1,675 1,675 1,700 1,700 1,700 19,725 20,296 571 16,590 (3,135)
Total Expense 11,635 12,405 12,571 12,644 12,156 12,603 12,592 12,586 12,722 13,307 12,524 13,047 150,791 154,848 4,056 139,935 (10,944)
Other Income/(Expense)Gain or Loss on Sale of Fixed Ass - - - - 58 - - - - - - - 58 - 58 (264) 322Other Income / Expense 40 2 43 3 20 (23) - - - - - - 85 - 85 (3,451) 3,536Interest Income 39 18 31 24 15 (14) - - - - - - 114 - 114 149 (35)Interest Expense (867) (891) (909) (884) (882) (897) (866) (866) (875) (851) (849) (864) (10,500) (10,502) 2 (9,120) 1,380Capitalized Interest - - 800 - - 719 - - 665 - - 577 2,761 2,724 37 2,723 (38)Change in Valuation of Swap - - 231 - - 361 - - - - - - 592 - 592 674 82
Net Other Income (Expense) (788) (871) 196 (857) (789) 147 (866) (866) (210) (851) (849) (286) (6,891) (7,777) 887 (9,290) 5,246
Net Income (Loss) $50 ($1,914) ($966) ($1,969) ($1,174) ($910) ($977) ($1,145) ($1,199) ($2,296) ($1,768) ($1,271) ($15,539) ($15,611) $72 ($1,307) ($14,232)(4,693,323)
2013 Headcount Actual/Fcst 565 565 566 570 569 572 579 581 586 591 593 595 595 *2013 Headcount Budget 589 589 598 599 600 603 603 603 603 603 603 603 603
Over / (Under) Budget (24) (24) (32) (29) (31) (31) (24) (22) (17) (12) (10) (8) (8)
* Seven positions have been eliminated from the forecast (see detail on Headcount Analysis).
NRR Over / (Under) Recovery $1,205 ($426) ($1,928) ($37) $713 ($3,342) $411 $391 ($2,586) ($483) ($6) ($2,685) ($8,773) ($7,967) ($805) $5,549 ($14,322)
Southwest Power PoolMonthly Forecast Overview
June 30, 2013(in thousands)
Page 3 of 15
Jun-2013 Jun-2013 Variance Jun-2013 Jun-2013 Variance Jun-2013 Jun-2012 VarianceActual Forecast Fav/(Unfav) Actual Budget Fav/(Unfav) Current Year Prior Year Fav/(Unfav)
IncomeTariff Administrative Service $9,365 $9,236 $129 $55,975 $56,900 ($924) $55,975 $45,824 $10,151Fees & Assessments 1,970 2,331 (361) 12,092 13,956 (1,865) 12,092 12,708 (617)Contract Services Revenue 36 72 (36) 208 374 (166) 208 13,494 (13,286)Miscellaneous Income 174 397 (222) 1,819 2,255 (436) 1,819 3,713 (1,894)
Total Income 11,546 12,036 (490) 70,093 73,485 (3,391) 70,093 75,738 (5,645)
ExpenseSalary 4,342 4,409 67 26,118 26,062 (56) 26,118 23,711 (2,407)Benefits & Taxes 2,269 2,169 (101) 12,193 12,100 (93) 12,193 10,850 (1,343)Continuing Education 25 64 40 309 560 252 309 212 (96)
Salary & Benefits 6,636 6,642 6 38,620 38,723 103 38,620 34,773 (3,846)Employee Travel 153 203 51 1,010 1,384 374 1,010 1,083 74Administrative 535 582 47 2,013 2,557 544 2,013 1,917 (96)Assessments & Fees 611 611 - 7,421 8,170 749 7,421 7,118 (303)Meetings 124 103 (21) 492 769 277 492 468 (24)Communications 309 310 1 1,814 2,146 332 1,814 2,182 368Leases 20 20 - 335 314 (21) 335 926 591Maintenance 937 854 (83) 5,475 5,010 (465) 5,475 3,735 (1,740)Services 1,615 1,333 (282) 7,138 8,094 956 7,138 6,675 (464)Regional State Committee 12 29 16 97 173 77 97 302 205Depreciation & Amortization 1,651 1,653 2 9,598 9,988 389 9,598 6,807 (2,791)
Total Expense 12,603 12,341 (262) 74,013 77,328 3,315 74,013 65,987 (8,026)
Other Income/(Expense)Other Income / Expense (23) - 23 85 - (85) 85 20 (64)Interest Income (14) - 14 114 - (114) 114 80 (34)Interest Expense (897) (889) 7 (5,330) (5,332) (2) (5,330) (4,221) 1,109Capitalized Interest 719 734 14 1,519 1,279 (239) 1,519 1,775 256Change in Valuation of Swap 361 - (361) 592 - (592) 592 295 (297)
Net Other Income (Expense) 147 (156) (303) (2,963) (4,053) (1,089) (2,963) (2,051) 912
Net Income (Loss) ($910) ($461) ($449) ($6,883) ($7,896) $1,013 ($6,883) $7,700 ($14,584)
Headcount 572 568 4 572 603 (31) 572 537 35
Southwest Power PoolActual Results Overview
(in thousands)
Current Month Compared to Forecast YTD Actual Compared to YTD Budget YTD 2013 Compared to YTD 2012
June 30, 2013
Page 4 of 15
6/30/2013 12/31/2012 Net Change
ASSETS Current Assets Cash & Equivalents $63,321 $95,693 ($32,372) Restricted Cash Deposits 41,666 43,743 (2,077) Accounts Receivable (net) 18,710 17,923 787 Other Current Assets 8,656 5,412 3,244 Total Current Assets $132,353 $162,771 (30,418)
Total Fixed Assets 190,067 173,752 16,315 Total Other Assets 1,602 2,029 (427) Investments 1,073 968 105
TOTAL ASSETS $325,095 $339,520 ($14,424)
LIABILITIES & EQUITY Liabilities Current Liabilities Accounts Payable (net) $10,479 $9,831 $648 Customer Deposits 41,619 43,914 (2,295) Current Maturities of LT Debt 15,724 12,700 3,024 Other Current Liabilities 28,944 28,742 203 Deferred Revenue 6,898 6,286 612 Total Current Liabilites 103,664 101,472 2,192
Long Term Liabilities US Bank Floating Senior Note - 2014 2,750 5,500 (2,750) US Bank 5.45% Senior Notes - 2016 12,000 15,000 (3,000) US Bank Maumelle Mortgage - 2027 3,649 3,752 (103) Campus 4.82% Senior Notes - 2042 63,491 64,006 (515) Integrated Marketplace 3.55% Senior Note - 2024 68,250 70,000 (1,750) Senior Notes - 2024 98,750 100,000 (1,250) Other Long Term Liabilities 10,154 10,519 (365) Total Long Term Liabilities 259,044 268,777 (9,733)
Net Income (6,883) (1,306) (5,578) Members' Equity (30,728) (29,422) (1,306) Total Members' Equity (37,612) (30,728) (6,883)
TOTAL LIABILITIES & EQUITY $325,095 $339,520 ($14,424)
Southwest Power PoolBalance SheetJune 30, 2013(in thousands)
Page 5 of 15
Project2013
Budget Q1 2013 Q2 2013 Q3 2013 Q4 20132013
Forecast2014
Forecast2015
ForecastPrior
Year(s)
TOTAL PROJECT
FORECAST
TOTAL PROJECT BUDGET
Over/(Under) Budget
Existing / Carryover Projects
IT Netezza Upgrade 2,263$ 1,592$ -$ -$ 671$ 2,263$ 177$ 120$ 519$ 3,078$ 3,038$ 40$ Centralized Modeling (CMT & MCST) 355 308 63 61 73 505 - - 2,011 2,516 2,455 62 EMS Marketplace Readiness 361 80 93 73 93 340 48 - 353 741 714 27 New ICCP Architecture-closed 311 66 65 - - 130 - - 355 485 665 (180) Ops Automation DC Ties-closed 200 29 - - - 29 - - 29 58 332 (274) Ops Automation OATI -closed 100 - - - - - - - 15 15 180 (165) High Availability * - 153 (30) - - 123 - - - 123 - 123 Credit Stacking Tool * - 142 128 - - 269 - - - 269 - 269 Software (including HR upgrade, other) * - (27) 27 - - 0 - - - 0 - 0 Facility * - 173 25 - - 197 - - - 197 - 197
Total Existing / Carryover 3,590$ 2,515$ 371$ 134$ 837$ 3,857$ 225$ 120$ 3,282$ 7,484$ 7,385$ 99$
SOUTHWEST POWER POOL2013 - 2015 FORECAST
CAPITAL COST PROJECTIONS
The Netezza Upgrade and EMS Marketplace Readiness projects are expected to come within 1% of the original budget.
The Centralized Modeling Tool / Model Change Submission Tool project began in mid-2011. The project scope has evolved as the Integrated Marketplace development has been underway. The current estimate includes post go-live support and puts the project at $62K over the original estimates.
New ICCP Architecture hardware/software purchase planned for 2013 was purchased in 2012 at a lower cost, causing the favorable variance to the budget.
Both of the Ops Automation project costs are expected to be less than budget for various reasons. For the OATI project, a number of items were removed from the scope after the project was budgeted, and several other items were already part of OATI functionality, requiring only configuration and testing efforts. The scope changes were related to items in which the savings in manual effort did not justify the cost of automation. For the DC Ties project, much of the requirements development and testing, originally assumed to be performed by outside consultants, was performed by SPP staff.
* See notes on next page
Page 6 of 15
Project2013
Budget Q1 2013 Q2 2013 Q3 2013 Q4 20132013
Forecast2014
Forecast2015
ForecastPrior
Year(s)
TOTAL PROJECT
FORECAST
TOTAL PROJECT BUDGET
Over/(Under) Budget
SOUTHWEST POWER POOL2013 - 2015 FORECAST
CAPITAL COST PROJECTIONS
* The 2012 Extension items were budgeted for and initially expected to have been completed in 2012.
The PRPC closed out the High Availability project at the end of 2012, as it was originally assumed to be complete. Some of the additional expense recorded in 2013 was reclassified to IT foundation in Q2.
The 2012 Software project reflects a credit in March which relates to a prior year correction for an HR software upgrade. This was assumed to be paid and complete in December; however, the final payment will actually be paid upon completion of training during the 2nd quarter ($31K).
Miscellaneous Facility expenses from the 2012 budget were incurred in 2013, including final payments due for interior walls, copy room cabinetry and audio/visual equipment. The final retainage was paid to the contractor in March ($100K).
2012 Extension projects - prior estimates not carried into 2013 budget:
Original 2012 2013 Final Proj Budget Ending Bal Activity Estimate
High Availability $5,120 $1,598 $ 123 $1,721Credit Stacking Tool $ 295 $ 126 $ 269 $ 395Facility $88,553 $83,872 $ 197 $84,069
Page 7 of 15
Project2013
Budget Q1 2013 Q2 2013 Q3 2013 Q4 20132013
Forecast2014
Forecast2015
ForecastPrior
Year(s)
TOTAL PROJECT
FORECAST
TOTAL PROJECT BUDGET
Over/(Under) Budget
SOUTHWEST POWER POOL2013 - 2015 FORECAST
CAPITAL COST PROJECTIONS
2013 New Projects
IT Data Center Migration Phase II 620$ -$ -$ 380$ 240$ 620$ 570$ -$ -$ 1,190$ 1,190$ -$ (IT Progress) Aurea ESB Replacement 50 - - 50 - 50 781 219 - 1,050 950 100 IT Portal 498 - 76 50 91 216 - - - 216 498 (282) ETSE 3.0 Transmission Settlements (2015) - - - - - - - 3,775 - 3,775 3,500 275 OPS DTS Upgrade to TTSE (2015) - - - - - - - 2,206 - 2,206 2,908 (702) IT EMS upgrade (2014-2015) - - - - - - 1,297 399 - 1,696 2,000 (304) Integration of IssueTrak with Remedy (2014) - - - - - - - - - - 150 (150)
Total New Projects 1,168$ -$ 76$ 480$ 331$ 886$ 2,648$ 6,599$ -$ 10,133$ 11,196$ (1,063)$
Projects for the IT Data Center Migration and IT Progress EBS Replacement (recently changed to Aurea EBS Replacement), which carry over into 2014, were recently approved by SPP Executives to be included in the 2014 budget. The projects are scheduled to begin in 2013, and forecasts have been updated based on recently submitted 2014 budget data.
The IT Portal project forecast was reduced by $282K. Although all consulting was budgeted as capital expense, part of the work expected does not qualify as capitalized expense, (i.e. documenting guidelines, training employees and defining processes).
All other new projects are still on target to begin in 2014 or 2015, and forecasts have been updated based on recently submitted 2014 budget data.
NOTE: Budget amounts represent estimates established in the original 2013 - 2015 budget. Many of the future year(s) calculations during the 2013 budget cycle are considered rough-order-of-magnitude (ROM) estimates, as the estimates were determined before the project scopes were defined. Forecast numbers represent updated estimates to be included in the 2014 - 2016 budget.
Page 8 of 15
Project2013
Budget Q1 2013 Q2 2013 Q3 2013 Q4 20132013
Forecast2014
Forecast2015
ForecastPrior
Year(s)
TOTAL PROJECT
FORECAST
TOTAL PROJECT BUDGET
Over/(Under) Budget
SOUTHWEST POWER POOL2013 - 2015 FORECAST
CAPITAL COST PROJECTIONS
Integrated Marketplace / CBA
Integrated Marketplace 21,006$ 9,565$ 8,443$ 9,261$ 7,783$ 35,052$ 6,507$ -$ 71,048$ 112,606$ 112,535$ 71$ Consolidated Balancing Authority 756 304 5 261 90 660 - - 1,900 2,561 2,477 84
Total Integrated Marketplace / CBA 21,762$ 9,869$ 8,448$ 9,522$ 7,873$ 35,712$ 6,507$ -$ 72,948$ 115,167$ 115,012$ 155$
IM Capitalized Interest (not included in balance) 2,711$ 800$ 734$ 613$ 565$ 2,711$ 641$ -$ 3,088$ 6,440$ 6,453$ (14)$
The IM project is currently forecasted at $155K more than the board approved target of $115 million. This is an unfavorable movement of approximately $90k from the May 31st report. Significant changes from the prior month include the following:
1). Additional consulting for the development of a web Tag system mirroring process ($187K)
2). Unbudgeted monitoring analytics development ($50K)
3). Support savings associated with Nexant ($80K), Accenture ($51K), and Delphi / Utilicast ($18K)
Page 9 of 15
Project2013
Budget Q1 2013 Q2 2013 Q3 2013 Q4 20132013
Forecast2014
Forecast2015
ForecastPrior
Year(s)
TOTAL PROJECT
FORECAST
TOTAL PROJECT BUDGET
Over/(Under) Budget
SOUTHWEST POWER POOL2013 - 2015 FORECAST
CAPITAL COST PROJECTIONS
Market Post Go-Live Projects
Combined Cycle Enhancements 380$ -$ -$ 190$ 190$ 380$ 5,965$ 150$ -$ 6,495$ 3,800$ 2,695$ Regulation Compensation (FERC Order 755) 365 - - 177 188 365 2,133 99 - 2,597 3,785 (1,188) Long-Term TCRs (LTTCRs) 429 - - 102 113 215 4,316 - - 4,531 1,510 3,021 Market to Market 472 - - 285 329 615 5,086 397 - 6,098 1,416 4,682 AFC Granularity Changes for TSRs (2014) - - - - - - 1,363 - - 1,363 1,363 - Sunset Clause for Load Submittal Legacy BAs (2014) - - - - - - - 156 - 156 156 - Assets Pseudo-Tying Out of SPP BA (2014) - - - 99 70 169 - - - 169 130 39 Marketplace Data for MPs Post Go-Live (2014) - - - - - - - 50 - 50 50 0
Total Market Post Go-Live 1,646$ -$ -$ 854$ 891$ 1,744$ 18,863$ 852$ -$ 21,459$ 12,210$ 9,249$
Mitigating Offer Data Submission System * 376 - - 336 41 376 - - - 376 400 (24)
Market Post Go-Live projects were recommended by the Project Review & Prioritization Committee (PRPC) and approved by Executives to be included in the upcoming 2014 budget. Forecasts for 2013 -2015 have been updated to reflect new estimates.
* The Mitigating Offer Data Submission System project is a web page for market participants to submit required cost data to Market Monitoring Unit (MMU) and is a FERC ordered regulatory requirement to be completed by the March 2014 go-live date. The project costs were included in the request for additional funding for the Integrated Marketplace, and are reflected in the IM project total of $115M.
NOTE: Budget amounts represent estimates established in the original 2013 - 2015 budget. Many of the future year(s) calculations during the 2013 budge cycle are considered rough-order-of-magnitude (ROM) estimates, as the estimates were determined before the project scopes were defined. Forecast numbers represent updated estimates to be included in the 2014 - 2016 budget.
Page 10 of 15
Project2013
Budget Q1 2013 Q2 2013 Q3 2013 Q4 20132013
Forecast2014
Forecast2015
ForecastPrior
Year(s)
TOTAL PROJECT
FORECAST
TOTAL PROJECT BUDGET
Over/(Under) Budget
SOUTHWEST POWER POOL2013 - 2015 FORECAST
CAPITAL COST PROJECTIONS
IT Foundation
Systems Administration Foundation 3,503$ 1,631$ 247$ 835$ 800$ 3,514$ 1,464$ 1,614$ -$ 6,593$ 6,582$ 10$ Network/Telecom Foundation 1,742 (11) 255 313 1,302 1,858 1,139 1,452 - 4,449 4,333 116 Applications Foundation 809 77 27 917 - 1,021 1,040 1,950 - 4,011 3,799 212 Service Management Foundation 600 356 208 228 323 1,116 428 360 - 1,904 1,387 517 Service Delivery Foundation 291 - 86 - 205 291 96 96 - 483 483 (0) Environmental Ops Foundation 100 - - - 225 225 79 83 - 386 261 125
Total IT Foundation 7,045$ 2,053$ 824$ 2,294$ 2,855$ 8,026$ 4,246$ 5,555$ -$ 17,826$ 16,846$ 980$
The Network / Telecom foundation project is expected to be $116K over budget due to additional expense for more efficient Juniper equipment , which was not available in 2012.
The Service Mgmt Foundation project is expected to be over budget primarily due to the following additions which were not included in the original 2013 budget (1) Remedy Upgrade Project ($345K) and (2) Service Delivery expenses for Event Management upgrade ($103K ) and Tripwire licenses ($25K ). All expenses were included in the 2012 budget, but not incurred until 2013.
The Environmental Operations Foundation project exceeds the 2013 budget due to the carryover from 2012 for the addition of Maumelle HVAC ($125K).
NOTE: Foundation budgets are not carried forward; therefore Project Budget represents current year budget only.
Page 11 of 15
Project2013
Budget Q1 2013 Q2 2013 Q3 2013 Q4 20132013
Forecast2014
Forecast2015
ForecastPrior
Year(s)
TOTAL PROJECT
FORECAST
TOTAL PROJECT BUDGET
Over/(Under) Budget
SOUTHWEST POWER POOL2013 - 2015 FORECAST
CAPITAL COST PROJECTIONS
Operations Foundation
Marketplace MOS Enhancements (2014-2015) -$ -$ -$ -$ -$ -$ 750$ 750$ -$ 1,500$ 1,500$ -$ Legacy Applications 300 122 44 79 7 251 400 325 - 976 1,000 (24)
Total Operations Foundation 300$ 122$ 44$ 79$ 7$ 251$ 1,150$ 1,075$ -$ 2,476$ 2,500$ (24)$
Miscellaneous Capital Spend
ETS Foundation-Alstom 75$ -$ -$ -$ -$ -$ 75$ 75$ -$ 150$ 225$ (75)$ FERC Order 1000 Regional RFP 165 - - - - - 165 30 - 195 225 (30) Stochastic Planning 70 - - - - - - - - - 200 (200) Redundant EnFuzion Node and PSSE Lock Ph 2 23 - 23 - - 23 - - - 23 23 - ITP Data Repository 5 - - - - - - - - - 10 (10) Update PROMOD to Server Solution 10 - - - - - - - - - 20 (20)
Total Miscellaneous Capital Spend 348$ -$ 23$ -$ -$ 23$ 240$ 105$ -$ 368$ 703$ (335)$
TOTAL CAPITAL COST PROJECTIONS 35,858$ 14,559$ 9,785$ 13,363$ 12,793$ 50,499$ 33,877$ 14,307$ 76,230$ 174,913$ 165,851$ 9,062$
There are no PRRs necessitating changes to the EIS market at this time; therefore, the ETS Foundation project forecast for 2013 has been removed. Forecasts for 2014 - 2015 have been updated based on recently submitted 2014 budget data.
FERC made a ruling on Order 1000 Regional RFP in mid-July. Adjustments will be made to upcoming forecasts after thorough consideration of the impacts associated with the FERC ruling.
Expenses for the Stochastic Planning, ITP Data Repository and PROMOD update projects have been removed from the forecast given the projects are on hold.
Due to the Integrated Marketplace (IM) program resources and systems, SPP Operations is focused on IM activities. Any expenditures for the remainder of 2013 Legacy Applications are only reserved for critical unforeseen issues.
Page 12 of 15
Current Month Actual vs. Budget Full Year Forecast vs. BudgetActual Budget Over/(Under) FY 2013 FY 2013 Over/(Under)Jun-13 Jun-13 Budget Forecast Budget Budget
Administration 49 52 (3) 49 52 (3)
Corporate Services 29 29 0 29 29 0
Government Affairs & Public Relations 3 4 (1) 3 4 (1)
Process Integrity 46 47 (1) 47 47 0
Compliance & Market Monitoring 26 27 (1) 27 27 0
SPP Regional Entity 28 32 (4) 31 32 (1)
Information Technology 138 143 (5) 143 143 0
Markets 6 6 0 6 6 0
Operations 151 158 (7) 158 158 0
Engineering Planning 39 44 (5) 40 44 (4)
Engineering Other 34 37 (3) 38 37 1
Regulatory Policy & General Counsel 23 24 (1) 24 24 0
TOTAL HEADCOUNT 572 603 (31) 595 603 (8)
Forecast vs. Budget
Original 2013 End-of-Year Budget 603Stochastic Planning positions (on hold) removed from 2013 forecast (2)Government Affairs positions (on hold) removed from 2013 forecast (2)Order 1000 Business Analyst removed from 2013 forecast (1)Settlement Analyst backfill removed from 2013 forecast (1)Eliminated backfill for Dec 2012 resignation (RE part-time clerk) (1)Eliminated duplicate Engineering position (1)
Revised 2013 End-of-Year Forecast 595
Revised 2013 End-of-Year Forecast 595Stochastic Planning positions remain on Org Chart 2Government Affairs positions remain on Org Chart 2
Current Organizational Chart Total 599
Southwest Power PoolHeadcount Analysis
June 30, 2013
Page 13 of 15
2013 HR Job Tracker
Req. # Position Dept # Dept Name StatusExtern
12-024 Sr. Compliance Specialist 130 RE - Compliance
12-088 Engineer II 440 GI Studies
12-104 Manager 900 Regulatory
12-105 Regulatory Analyst III 900 Regulatory
12-126 Sr. Business Analyst 510 IT Apps-Data Mgmt
12-129 Engineer II 460 Economic Planning
12-130 Sr. Engineer 410 Steady State Planning
12-080 IT Specialist II 510 IT Apps-Reliability
12-100 Engineer II 850 Modeling & Data Integrity
12-122 Service Desk Analyst (Part-Time) 580 IT Service Desk
12-133 Project Manager 560 Project Management
13-001 Sr. VP, Govermental Affairs 110 Officers
12-114 Complance Analyst II 230 Compliance
12-134 Supervisor, Reliability Coordination 820 Systems Operations
12-136 Market Design Analyst I/Engineer I 720 Market Design
12-131 Operator 820 Systems Operations
13-002 LMS Support and Web/CBT Developer (filled 2012) 340 Customer Training
12-071 Engineer II 410 Steady State Planning
12-132 Operator 820 Systems Operations
12-025 Sr. Compliance Specialist 130 RE - Compliance
12-116 Executive Director 130 Regional Entity
12-125 Manager of Finance & Process Improvement 170 Regional Entity
12-135 Engineer II 420 Engineer II
12-137 Engineer II 430 Modeling
13-004 Customer Trainer 340 Customer Training
13-010 IT Programmer Analyst II (ESB & Portal) 510 IT Apps Arch Settlements Supp
13-014 Market Analyst I, IM 840 Markets Administration
13-017 IT Senior Programmer Analyst (CMS) 510 IT Apps/Settlements
13-023 Programmer Analyst I (TCR) 510 Relaibility Tariff/Scheduling
13-009 IT Programmer Analyst II (POPS) 510 Markets, Requirements, Test
13-016 Operator III - Day-Ahead Market, IM 840 Markets Administration
13-021 Sr. Data Warehouse Developer 530 Data Management
13-007 Engineer I, Order 1000 460 Economic Planning
13-019 Engineer I 430 Modeling
13-003 Talent Management Specialist 150 Human Resources
13-006 Engineer I, Order 1000 410 Steady State Planning
13-018 Talent Management Administrator 150 Human Resources
13-005 Business Analyst II (removed from forecast) 120 Purchasing
13-011 IT Programmer Analyst I (CMT) 510 Relaibility Tariff/Scheduling
13-012 Attorney 330 Legal
13-008 Interregional Coordinator, Order 1000 8200 Interregional Coordination
13-013 Sr. Tariff Administrator, IM 820 Systems Operations
13-020 Manager, Stochastic Planning (on hold) 8000 Engineering Planning
13-022 Sr. Engineer, Stochastic Planning (on hold) 8000 Engineering Planning
Page 14 of 15
2013 HR Job Tracker
Req. # Position Dept # Dept Name StatusExtern
13-024 Sr. Legislative Analyst 310 Government Affairs
13-025 Human Resouce Generalist I 150 Human Resources
13-028 Network/Telecom Administrator 580 IT Enterprise Operations
13-033 Business Analyst II 510 IT Applications
13-030 Sr. Data Anaylst 510 IT Applications, Data Management
13-034 Sr. Test Analyst 510 IT Applications
13-027 Engineer II, Reliablity Standards 200 Interregional Affairs
13-031 Sr. Operator 820 Systems Operations
13-032 Sr. Operator 820 Market Operations
13-035 Part-Time Service Desk Analyst 580 IT Enterprise Operations
13-043 Operator II 820 Systems Operations
13-044 Operator III 820 Systems Operations
13-046 Lead Compliance Analyst 230 SPP Compliance
13-048 Business Analyst II 510 IT Applications
13-045 Lead Operator 820 Systems Operations
13-047 Lead Architect, Data Warehouse 510 IT Applications
13-049 Part-Time Service Desk Analyst 580 IT Operations
13-029 Sr. Planning Anaylst 470 Engineering Spec Studies / Resource Planning
Remaining 2012 Positions in Blue: 12-xxx 2013 YTD Budgeted Positions Filled 132013 Budgeted Positions Highlighted in Grey: 13-001 thru 13-023 2013 YTD Replacement Positions Filled 6Replacement Positions Highlighted in Yellow: 13-024 thru 13-xxx 2013 YTD Total Hires 19
2012 Positions Filled in 2013 17Total Positions Filled 36
Status Legend 2013 2012 TotalInactive 7 3 10Active, Not Posted 3 0 3Active, Posted 11 2 13Filled 19 17 36
Hire LegendInternal 5 5 10External 14 12 26
Total 19 17 36
05/31 Ending Active Headcount 569Resignations during May -3June External Hires 6
06/30 Ending Active Headcount 5722012 Open 52013 Open 212013 Positions eliminated * -3
2013 Year End Forecast 595
* Resignations w/o backfill are reflected in Active reduction (total 8 eliminated/on hold)
Page 15 of 15
Corporate Metrics 2nd Quarter 2013
July 23, 2013
1 Congestion
2 Regional Control Performance
3 Transmission Utilization Proxy
4 EIS Prices and Price Range
5 Congestion - Uplift
6 Market Liquidity
Financial Metrics
7 SPP Admin Fee performance
8 Budget Performance Monitor
9 Financial Settlement Index
10 Financial Disputes Index
11 Employee Turnover
12 Recruiting
13 Compliance with NERC Standards
14 IT System Performance
15 Strategic Plan Progress
16 Studies
Metrics Definitions
Supplement - Regulatory Activity Update & Outlook
DISCLAIMER
The data and analysis in this report are provided for informational purposes only and shall not be considered or relied upon as market advice or market settlement data.
Southwest Power Pool (SPP) makes no representation or warranties of any kind, express or implied, with respect to the accuracy or adequacy of the information contained herein.
SPP shall have no liability to recipients of this information or third parties for the consequences arising from errors or discrepancies in this information, or for any claim, loss or damage of any kind or nature whatsoever arising out of
or in connection with (i) the deficiency or inadequacy of this information for any purpose, whether or not known or disclosed to the authors, (ii) any error or discrepancy in this information, (iii) the use of this information, or (iv) a loss of
business or other consequential loss or damage whether or not resulting from any of the foregoing.
Learning & Growth
Performance
Southwest Power Pool
Corporate Metrics
Table of Contents
Transmission & Market Indicators
1a. Congestion
Time in hours Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 mo
Binding & Breached Time 631 478 585 650 720 636 690 623 535 534 443 674 694 581 628 505 555 625 617
Over Limit Time 123 215 301 493 367 344 315 374 169 121 252 335 264 164 413 82 156 277 301
% Tags/ Schedules Curtailed (GWh) 0.50% 0.22% 0.31% 0.73% 0.73% 0.69% 1.13% 0.87% 0.39% 0.39% 0.18% 0.34% 0.95% 0.35% 0.34% 0.54% 0.62% 0.61% 0.59%
Tran
smis
sion
& M
arke
t Ind
icat
ors
Monthly Average
0.00%
0.20%
0.40%
0.60%
0.80%
1.00%
1.20%
1.40%
1.60%
-
100
200
300
400
500
600
700
800
% T
ags/
Sche
dule
s C
urta
iled
Hou
rs
Binding & Breached Time Over Limit Time % Tags/ Schedules Curtailed (GWh)
-
200
400
600
800
2010 2011 2012 12 mo
Average Monthly Binding & Breached Time (hrs)
- 50
100 150 200 250 300
2010 2011 2012 12 mo
Average Monthly Over Limit Time (hrs)
1b. Congestion - Curtailments
in GWh Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 mo
Tag Curtailments 17.3 7.6 13.0 34.0 51.9 83.1 99.1 55.9 23.7 28.4 14.9 20.9 28.2 21.7 10.1 85 87 42 39
Market (Schedules) Curtailments 88.8 46.3 71.4 202.5 162.9 82.4 149.2 127.4 70.5 66.8 24.2 56.4 177.6 59.2 78.6 49 67 105 105
TOTAL Curtailments 106.1 53.9 84.4 236.5 214.9 165.5 248.2 183.3 94.2 95.3 39.1 77.3 205.8 80.9 88.8 134 154 148 144
Total Tags/ Schedules 21,016 24,343 27,262 32,404 29,460 24,023 22,022 21,004 24,285 24,702 21,288 22,960 21,662 23,084 26,010 24,599 24,689 24,343 24,409
% Tags/ Schedules Curtailed 0.50% 0.22% 0.31% 0.73% 0.73% 0.69% 1.13% 0.87% 0.39% 0.39% 0.18% 0.34% 0.95% 0.35% 0.34% 0.54% 0.62% 0.61% 0.59%
Tran
smis
sion
& M
arke
t Ind
icat
ors
0.00%
0.20%
0.40%
0.60%
0.80%
1.00%
1.20%
-
50
100
150
200
250
300
350
% T
ags/
Sche
dule
s C
urta
iled
GW
h C
urta
iled
Market (Schedules) Curtailments Tag Curtailments % Tags/Schedules Curtailed
-
20
40
60
80
100
2010 2011 2012 12 mo
Tag Curtailments (GWh)
- 20 40 60 80
100
2010 2011 2012 12 mo
Market Curtailments (GWh)
1c. Congestion - TLR / CME Time
in hours Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 mo
Level 3A 213 199 266 251 364 443 467 343 138 361 327 359 166 177 120 949 517 369 293 Level 3B 8 17 19 21 27 33 27 34 11 18 11 22 9 14 23 166 46 23 21 Level 4 25 31 34 1 0 0 6 6 0 4 31 0 0 0 0 41 77 9 4 Level 5A 36 128 126 430 171 117 97 45 24 103 146 31 20 59 10 83 52 110 104 Level 5B 3 5 5 21 4 7 8 1 2 6 11 4 3 5 4 6 6 5 6 Total TLR Time 285 380 450 723 566 600 605 429 175 492 526 416 198 255 157 1,246 697 517 429 CME Time (loading >90%) 2,076 1,566 2,276 2,665 2,192 2,207 2,965 2,483 2,523 2,206 1,519 2,147 2,474 1,791 2,969 847 1,315 2,276 2,345
Tran
smis
sion
& M
arke
t Ind
icat
ors
Monthly Average in Hours
0
1,000
2,000
3,000H
ours
in T
LR /
CM
E
Level 5B Level 5A Level 4 Level 3B Level 3A CME Time (loading >90%)
-
400
800
1,200
2010 2011 2012 12 mo
Monthly Average Level 3 TLR (hrs)
-
40
80
120
2010 2011 2012 12 mo
Monthly Average Level 5 TLR (hrs)
-
20
40
60
80
100
2010 2011 2012 12 mo
Monthly Average Level 4 TLR (hrs)
-
500
1,000
1,500
2,000
2,500
2010 2011 2012 12 mo
CME Time (loading > 90%) (hrs)
1d. Congestion - Congested Intervals
Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 moUncongested Intervals 12% 36% 19% 13% 3% 12% 7% 14% 28% 28% 34% 9% 4% 22% 13% 30.8% 23.8% 14.5% 15.4%
Intervals with Binding Only 79% 58% 76% 79% 92% 82% 81% 80% 68% 68% 61% 83% 87% 73% 81% 63.8% 71.8% 79.2% 78.0%
Intervals with a Breach 9% 6% 6% 8% 5% 6% 12% 6% 4% 3% 5% 8% 9% 5% 7% 5.4% 4.4% 6.3% 6.5%
Interval = 5 minutes
Tran
smis
sion
& M
arke
t Ind
icat
ors
Average
0%
10%
20%
30%
40%
2010 2011 2012 12 mo
Uncongested Intervals
0%
20%
40%
60%
80%
100%
Uncongested Intervals Intervals with Binding Only Intervals with a Breach
0%
20%
40%
60%
80%
100%
2010 2011 2012 12 mo
Intervals with Binding Only
0%
2%
4%
6%
8%
2010 2011 2012 12 mo
Intervals with a Breach
1e. Price Contour Map (April - June 2013)Tr
ansm
issi
on &
Mar
ket I
ndic
ator
s
1f. Price Contour Map - last 12 months (July 2012 - June 2013)Tr
ansm
issi
on &
Mar
ket I
ndic
ator
s
PENMUNSTRCRA PENMUN87TCRA LAKALASTJHAW
NEORIVNEOMOR
OSGCANBUSDEA SPSNORTH_STH
GRAXFRSWEELK
TAHH59MUSFTS
MINXFRMINSET
1g. Congestion - Flowgates - last 12 months (July 2012 - June 2013)
Region Flowgate Name Flowgate Location (kV)
Avg Hourly Shadow
Price ($/MWh)
Total % Intervals
Congested
Projects Expected to Provide Some Positive Mitigation(Estimated In Service Date – Upgrade Type)
OSGCANBUSDEA Osage Switch - Canyon East [SPS] [(115) ftlo Bushland - Deaf Smith [SPS] (230) $31.93 28.1%
1. Tuco Int. – Woodward 345 kV line (May 2014 - Balanced Portfolio)2. Castro County Int. – Newhart 115 kV line (April 2015 - Regional Reliability)3. Tuco Int. – Amoco – Hobbs 345 lines (Currently on hold – ITP10)
GRAXFRSWEELK Grapevine Xfmr (230/115) [SPS] ftlo Sweetwater – Elk City (230) [CSWS] $8.10 6.0% 1.Bowers – Howard 115 kV line (June 2016 – ITPNT)
2. Altus Jct Tap – Russell 138 kV (in service 2012)
SPSNORTH_STH 5 element PTDF flowgate north to south through west Texas $3.89 15.8% 1. Randall County Interchange – Amarillo South Interchange 230 kV line (May 2013)
SHAXFRELKXFR Shamrock Xfmr (115/69) [CSWS} ftlo Elk City Xfmr (230/138) [WFEC] $2.51 1.3% 1. Elk City – Gracemont 345 kV line (March 2018 – ITP10)
PENMUNSTRCRA Pentagon – Mund (115) [WR] ftlo Stranger Creek – Craig (345) [WR-KCPL] $7.55 6.5%
1. Tap existing Swissvale – Stilwell 345 kV line at West Gardner (in service December 2012)2. Terminal upgrade for Pentagon – Mund 115 kV line (in service 2012)3. Iatan – Nashua 345 kV line (June 2015 - Balanced Portfolio)
PENMUN87TCRA Pentagon – Mund (115) [WR] ftlo 87th Street – Craig (345) [WR-KCPL] $3.63 1.9% 1. Tap existing Swissvale – Stilwell 345 kV line at West Gardner (in service December 2012)
2. Iatan – Nashua 345 kV line (June 2015 - Balanced Portfolio)
LAKALASTJHAW Lake Road – Alabama [GMOC] (161) ftlo St. Joe – Hawthorn [GMOC] (345) $3.09 1.3%
1. Axtell – Post Rock – Spearville 345 kV line, two Spearville – Comanche – Flat Ridge –Woodward 345 kV lines, and two Flat Ridge – Wichita 345 kV lines (Dec 2014 - Balanced Portfolio/Priority Projects)2. Iatan – Nashua 345 kV line (June 2015 - Balanced Portfolio)3. Nebraska City – Maryville – Sibley 345 kV line (June 2017 - Priority Projects)4. Eastowne Transformer (345/161) and decommission of Lake Road – Alabama 161 kV line (May 2013 – sponsored upgrade)
Eastern Oklahoma TAHH59MUSFTS Tahlequah-Highway 59 (161) [GRDA-OGE] ftlo Muskogee-Fort Smith (345) [OGE] $2.91 2.7% 1. Muskogee – Seminole 345kV (December 2013 - Balanced Portfolio)
SE Kansas NEORIVNEOMOR Neosho - Riverton (161) ftlo Neosho - Morgan (345) [WR-EDE] $2.91 2.7% 1. Shipe Road – East Rogers 345 kV (June 2016 - Regional Reliability)
Western Kansas MINXFRMINSET Mingo Xfmr (345/115) ftlo Mingo - Setab (345) [SECI] $2.50 3.2% 1. Axtell-Post Rock-Spearville 345 kV (in service December 2012)
2. Hitchland – Woodward 345 kV (July 2014 – High Priority)
Tran
smis
sion
& M
arke
t Ind
icat
ors
Texas Panhandle
Kansas City - Omaha Corridor
0%
10%
20%
30%
$0
$10
$20
$30
Avg Hourly Shadow Price ($/MWh) Total % Intervals Congested
2a. Regional Control Performance - CPS1 Compliance
CPS1 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 2013
>150% 6 7 8 5 7 5 7 6 7 4 7 5 7 7 6 6 4 4 6
100%-150% 14 13 12 15 13 15 13 14 13 16 13 15 13 13 14 13 16 16 14
<100% 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - - - - Tran
smis
sion
& M
arke
t Ind
icat
ors
Average
Violation if any 1 Balancing Authority has an average over the 12 month period of less than 100%.
0
2
4
6
8
10
12
14
16
18
20#
Bal
anci
ng A
utho
ritie
s
<100% 100%-150% >150%BA's with a CPS1 value of <100% are non-compliant
-
4
8
12
16
20
2010 2011 2012 2013# B
alan
cing
Aut
horit
ies
<100% 100%-150% >150%
2b. Regional Control Performance - CPS2 Compliance
CPS2 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 2013
>95% 17 14 15 13 16 16 18 17 17 18 17 15 15 13 12 17 17 17 15
90-95% 3 6 5 7 4 4 2 3 3 2 3 5 5 7 8 2 3 3 5
<90% 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - - - Tran
smis
sion
& M
arke
t Ind
icat
ors
Average
Violation if any 1 Balancing Authority has a violation in a 12 month period.
0
2
4
6
8
10
12
14
16
18
20#
Bal
anci
ng A
utho
ritie
s
<90% 90-95% >95%BA's with a CPS2 value of <90% are non-compliant
0
4
8
12
16
20
2010 2011 2012 2013
# B
alan
cing
Aut
horit
ies
<90% 90-95% >95%
3a. Transmission Utilization - $
Service (in MM $) Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 mo
Network 72.76 78.13 80.27 80.62 84.20 83.98 78.09 76.44 77.21 77.07 84.17 85.12 84.09 88.07 91.14 46.88 66.16 77.17 82.52
Firm PTP 7.45 7.63 7.73 6.30 6.20 6.12 5.68 5.97 6.73 7.41 7.84 8.07 7.25 7.35 7.56 4.80 4.65 6.50 6.87
Non-Firm PTP 0.85 0.70 0.64 0.73 0.61 0.49 0.53 0.62 1.36 0.80 0.52 0.53 0.71 0.68 0.47 0.95 0.65 0.66 0.67
Total 81.06 86.46 88.64 87.65 91.01 90.60 84.29 83.03 85.30 85.28 92.53 93.72 92.04 96.11 99.17 52.63 71.46 84.33 90.06
Tran
smis
sion
& M
arke
t Ind
icat
ors
Monthly Average
0
20
40
60
80
100in
mill
ions
$
Non-Firm PTP Firm PTP Network
$0
$20
$40
$60
$80
$100
2010 2011 2012 12 mo
in m
illio
ns
Non-Firm PTP Firm PTP Network
3d. Transmission Service Requests
Confirmed Refused Confirmed Refused Confirmed Refused Confirmed RefusedHourly 20,411 8,475 30,473 9,525 26,973 8,733 23,308 8,714Daily 9,218 25,949 3,286 19,098 1,795 13,676 669 4,652Weekly 789 3,277 987 4,723 520 5,796 613 2,198Monthly 16,686 52,977 6,436 54,967 5,503 107,103 5,265 17,854Yearly 630,697 32,055 724,067 62,545 792,533 104,685 398,202 58,226Total 677,801 122,733 765,249 150,858 827,324 239,993 428,057 91,644
2013 (Jan-Jun)2010 2011 2012
Tran
smis
sion
& M
arke
t Ind
icat
ors
0
200,000
400,000
600,000
800,000
1,000,000
Hou
rly
Dai
ly
Wee
kly
Mon
thly
Year
ly
Hou
rly
Dai
ly
Wee
kly
Mon
thly
Year
ly
Hou
rly
Dai
ly
Wee
kly
Mon
thly
Year
ly
Hou
rly
Dai
ly
Wee
kly
Mon
thly
Year
ly
2010 2011 2012 2013
GW
h Confirmed Refused
0
20,000
40,000
60,000
80,000
100,000
120,000
Hou
rly
Dai
ly
Wee
kly
Mon
thly
Year
ly
Hou
rly
Dai
ly
Wee
kly
Mon
thly
Year
ly
Hou
rly
Dai
ly
Wee
kly
Mon
thly
Year
ly
Hou
rly
Dai
ly
Wee
kly
Mon
thly
Year
ly
2010 2011 2012 2013
GW
h
4a. EIS Price and Price Range - for three months ending
AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KMEA KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAC TEAN WFES WRGS
MP Max 132 133 128 131 129 132 291 128 163 129 129 129 132 130 197 134 135 133 148 278 228 130 138 129
MP Avg 26.35 26.35 22.55 26.26 25.34 25.76 32.96 26.23 27.15 26.32 25.61 25.45 23.32 23.04 23.55 26.84 26.70 23.49 22.46 32.72 26.46 23.13 26.65 25.35
MP Min -178 -176 -205 -180 -187 -178 -25 -187 -187 -186 -185 -186 -195 -200 -209 -173 -172 -193 -223 -27 -181 -198 -172 -186
Volatility 44% 43% 65% 44% 48% 41% 46% 46% 50% 45% 43% 44% 66% 65% 75% 41% 41% 65% 75% 46% 53% 64% 42% 42%
Tran
smis
sion
& M
arke
t Ind
icat
ors
June 2013
$26.83 40%
0%
20%
40%
60%
80%
100%
120%
$22
$24
$26
$28
$30
$32
$34
Vola
tility
(Sta
ndar
d D
evia
tion
/ Ave
rage
)
LIP
($/M
Wh)
MP Volatility SPP Avg LIP = MP Avg LIP SPP Volatility
4b. EIS Price and Price Range - for 12 months ending
AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KMEA KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAC TEAN WFES WRGS
MP Max 225 257 200 223 223 224 291 225 227 226 227 214 202 199 246 234 242 359 209 278 228 199 242 215
MP Avg 25.23 25.20 21.68 25.75 24.18 24.93 27.27 24.83 25.68 25.02 24.78 24.13 22.50 22.19 23.96 25.11 25.13 22.72 22.62 27.59 25.39 22.32 25.01 23.99
MP Min -178 -176 -205 -180 -187 -178 -69 -187 -187 -186 -185 -186 -195 -200 -209 -173 -172 -193 -223 -72 -181 -198 -172 -186
Volatility 41% 43% 60% 45% 44% 40% 42% 43% 47% 44% 44% 42% 58% 58% 70% 41% 42% 61% 66% 44% 46% 58% 42% 41%
Tran
smis
sion
& M
arke
t Ind
icat
ors
June 2013
$24.96 39%
0%
20%
40%
60%
80%
$20
$22
$24
$26
$28
Vola
tility
(Sta
ndar
d D
evia
tion
/ Ave
rage
)
LIP
($/M
Wh)
MP Volatility SPP Avg LIP = MP Avg LIP SPP Volatility
4c. EIS Prices
in $ Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 moMonthly AvgLIP ($/MWh) 18.42 22.25 21.33 27.33 25.00 22.19 24.34 23.68 21.85 23.35 23.96 27.26 27.59 27.52 25.35 31.33 29.28 22.29 24.96
PEPL GasCost ($/MMBtu) 1.85 2.29 2.33 2.80 2.72 2.70 3.19 3.42 3.22 3.28 3.28 3.69 4.03 3.87 3.56 4.17 3.89 2.64 3.31
Average
Tran
smis
sion
& M
arke
t Ind
icat
ors
$0
$2
$4
$6
$8
$10
$0
$10
$20
$30
$40
$50
Jun11
Jul 11 Aug11
Sep11
Oct11
Nov11
Dec11
Jan12
Feb12
Mar12
Apr12
May12
Jun12
Jul 12 Aug12
Sep12
Oct12
Nov12
Dec12
Jan13
Feb13
Mar13
Apr13
May13
Jun13
Gas
Cos
t (Pa
nhan
dle
East
ern
Pipe
line)
$/M
MB
tu
Electricity (LIP) 12 month avg LIP Gas (PEPL) 12 month avg Gas
Elec
tric
ity P
rice
(LIP
) $/M
Wh
4d. EIS Prices - annual
in $ 2007 2008 2009 2010 2011 2012 2013* * through first six months of 2013Monthly Avg LIP ($/MWh) 49.42 53.21 27.89 31.33 29.28 24.96 25.86
PEPL Gas Cost ($/MMBtu) 6.15 7.12 3.31 4.17 3.89 3.31 3.62
Tran
smis
sion
& M
arke
t Ind
icat
ors
Average
$0
$2
$4
$6
$8
$10
$12
$0
$10
$20
$30
$40
$50
$60
2007 2008 2009 2010 2011 2012 2013*
Elec
tric
ity P
rice
(LIP
) $/M
Wh
Gas
Cos
t (Pa
nhan
dle
East
ern
Pipe
line)
$/M
MB
tu
Monthly Avg LIP ($/MWh) PEPL Gas Cost ($/MMBtu)
5. Revenue Neutrality Uplift
in thousands $ Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 mo
Total Uplift -1,269 233 -399 -815 -580 -938 937 -1,077 -692 759 -669 -1,130 -610 -1,165 -381 -2,398 -13,769 -7,463 -6,360
Revenue Neutrality Uplift (RNU) ensures settlement payments/receipts for eachhourly settlement interval equal zero.• Positive RNU - SPP receives insufficient revenue and collects from market participants.• Negative RNU - SPP receives excess revenue, which must be credited back to market participants.
-3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000 -3000
Tran
smis
sion
& M
arke
t Ind
icat
ors
Total
-$3,000
-$2,000
-$1,000
$0
$1,000
$2,000in
thou
sand
s $
-$16,000
-$12,000
-$8,000
-$4,000
$0
$4,000
2010 2011 2012 12 mo
in th
ousa
nds $
6a. Market Liquidity - Offered and Dispatchable
Daily Average Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 mo
Dispatchable MW 11,304 13,244 16,564 17,693 16,938 14,833 12,266 11,792 12,857 13,613 12,903 12,455 11,360 12,351 16,077 11,221 12,738 13,693 13,762
Total Offered MW 27,255 31,560 38,155 42,357 39,584 33,311 27,697 26,998 29,629 30,762 28,789 27,415 26,215 28,411 35,764 33,917 32,079 31,781 31,411
% of Total Offered 41% 42% 43% 42% 43% 45% 44% 44% 43% 44% 45% 45% 43% 43% 45% 33.1% 39.7% 43.1% 43.8%
Tran
smis
sion
& M
arke
t Ind
icat
ors
Monthly Average
0%
20%
40%
60%
80%
0
10,000
20,000
30,000
40,000
Jun 11 Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13
% o
f Tot
al O
ffere
d
MW
(dai
ly a
vera
ge)
Dispatchable MW Total Offered MW % of Total Offered
0
10,000
20,000
30,000
40,000
Dispatchable MW Total Offered MWMW
(dai
ly a
vera
ge)
2010 2011 2012 12 mo0%
10%
20%
30%
40%
50%
2010 2011 2012 12 mo
% of Total Offered
6b. Market Liquidity - Volume
Average Daily Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 mo
Sales (MWh) 70,807 67,753 78,720 83,253 83,685 71,518 65,963 70,377 75,919 70,856 65,433 61,724 69,420 68,504 88,415 55,116 60,380 73,795 72,922
Sales ($000's) 1,227 1,461 1,658 2,194 2,051 1,480 1,466 1,541 1,583 1,598 1,491 1,597 1,799 1,804 2,123 1,651 1,695 1,571 1,727
Tran
smis
sion
& M
arke
t Ind
icat
ors
Monthly Average
$0
$1,000
$2,000
$3,000
$4,000
$5,000
0
20,000
40,000
60,000
80,000
100,000
Jun 11 Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13
Sale
s ($
000s
)
Sale
s M
Wh
EIS Market Sales Volumes (average daily volume by month)
Sales (MWh) Sales ($000's)
0
20,000
40,000
60,000
2010 2011 2012 12 mo
Aver
age
Dai
ly S
ales
(MW
h)
0
1,000
2,000
2010 2011 2012 12 mo
Aver
age
Dai
ly S
ales
($00
0's)
7. SPP Admin Fee Performance
2005 2006 2007 2008 2009 2010 2011 2012 2013Budgeted Net Revenue Required ($000s) 44,391$ 45,688$ 52,819$ 61,462$ 56,478$ 68,358$ 78,368$ 89,560$ 121,814$ Budgeted Load (000's) 253,489 258,556 288,649 312,496 331,324 333,458 343,000 353,453 360,915 Budgeted NRR / Budget Load 0.175$ 0.177$ 0.183$ 0.197$ 0.170$ 0.205$ 0.228$ 0.253$ 0.338$
Approved Admin Fee 0.160 0.160 0.190 0.190 0.170 0.195 0.210 0.255 0.315 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Actual Net Revenue Required ($000's) 38,714$ 48,613$ 47,998$ 58,081$ 59,837$ 63,497$ 80,841$ 84,776$ 121,496$ Actual Load (000's) 267,239 286,446 301,098 296,135 328,175 331,610 341,438 361,686 358,670 Actual NRR / Actual Load 0.145$ 0.170$ 0.159$ 0.196$ 0.182$ 0.191$ 0.237$ 0.234$ 0.339$
EIA-411 Load Growth Forecast 3.05% -0.60% 1.80% 2.10% 2.40% -1.00% 2.21% 0.00% 0.00%
Actual Load Growth 8.82% 7.19% 5.12% -1.65% 10.82% 1.05% 2.96% 5.93% -0.83%
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Note: Budgeted 2013 figures cover the entire 2013 calendar year, while actual 2013 figures cover the period through the date of this report.
$0.12
$0.14
$0.16
$0.18
$0.20
$0.22
$0.24
$0.26
$0.28
$0.30
$0.32
$0.34
$0.36
2005 2006 2007 2008 2009 2010 2011 2012 2013
$ pe
r MW
h
Approved Admin Fee Budgeted NRR / Budget Load Actual NRR / Actual Load
8. Budget Performance Monitor
in thousands $ Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13
Budgeted Operating Expense 12,907 12,570 12,692 12,843 12,368 12,083 12,773 12,582 12,811 13,268 12,594 13,307
Actual Operating Expense 12,516 11,692 12,402 11,374 11,977 13,026 11,635 12,405 12,571 12,644 12,156 12,603
Monthly Variance:Over Budget / (Under Budget) (391) (878) (290) (1,469) (391) 943 (1,138) (177) (240) (624) (438) (704)
12 month Cumulative Variance:Over Budget / (Under Budget) (391) (1,268) (1,558) (3,027) (3,418) (2,475) (3,613) (3,790) (4,030) (4,654) (5,092) (5,796)
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-$8,000
-$6,000
-$4,000
-$2,000
$0
$2,000
Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13
in th
ousa
nds
$
Operating Expense Variance
Monthly Variance Cumulative Variance
9. Financial Settlement Index
in thousands Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 12 moLate Transmission Payments $4 $322 $55 $2,551 $26 $177 $997 $1,893 $1,084 $3,558 $3,149 $8,217 $22,033Total Transmission Payments $24,734 $23,984 $25,954 $25,850 $23,643 $22,800 $23,121 $26,303 $27,115 $28,927 $27,753 $36,587 $316,771
% Late Payments 0% 1% 0% 10% 0% 1% 4% 7% 4% 12% 11% 22% 7%
in thousands Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 12 moLate EIS Market Payments $- $- $187 $- $760 $- $3 $3 $125 $- $70 $- $1,148Total EIS Market Payments $22,546 $25,453 $16,362 $13,082 $16,749 $14,633 $20,525 $15,832 $13,102 $15,613 $15,996 $17,895 $207,788
% Late Payments 0% 0% 1% 0% 5% 0% 0% 0% 1% 0% 0% 0% 1%
in thousands Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 12 moTransmission Short Pays $- $- $- $- $- $- $- $- $433 $720 $- $- $1,153EIS Market Short Pays $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
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0%
5%
10%
15%
20%
25%%
of T
otal
Pay
out
% of Late Transmission Payments
0%
5%
10%
15%
20%
25%
% o
f Tot
al P
ayou
t
% of Late EIS Market Payments
$0
$200
$400
$600
$800
in th
ousa
nds
Transmission Short Pays
$0
$10
$20
$30
$40
$50
in th
ousa
nds
EIS Market Short Pays
10a. Financial Disputes Index - $
(Figures in $000's)
Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 mo
Total Disputes $245.6 $60.4 $142.0 $13.1 $116.8 $30.9 $0.2 $46.3 $3.9 $121.4 $5.4 $36.1 $3.9 $104.6 $10.8 234.2$ 45.2$ 61.5$ 41.1$
Avg. Dispute Size $12.3 $2.5 $5.5 $1.0 $3.4 $1.0 $0.0 $1.7 $0.2 $2.4 $0.2 $1.1 $0.7 $3.3 $0.3 15.2$ 1.3$ 2.7$ 1.3$
Largest single dispute $231.8 $28.7 $41.5 $6.8 $68.2 $8.9 $0.3 $24.6 $1.5 $35.2 $2.2 $7.2 $1.7 $28.6 $6.9 1611.3$ 212.4$ 231.8$ 68.2$ *
* Annual maximum
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Monthly Average
$0
$50
$100
$150
$200
$250
$300$0
00's
Settlement Dispute Statistics ($)
Total Disputes Largest single dispute Average Dispute Size
$0
$100
$200
$300
2010 2011 2012 12 mo
Monthly Average Amount in Dispute ($000's)
$0
$5
$10
$15
$20
2010 2011 2012 12 mo
Average Dispute Size ($000's)
$0
$500
$1,000
$1,500
$2,000
2010 2011 2012 12 mo
Largest Single Dispute ($000's)
10b. Financial Disputes Index
(Figures in $000's) Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13 2010 2011 2012 12 mo# Disputes 41 25 24 23 8 36 18 11 19 17 20 28 30 17.8 38.1 24.3 21.6 # Resettlements 30 10 19 31 32 31 40 8 11 18 28 32 6 11.7 8.6 23.9 22.2 Avg Days Outstanding 44 39 35 33 32 65 28 10 72 28 16 27 32 27.4 27.3 40.5 34.8
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Monthly Average
0
25
50
75
0
25
50
75
100
125
150
Avg.
Day
s O
utst
andi
ng
# of
Dis
pute
s an
d R
eset
tlem
ents
Settlement Dispute Statistics
Avg Days Outstanding # Disputes # Resettlements
-
20
40
2010 2011 2012 12 mo
Monthly Average of Active Disputes
-
10
20
30
2010 2011 2012 12 mo
Average Monthly Resettlements
-
10
20
30
40
50
2010 2011 2012 12 mo
Average Days Outstanding
11a. Employee Turnover - monthly
Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13Voluntary TO Rate 0.9% 0.2% 0.6% 0.4% 1.1% 0.2% 0.0% 0.9% 0.2% 0.4% 0.2% 0.2% 0.9% 0.2% 0.3%Involuntary TO Rate 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%Total Turnover (# of employees) 5 1 3 2 6 1 - 5 1 2 1 1 5 1 2
Permanent Employees 530 528 541 549 553 554 562 560 558 563 564 565 566 569 573
Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13Rolling 12-monthTurnover Rate 4.7% 4.7% 5.0% 4.6% 5.3% 5.1% 4.7% 5.2% 5.2% 5.5% 5.1% 5.1% 5.0% 5.0% 4.8%
Lear
ning
& G
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th
300
350
400
450
500
550
600
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
Jun11
Jul 11 Aug11
Sep11
Oct11
Nov11
Dec11
Jan12
Feb12
Mar12
Apr12
May12
Jun12
Jul 12 Aug12
Sep12
Oct12
Nov12
Dec12
Jan13
Feb13
Mar13
Apr13
May13
Jun13
Turn
over
Rat
e Employee Turnover (monthly)
Involuntary TO Rate Voluntary TO Rate # of Employees
0%
2%
4%
6%
8%
10%
Jun 11 Jul 11 Aug 11 Sep 11 Oct 11 Nov 11 Dec 11 Jan 12 Feb 12 Mar 12 Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13
Turn
over
Rat
e
Rolling 12-month Turnover Rate
11b. Employee Turnover - annual
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Total Turnover 3 1 7 7 10 8 8 8 14 21 30 13 21 20 28 12 Total Employees 39 45 73 110 110 116 131 169 245 295 345 423 449 514 558 565 Turnover Ratio 7.7% 2.2% 9.6% 6.4% 9.1% 6.9% 6.1% 4.7% 5.7% 7.1% 8.7% 3.1% 4.7% 3.9% 5.0% 4.2%
Lear
ning
& G
row
th
Note 1: Total Turnover only includes voluntary and involuntary separations; retirements and interns are not used in the calculation.
Note 2: Turnover Ratio is annualized for the current year.
-
100
200
300
400
500
600
0%
2%
4%
6%
8%
10%
12%
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Tota
l Em
ploy
ees
Turn
over
Rat
e (a
nnua
lized
) Annual Turnover Ratio and Employee Count
Total Employees Turnover Ratio
12. Staffing Summary
Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13
Filled w/ Internal Hire 6 9 5 4 5 2 3 2 3 4 1 - 2 - 1 Filled w/ External Hire 6 2 12 9 10 2 8 2 - 4 2 2 5 4 6 Hired YTD 29 40 57 70 85 89 100 104 107 8 11 13 20 24 31
2011 2012 2013
Filled w/ Internal Hire 78 53 8 Filled w/ External Hire 78 54 23 Hired YTD 156 107 31
Lear
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& G
row
th
0
20
40
60
80
100
120
Apr 12 May 12 Jun 12 Jul 12 Aug 12 Sep 12 Oct 12 Nov 12 Dec 12 Jan 13 Feb 13 Mar 13 Apr 13 May 13 Jun 13
Empl
oyee
s
Filled w/ External Hire Filled w/ Internal Hire Hired YTD
13. SPP Regional Entity Compliance
2010 2011 1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 2012 2013Starting Caseload 154 268 245 275 286 220 178 206 245 178New Violations 254 239 57 44 34 38 56 46 275 102Processed by SPP RE 117 187 15 22 84 76 19 35 251 54Dismissed by SPP RE 23 75 12 11 16 4 9 10 62 19Ending Caseload 268 245 275 286 220 178 206 207 178 207
Cumulative Violations 448 687 744 788 822 860 916 962
Perf
orm
ance
0
100
200
300
2009 2010 2011 2012 1Q '13 2Q '13
Period End Open Caseload
2010 2011 2012 1Q 2013 2Q 20130
100
200
300Violations
New Processed Dismissed
14a. IT System Performance - Monthly Service Availability
Market System(MOS)
Reliability(EMS)
Reliability(ICCP)
Tariff Admin(OASIS)
Scheduling(RTO_SS) COS Portal MUI Portal
Target Uptime % 99.87 99.93 99.93 99.87 99.87 99.46 99.87
Target Threshold (min) 60 30 30 60 60 240 60
Apr Uptime % 100.00 100.00 100.00 100.00 100.00 100.00 100.00
May Uptime % 100.00 100.00 100.00 100.00 100.00 100.00 100.00
Jun Uptime % 100.00 100.00 100.00 100.00 100.00 100.00 100.00
Apr Outage Minutes 0 0 0 0 0 0 0
May Outage Minutes 0 0 0 0 0 0 0
Jun Outage Minutes 0 0 0 0 0 0 0
GREENMeets or Exceeds Targeted Uptime
YELLOWUnplanned
outage below Target Uptime
REDUnplanned
outage below Target Uptime
Perf
orm
ance
Apr Apr Apr Apr Apr Apr Apr May May May May May May May Jun Jun Jun Jun Jun Jun Jun
97.00
97.50
98.00
98.50
99.00
99.50
100.00
Market System(MOS)
Reliability(EMS)
Reliability(ICCP)
Tariff Admin(OASIS)
Scheduling(RTO_SS)
COS Portal MUI Portal
% S
ervi
ce A
vaila
bilit
y
14b. IT System Performance - 12 Month Service Availability
%Market System (MOS)
Reliability (EMS)
Reliability (ICCP)
Tariff Admin (OASIS)
Scheduling (RTO_SS) COS Portal MUI Portal
12 Month Service
Availability99.95 100.00 100.00 100.00 100.00 99.79 100.00
Perf
orm
ance
98.00
98.50
99.00
99.50
100.00
Market System(MOS)
Reliability(EMS)
Reliability(ICCP)
Tariff Admin(OASIS)
Scheduling(RTO_SS)
COS Portal MUI Portal
% S
ervi
ce A
vaila
bilit
y
15. Strategic Plan - Progress Dashboard June 2013Pe
rfor
man
ce
No update
16a. Studies - Aggregate - MW
Completed 2Q 12 3Q 12 4Q 12 1Q 13 2Q 13 In Progress 2Q 12 3Q 12 4Q 12 1Q 13 2Q 132011-AGP1 1,401 2011-AGP1 4,587 4,554 3,959
2011-AG2 1,252 2011-AG2 2,474 2,174 1,976 1,676
2011-AG3 4,592 3,573 3,266 3,040 2,869
2012-AG1 2,870 2,834
2012-AG2 5,733 5,170 4,756
2012-AG3 10,412 8,423 8,323
TOTAL - - - 1,401 1,252 2013-AG1 3,945 TOTAL 14,523 16,034 24,783 17,895 17,971
MW
Perf
orm
ance
MW
2011-AGP1 2011-AGP1 2011-AGP1
2011-AG2 2011-AG2 2011-AG2
2011-AG2
2011-AG3 2011-AG3
2011-AG3
2011-AG3
2011-AG3
Completed 2010-AGP1
2012-AG1
2012-AG1
2012-AG2
2012-AG2
2012-AG2
Completed 2011-AG2
Completed 2011-AGP1
2012-AG3
2012-AG3
2012-AG3
2013-AG1
(4,000)
-
4,000
8,000
12,000
16,000
20,000
24,000
2Q 12 3Q 12 4Q 12 1Q 13 2Q 13
MW
16b. Studies - Aggregate - Upgrade $
Completed 2Q 12 3Q 12 4Q 12 1Q 13 2Q 13 In Progress 2Q 12 3Q 12 4Q 12 1Q 13 2Q 132011-AGP1 -$ 2011-AGP1 114.7$ 79.0$ 8.2$
2011-AG2 4.1$ 2011-AG2 206.6$ 21.4$ 55.0$ 56.9$
2011-AG3 1,158.9$ 627.4$ 345.2$ 579.4$ 464.0$
2012-AG1 72.8$ 186.6$
-$ 2012-AG2 526.4$ 453.9$ 453.9$
2012-AG3 579.7$ 579.7$ 368.9$
TOTAL -$ -$ -$ -$ 4.1$ 2013-AG1 101.3$ TOTAL 1,553.0$ 1,254.3$ 1,442.0$ 1,669.9$ 1,120.8$
Perf
orm
ance
$ (in millions) $ (in millions)
2011-AGP1 2011-AGP1 2011-AGP1
2011-AG2
2011-AG2 2011-AG2 2011-AG2
2011-AG3
2011-AG3
2011-AG3 2011-AG3
2011-AG3
2012-AG1
2012-AG1
2Q 12
3Q 12
4Q 12
1Q 13
2012-AG2
2012-AG2
2012-AG2
2012-AG3
2012-AG3
2012-AG3
2013-AG1
-$500
$500
$1,500
$2,500
2Q 12 3Q 12 4Q 12 1Q 13 2Q 13
$ (in
mill
ions
)
16c. Studies - Generation Interconnection - MW
In Progress 2Q 12 3Q 12 4Q 12 1Q 13 2Q 13Pre Queue Reform 48 18 18
Transition Cluster 454 544 296
DISIS-2009-001 201 201 201 201 201
DISIS-2010-001 1,013 911 502 401 300
DISIS-2010-002 478 278 278 278 728
DISIS-2011-001 4,420 4,092 4,019 3,769 3,319
DISIS-2011-002 2,073 1,972 1,797 1,246 1,096
DISIS-2012-001 816 794 533 532 491
DISIS-2012-002 99 3,542 3,382 2,962 2,759
DISIS-2013-001 1,550 1,629
PISIS-2012-001 150
PISIS-2012-002 605 80
PISIS-2013-001 725 400
FCS-2012-002 80
FCS-2012-003 425
FCS-2012-004 680 955
FCS-2013-002 200 Pending Withdrawal
TOTAL 10,257 13,637 12,060 11,665 11,124
Perf
orm
ance
MW
-
5,000
10,000
15,000
2Q 12 3Q 12 4Q 12 1Q 13 2Q 13
MW
Generation Interconnection MW - In Progress
Pre Queue Reform Transition Cluster 2009 Studies 2010 Studies 2011 Studies 2012 Studies 2013 Studies
Metrics Definitions
Transmission and Market Indicators
Two groups of metrics will be monitored to provide an overall health indication of the regional transmission system and market.
• Reliability Performance Indicators, which focus on the actual operations of the transmission system and whether or not it was operated within expected limits and standards.
• Market Performance Indicators, which focus on the performance of the market in terms of overall volume, prices and level of participation.
The intent is to monitor the trends in these areas over time to identify any unexpected performance in an area. Specific performance targets may be established in the future as experience is gained with the information.
Reliability Performance Indicators
This sub-group of metrics is designed to measure the operations of the transmission system from a reliability perspective.
• How much time was congested during the period. (see Congestion)
• How much energy was curtailed due to congestion? (see Congestion)
• Was the system operated in compliance with the relevant control performance standards? (see Regional Control Performance)
1. Congestion
1a. Congestion
• Time (in hours) during the month that flowgates were in Congested (Breached or Binding) and Over the Limit
• % of Schedules/Tags Curtailed
1b. Curtailments
• Tag Curtailments and Market (Schedules) Curtailments along with Total Tags and Schedules.
1c. TLR / CME Time
•
TLR Events by level (in hours) Level 3 - curtailment of non-firm schedules and non-firm market flow Level 4 – curtailment of all non-firm schedules and non-firm market flow (additional reconfiguration
of transmission allowed) Level 5 - curtailment of all non-firm and some firm schedules and market flow "A" Levels begin curtailing at the beginning of the next hour "B" Levels begin curtailing immediately and lasts through the end of the next hour
• CME (Congestion Management Events) where loading is greater than 90% (in hours)
1d. Congested Intervals
• Percent of intervals binding (flow = System Operating Limit [SOL]), breached (flow > SOL) and congested (either binding or breached) during the month.
1e. & 1f. Price Contour Map
• Graphic representation of average monthly prices by load area for the last quarter and last 12 months. Flowgates appearing in the top ten by average shadow price impact in 1g. are identified on 1f.
1f. Congestion
• Congestion by flowgate by average hourly shadow price.
2. Regional Control Performance
Measures the aggregate performance to the NERC CPS (Control Performance Standards) of the Balancing Authorities in the region. This indicator is set based on the number of BAs within region that are in compliance with the NERC real time control performance standards (known as BAL-001 – Real Power Balancing Control Performance and BAL-002 – Disturbance Control Performance).
• CPS1 requires BAs to be in compliance for 100% of the periods measured within the month; and CPS2 requires BAs to be in compliance for 90% of the periods measured within the month.
• For the CPS1 standard, each BA’s rolling 12 month performance is grouped into one of three performance bands (<100% [red], 100-150% [yellow], >150% [green]).
• The number of BA’s whose CPS1 score falls into these bands is shown; with below 100% meaning non-compliant with the standard.
• CPS2 performance is depicted in the appropriate bands (<90% [red], 90-95% [yellow], >95% [green]) based on the monthly CPS2 score rather than a rolling 12 month average.
Market Performance Indicators
This sub-group of indicators provides a view of the effectiveness of the EIS market in the context of answering the following questions:
• What was the value of transmission services used in the month? (see Transmission Utilization)
• What was the average wholesale price paid in the region and what was its volatility? (see EIS Price and Price Range)
• How much Revenue Neutrality Uplift was generated during the month? (see Congestion Uplift)
• What was the level of available generation offered to the market and EIS related energy sales in the month? (see Market Liquidity)
3. Transmission Utilization
Measures the volume of transmission service scheduled in the month in terms of the transmission service revenues paid by both Network Customers and Point-to-Point customers.
• The revenues paid by transmission customers are directly related to the amount of transactions scheduled on the transmission system and therefore provide a proxy as to the utilization of the transmission system in the period.
• Transmission service revenues will be reported as a simple sum of revenues paid for Network Service, Firm Point-to-Point, and Non-Firm Point-to-Point transmission service.
• Transmission service MWh will be reported as a simple sum of Network Service, Firm Point-to-Point, and Non-Firm Point-to-Point transmission service.
4. Price and Price Ranges •
Shows the EIS market prices (high, average and low) for each market participant within the footprint on during the previous 12-month period as well as for the previous month. Also provides an SPP-wide average price for the period reported. Volatility (measured as the coefficient of correlation, which is average divided by the standard deviation) is shown for each market participant as well as SPP as a whole. A higher volatility indicates more variability in prices.
• Shows the SPP-wide monthly average EIS price and the Gas Cost at the Panhandle Eastern Pipeline hub along with12-month rolling averages.
5. Revenue Neutrality Uplift
Tracks amount of RNU (Revenue Neutrality Uplift) charged or credited to market participants during the month. RNU ensures settlement payments/receipts for each hourly settlement interval equal zero.
• Positive RNU - SPP receives insufficent revenue and collects from market participants.
• Negative RNU - SPP receives excess revenue, which must be credited back to market participants.
6. Market Liquidity
Measures the average daily MW offered and dispatchable to the EIS market (dispatchable generation); as well as the average daily sales volume during the month in MWh and dollars.
• Data is taken from the Resource Plans.
• A “percent of total offered” is calculated using the dispatchable MW divided by the total offered MW. Although no specific performance targets have been set, the intent is to monitor the trend of this index to identify significant deviations from average.
Financial Metrics
This group of metrics provides a view of the organization’s overall financial situation in terms of both the operating costs and settlement functions carried out.
7. SPP Admin Fee Performance Measures actual costs incurred by SPP on an annual basis and compares this to the approved Admin Fee and Budgeted Net Revenue Requirement (NRR).
8. Budget Performance Monitor Measures the total actual operating expenses against the total budgeted operating expenses across the organization.
9. Financial Settlement Index Metric measures the timeliness of the financial settlements for both transmission billing and EIS market billing and provides a proxy for the strength of the organization’s cash flow.
10. Financial Disputes Index
Measures the number and value of disputes made with regard to the financial settlements of the markets. The objective in this area is twofold: (1) minimize the time to clear disputes; and (2) minimize the total value of dollars in dispute.
• The dollar amount for total disputes, the average dispute size and the largest single dispute is tracked.
• The number of disputes active during the month, as well as the average days outstanding for those disputes is calculated. In addition, the number of resettlements during the month is tracked.
Learning & Growth Metrics
These indicators provide insights into the organization’s success in maintaining and supporting its desired staffing levels and employee growth plans.
11. Employee Turnover
Measures both involuntary and voluntary turnover rates, along with number of employees in the organization. Monthly turnover is charted on a rolling 12 month basis, while annual turnover ratio and number of employees is provided for historical purposes.
•
A turnover rate is calculated each month by dividing the total turnover for the month by the total employee count at month-end. This monthly rate is then aggregated for the previous 12 months giving a 12-month turnover rate. In order to observe the trend, this 12-month turnover rate is calculated on a rolling basis for the last 25 months.
• An annual turnover rate and the number of employees at year-end are both tracked for historical purposes.
12. Staffing Measures the number of new hires during a month (positions filled) from internal transfers and external hires. Also shows year-to-date new hire total.
Performance Metrics
The metrics in this group focus on NERC Compliance and IT System Availability.
13. SPP RE Compliance Measures SPP Regional Entity compliance of all NERC standards. Metrics track the active caseload, as well as new possible violations and the disposition of reported violations.
14. IT System Availability Measures availability of SPP IT Systems.
15. Strategic Plan Progress Tracks status of elements of the SPP Strategic Plan.
16. Studies Tracks status of Aggregate Studies and Generation Interconnection Studies by MW and upgrade costs (Aggregate Studies only).
SPP Tariff/Governing Document Revisions Docket Number Short Description Summary ER12-959 and 13-1143 (U.S. Court of Appeals)
SPP Submission of Tariff Revisions to Implement a Formula Rate for Transmission Service for Tri-County Electric Cooperative, Inc. ("Tri-County"), a Transmission Owner in the Southwestern Public Service Company ("SPS") Zone Xcel Energy Services Inc.(“Xcel”) v. Federal Energy Regulatory Commission (“FERC”) (Petition for Review of Orders issued in FERC Docket No. ER12-959)
On April 22, 2013, the Administrative Law Judge issued the Initial Decision. The Presiding Judge determined that Tri-County failed to carry its burden to prove that its facilities specified at Exhibit Nos. TCE-2 and TCE-3 are Transmission Facilities eligible to be rolled into SPP's Zone 11 Annual Transmission Revenue Requirement. On April 23, 2013, Xcel filed a Petition for Review before the U.S. Court of Appeals for the District of Columbia Circuit in Case No. 13-1143. Xcel requested the Court for review of the March 30, 2012 and February 21, 2013 Orders issued in FERC Docket No. ER12-959. On April 24, 2013, Commission Trial Staff filed a Status Report regarding negotiations in this proceeding. On April 16, 2013, the participants held a settlement phone conference to discuss the Phase II issues. The next phone conference was scheduled for April 30, 2013. The participants requested that the suspension of the procedural schedule be extended until July 1, 2013. The participants committed to file a further progress report with the Chief Judge on July 1, 2013, if necessary. On April 25, 2013, FERC issued an Order of Chief Judge Continuing Suspension of Phase II Proceedings until July 1, 2013. On May 22, 2013, Tri-County and Occidental Permian, Ltd. and Occidental Power Marketing, L.P filed Briefs on Exceptions. On May 23, 2013, Xcel filed a Non-Binding Statement of Issues to be Raised in U.S. Court of Appeals Case No. 13-1143. On June 4, 2013, FERC filed a Motion to Dismiss Petition for Lack of Jurisdiction in U.S. Court of Appeals Case No. 13-1143. On June 11, 2013, the Commission Trial Staff, Xcel and Tri-County filed Briefs Opposing Exceptions (Phase 1). On June 28, 2013, Xcel filed a Motion to Suspend Phase II Proceedings until an order on the merits of the Initial Decision is issued by the Commission on the Phase I proceedings.
ER12-1179
SPP Submission of Tariff Revisions to Implement SPP Integrated Marketplace
On April 19, 2013, SPP submitted its Compliance Filing pursuant to the March 21, 2013 Order on Rehearing and Clarification. An effective date of March 1, 2014 was requested. On May 10, 2013, Omaha Public Power District (“OPPD”) filed a Protest in response to SPP's April 19,
SPP Tariff/Governing Document Revisions Docket Number Short Description Summary and 13-1181 (U.S. Court of Appeals)
Nebraska Public Power District (“NPPD”) v. Federal Energy Regulatory Commission (“FERC”) - Petition for Review of Orders in FERC Docket ER12-1179
2013 Compliance Filing. However, OPPD's protest is concerning grandfathered agreement issues. OPPD stated: 1) SPP has not met all of its compliance obligations; and 2) the Commission should direct that settlement judge procedures be initiated. On May 10, 2013, OPPD filed a Motion Requesting Immediate Appointment of Settlement Judge and Directing Further Procedures. On May 15, 2013, SPP filed its Third Status Report concerning its efforts to resolve issues associated with the integration into SPP's Integrated Marketplace of so-called grandfathered agreements. On May 17, 2013, NPPD filed a Petition for Review of the October 18, 2012 and March 21, 2013 Orders issued in FERC Docket No. ER12-1179 before the U.S. Court of Appeals in Case No. 13-1181. On June 6, 2013, FERC issued an Order Establishing Settlement Judge Procedures, granting OPPD's May 10, 2013 Motion to establish settlement judge procedures to address the unresolved issues regarding the integration of OPPD's grandfathered agreements into the Integrated Marketplace. If the parties are unable to resolve the issues by August 1, 2013, settlement judge procedures are to cease and the settlement judge shall report to the Chief Judge and the Commission on or before August 6, 2013 that a settlement has not been achieved. Should this occur, SPP was directed to submit by August 8, 2013 a proposal to address the unresolved issues by either proposed a carve-out of the OPPD grandfathered agreements or a proposal for the integration of the agreements into the Integrated Marketplace. Parties may submit responses to SPP's proposal on or before August 15, 2013. On June 18, 2013, NPPD filed a Preliminary Non-Binding Statement of Issues in U.S. Court of Appeals Case No. 13-1181. On June 19, 2013, SPP filed a Motion to Expand Scope of Settlement Proceeding, Request for Shortened Answer Period, and Request for Expedited Ruling. SPP moved to expand the scope of the settlement judge proceeding established by the June 6, 2013 Order to include unresolved issues relating to other protesting parties with grandfathered agreements that have not yet been integrated into SPP's proposed Integrated Marketplace. On June 24, 2013, FERC issued an Order of Chief Judge Granting Motion to Expand Settlement Proceedings to include all grandfathered agreements that have not yet been integrated into SPP's proposed Integrated Marketplace. On June 26, 2013, FERC issued a Notice of Upcoming Settlement Conferences. Additional settlement
SPP Tariff/Governing Document Revisions Docket Number Short Description Summary
conferences were scheduled for July 9-10, July 16-17, and July 23-24, 2013. On July 2, 2013, FERC filed a Motion to Dismiss Petition for Review or, in the Alternative, to Hold Appeal in Abeyance in U.S. Court of Appeals Case No. 13-1181. A settlement conference was held on July 9-10, 2013 to discuss grandfathered agreements. On July 11, 2013, FERC issued a Notice of Upcoming Settlement Conferences. The next settlement conference is scheduled for July 15, 2013. This is in addition to the conferences previously scheduled for July 16, 23, and 24. The settlement conference previously scheduled for July 17 was cancelled.
ER12-2292 SPP Submission of Tariff Revisions to Attachment AE to Facilitate the Systematic Rather than Manual Curtailment of Non-Dispatchable Resources in the Energy Imbalance Services Market ("EIS Market") During Period of Congestion
On April 10, 2013, SPP filed a Reply to Comments of Acciona Wind Energy USA LLC. SPP provided clarification in response to Acciona's concerns raised in its March 22, 2013 Comments.
ER13-366 and ER13-367
SPP Submission of Tariff Revisions to Comply with Order No. 1000 Regional Planning and Cost Allocation Requirements SPP Submission of Revisions to its Membership Agreement to Comply with Order No. 1000
FERC action is pending.
ER13-1173 SPP Submission of Tariff Revisions to Modify Certain Aspects of the SPP Integrated Marketplace
Several Parties filed Motions to Intervene. FERC action is pending.
ER13-1748 SPP Order No. 755 Compliance Filing to Adopt a Two-Part Compensation Methodology for Resources that Provide
On June 21, 2013, SPP submitted its Order No. 755 Compliance Filing to adopt a two-part compensation methodology for Resources that provide Regulation-Up and Regulation-Down Operating Reserve products in the SPP Integrated Marketplace, and to adopt other Tariff language required by Order No. 755.
SPP Tariff/Governing Document Revisions Docket Number Short Description Summary
Regulation-Up and Regulation-Down Operating Reserve Products in the SPP Integrated Marketplace and Other Tariff Language
An effective date of March 1, 2015 was requested.
ER13-1768 and ER13-1769
SPP Submission of Tariff Revisions to Attachment AN to Incorporate into the Tariff the Agreement Between Southwest Power Pool, Inc. and Southwest Power Pool Balancing Authority Participants Relating to the Implementation of the Southwest Power Pool Balancing Authority ("SPP BA Agreement")
On June 25, 2013, SPP submitted Tariff revisions to incorporate into Attachment AN of the Tariff the Agreement Between Southwest Power Pool, Inc. and Southwest Power Pool Balancing Authority Participants Relating to the Implementation of the Southwest Power Pool Balancing Authority in Docket No. ER13-1768. Additionally, SPP submitted revisions to SPP's Bylaws and Membership Agreement contained in SPP's Governing Documents Tariff that are necessary to facilitate the implementation of the SPP Balancing Authority. Due to software limitations, the Bylaws and Membership Agreement changes were submitted under Docket No. ER13-1769. An effective date of March 1, 2014 was requested.
ER13-1939 SPP Submission of Tariff Revisions to Comply with Order No. 1000 Interregional Coordination and Cost Allocation Requirements
On July 10, 2013, SPP submitted revisions to its Tariff to comply with Order No. 1000's requirements for interregional coordination and cost allocation. SPP requested an effective date for all Tariff revisions submitted herein which is coincident to the effective date the Commission ultimately approves for SPP's Order No. 1000 regional compliance. In its regional compliance filing, SPP requested an effective date of March 30 following the Commission's acceptance of such filing. For Addendum 4 to Attachment O, SPP requested an effective date of the later of March 30 the year after Commission acceptance of SPP's regional planning process, or January 1, 2015.
Other Filings of Interest Docket Number Short Description Summary EL11-34 and 12-1158 (U.S. Court of Appeals)
Midwest Independent Transmission System Operator, Inc. ("MISO”) Petition for Declaratory Order Seeking Commission Confirmation Regarding Section 5.2 of the Joint Operating Agreement ("JOA") between MISO and SPP Southwest Power Pool, Inc. v. Federal Energy Regulatory Commission (“FERC”)
FERC and U.S. Court of Appeals action is pending.
EL13-15 and EL13-35 (consolidated)
Southwestern Public Service Company ("SPS") Complaint Seeking a Finding that the Rates in SPP Zone 11 are Unjust and Unreasonable due to the Inclusion of the Costs of Facilities of Tri-County Electric Cooperative, Inc. ("Tri-County") Southwestern Public Service Company ("SPS") Complaint Requesting Establishment of a January 1, 2013 Refund Effective Date and a Finding from the Commission that SPP has Violated the Federal Power Act by Implementing a 40% Increase in the Tri-County Electric Cooperative, Inc. ("Tri-County") Annual Transmission Revenue Requirement
On April 22, 2013, FERC issued an Order Granting Rehearing for Further Consideration of the February 21, 2013 Order. A formal settlement conference was held on May 2, 2013. On May 20, 2013, Settlement Judge Young filed a Settlement Judge Report to the Commission and Chief Judge. A formal settlement conference was held on May 2, 2013. Additional information was exchanged on May 10, 2013. A conference call to discuss the May 10, 2013 information was conducted on May 16, 2013. Proposed formula rate tariff language exchange was scheduled for May 24, 2013, and a conference call to discuss the tariff language proposals was scheduled for June 6, 2013. A conference call was held on June 6, 2013.
Other Filings of Interest Docket Number Short Description Summary
ER13-1864 Joint Operating Agreement
("JOA") between SPP and the Midcontinent Independent System Operator, Inc. ("MISO") to Include Market-to-Market ("M2M") Terms and Conditions (SPP Rate Schedule FERC No. 9)
On June 28, 2013, SPP submitted revisions to the JOA between SPP and MISO to reflect the market-to-market terms and conditions to which SPP and MISO have substantively agreed, which have been incorporated into a proposed Attachment 2 - Interregional Coordination Process to the JOA. SPP requested an effective date of one-year following the start-up of SPP's Integrated Marketplace currently scheduled for March 1, 2014.
ER13-1937 Joint Operating Agreement ("JOA") between SPP and the Midcontinent Independent System Operator, Inc. ("MISO") to Comply with Interregional Requirements of Order No. 1000 (SPP Rate Schedule FERC No. 9)
On July 10, 2013, SPP submitted revisions to the JOA between SPP and the Midcontinent Independent System Operator, Inc. to address the interregional coordination and cost allocation requirements of Order No. 1000. SPP requested an effective date to coincide with the effective date of its Order No. 1000 regional Tariff provisions. In its regional compliance filing, SPP requested an effective date of March 30 following the Commission's acceptance of such filing.
ES13-20 Application of Southwest Power Pool, Inc. Under Section 204 of the Federal Power Act for an Order Authorizing the Issuance of Securities
On April 16, 2013, SPP filed an Application Under Section 204 of the Federal Power Act for an Order Authorizing the Issuance of Securities of up to $30 million in non-secured Promissory Notes. The Notes will be used to: (i) supplement SPP's short-term working capital needs; and (ii) satisfy the liquidity requirements of SPP's various outstanding credit agreements. SPP requested the Commission approve this application by June 16, 2013. On May 23, 2013, SPP filed an amendment to its Application Under Section 204 of the Federal Power Act for an Order Authorizing the Issuance of Securities filed on April 16, 2013. SPP requested the Commission approve this application by June 13, 2013. On June 6, 2013, FERC issued an order authorizing SPP to issue unsecured promissory notes in an aggregate principal amount not to exceed $30 million. The authorization is effective on this date and expires on June 6, 2015. SPP is to file a Report of Securities Issued no later than 30 days after the issuance of securities. On July 11, 2013, SPP filed its Report of Securities Issues pursuant to Section 34.10 of the Commission's Regulations.
State Cases Docket Number Short Description Summary Arkansas 10-011-U
In the Matter of a Show Cause Order Directed to Entergy Arkansas, Inc. (“EAI”) Regarding Its Continued Membership in the Current Entergy System Agreement, or Any Successor Agreement Thereto, and Regarding the Future Operation and Control of Its Transmission Assets
On April 8, 2013, the APSC issued Order No. 76, granting EAI's Application to Transfer Functional Control of its Electric Transmission Facilities to the Midwest Independent Transmission System Operator, Inc. Regional Transmission Organization, conditioned upon full and continued compliance by EAI and MISO with each of the Order No. 68 Conditions. The APSC also granted EAI's Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility. EAI's request for approval to defer its MISO transition costs, without the addition of carrying costs, was granted subject to EAI compliance with the five ratepayer protection provisions as recommended by Staff witness Hilton and as set forth in the Order. EAI and MISO were directed to file in this Docket on the first business day of each month, beginning on May 1, 2013, Supplemental Testimony providing monthly updates regarding the progress of the integration of EAI into MISO process; critical developments in the various Entergy/MISO related proceedings pending before FERC and Entergy's other retail regulators; and ongoing compliance with the Order No. 68 Conditions. By subsequent Order the Commission will establish a procedural schedule for the consideration of MISO's Application for a Certificate of Convenience and Necessity in Docket No. 11-165-U.
Arkansas 10-074-U
In the Matter of the Application of Southwestern Electric Power Company (“SWEPCO”) for a Certificate of Environmental Compatibility and Public Need (“CECPN”) for the Construction, Ownership, Operation and Maintenance of the Proposed Flint Creek to Shipe Road Project and Associated Facilities to be Located in Benton County, Arkansas
On April 22, 2013, the APSC issued Order No. 15. The Commission granted SWEPCO modifications to its CECPN to the approved route for the 161 kV transmission line in order to accommodate the Kinyon/Webb landowners and to the approved route for the 345 kV transmission line south of Decatur, Arkansas, in order to address concerns held by the Federal Aviation Administration.
Arkansas 13-041-U
In the Matter of the Application of Southwestern Electric Power Company ("SWEPCO") for a Certificate of Environmental
On April 3, 2013, SWEPCO filed its Application for CECPN. SWEPCO proposed to build the Shipe Road to Kings River 345 kV transmission line, the proposed Kings River Station, and miscellaneous upgrades to the Shipe Road Station.
State Cases Docket Number Short Description Summary
Compatibility and Public Need ("CECPN") for the Construction, Ownership, Operation and Maintenance of the Proposed 345 kV Transmission Line Between the Shipe Road Station and the Proposed Kings River Station and Associated Facilities to be Located in Benton, Carroll and/or Madison and Washington Counties, Arkansas
On April 3, 2013, Joseph Hassink, Jennifer Jackson, Brian Johnson, and Stephen Thornhill filed Direct Testimony on behalf of SWEPCO in support of the Application. Numerous Parties filed Motions to Intervene. On May 24, 2013, the APSC issued Order No. 7, establishing the following procedural schedule: June 28, 2013 (by Noon) - Staff and Intervenor Direct Testimony; July 19, 2013 (by Noon) - Applicant Rebuttal Testimony; August 7, 2013 (by Noon) - Staff and Intervenor Surrebuttal Testimony; and August 21, 2013 (by Noon) - Applicant Sur-Surrebuttal Testimony. On June 3, 2013, the APSC issued Order No. 8 scheduling public comment hearings. On June 17, 2013, Julia R. Neighbors Revocable Trust and Trustees filed a Motion to Dismiss the Application filed by SWEPCO. Numerous Intervenors filed Direct Testimony in June. On June 28, 2013, Lanny Nickell filed Direct Testimony on behalf of SPP. Discovery in this proceeding is ongoing.
Kansas 13-ITCE-677-MIS
In the Matter of the Application of ITC Great Plains, LLC (“ITC”) and Mid-Kansas Electric Company, LLC (“MKEC”) for a Siting Permit for the Construction of a 345 kV Transmission Line in Cloud and Ottawa Counties, Kansas
On May 3, 2013, ITC and MKEC filed a Joint Application requesting a siting permit conferring on the Companies the right to construct their portion of a 345 kV transmission line from ITC's Elm Creek Substation south to Westar Energy, Inc.'s Summit Substation. On May 3, 2013, Salvatore Falcone, Alan Myers, Kristine Schmidt, and Noman Williams filed Direct Testimony on behalf of ITC and MKEC in support of the Joint Application. On May 8, 2013, the KCC issued an Order Adopting Procedural Schedule. On June 3, 2013, Thomas DeBaun and Michael Wegner filed Direct Testimony on behalf of the KCC. On June 3, 2013, Katherine Prewitt filed Direct Testimony on behalf of SPP. On June 28, 2013, Alan Myers, on behalf of ITC Great Plains, LLC, filed Testimony in Response to Comments at June 3, 2013 Public Hearing and Written Comments Received by the Commission.
State Cases Docket Number Short Description Summary
On July 9, 2013, the KCC issued an Order Granting Motion to Modify Procedural Schedule. The evidentiary hearing was rescheduled to be held on August 6, 2013. The remainder of the procedural schedule is as follows: July 16, 2013 (by 3 PM) - The Companies' Rebuttal to Staff/Intervenor Response to Public Hearing Comments; July 23, 2013 (by 3 PM) - Prehearing Motion and Discovery Cutoff; List of Disputed Issues due; July 30, 2013 - Prehearing Conference begins at 9:30 AM; August 6, 2013 - Evidentiary Hearing begins at 9 AM; August 12, 2013 (by 3 PM) - The Companies' Initial Post-Hearing Briefs due; August 19, 2013 (by 3 PM) - Staff and Intervenor Post-Hearing Briefs due; August 23, 2013 (by 3 PM) - The Companies Reply Brief due; and September 3, 2013 - Final Order due.
Kansas 13-WSEE-676-MIS
In the Matter of the Application of Westar Energy, Inc. (“Westar”) for a Siting Permit for the Construction of a 345 kV Transmission Line in Saline and Ottawa Counties, Kansas
On May 3, 2013, Westar filed an Application for a siting permit to construct a 345 kV transmission line from Westar's Summit Substation to an interconnection point near Justice Road in Ottawa County, Kansas. On May 3, 2013, Salvatore Falcone, Kelly Harrison, and Dennis Reed filed testimony on behalf of Westar in support of the Application. On May 8, 2013, the KCC issued an Order Setting Procedural Schedule. On May 31, 2013, Thomas DeBaun and Michael Wegner filed Direct Testimony on behalf of the KCC. On May 31, 2013, Katherine Prewitt filed Direct Testimony on behalf of SPP. On June 28, 2013, Kelly Harrison and Salvatore Falcone filed Supplemental Testimony on behalf of Westar. On July 2, 2013, Michael Wegner, P.E. filed Testimony in Response to Comments at June 5, 2013 Public Hearing on behalf of the KCC. The remainder of the procedural schedule is as follows: July 24, 2013 - Prehearing Conference begins at 9:30 AM; July 24, 2013 (3 PM) - Prehearing Motion and Discovery cutoff; List of Disputed Issues due;
State Cases Docket Number Short Description Summary
August 7, 2013 - Evidentiary Hearing begins at 9 AM; August 14, 2013 (by 3 PM) - Simultaneous Initial Briefs; August 21, 2013 (by 3 PM) - Simultaneous Responsive Briefs; and September 3, 2013 - Final Order due.
Missouri EO-2012-0135 and EO-2012-0136 (consolidated)
In the Matter of the Application of Kansas City Power & Light Company (“KCPL”) for Authority to Extend the Transfer of Functional Control of Certain Transmission Assets to the Southwest Power Pool, Inc. In the Matter of the Application of KCP&L Greater Missouri Operations Company (“KCPL-GMO”) for Authority to Extend the Transfer of Functional Control of Certain Transmission Assets to the Southwest Power Pool, Inc.
On May 16, 2013, the Parties filed a Stipulation and Agreement. On May 16, 2013, the Parties filed a Joint Motion for Suspension of Procedural Schedule and Hearings. On May 22, 2013, the MoPSC issued an Order Suspending Procedural Schedule and Cancelling Evidentiary Hearing. On June 19, 2013, the MoPSC issued an Order Approving Stipulation and Agreement, effective July 19, 2013.
Missouri EO-2012-0269
In the Matter of The Empire District Electric Company's (“Empire”) Submission of Its Interim Report Regarding Participation in the Southwest Power Pool, Inc.
On June 12, 2013, the MoPSC issued an Order Approving Jointly Proposed Procedural Schedule. The following procedural schedule was established: July 12, 2013 - Empire Direct Testimony; August 6, 2013 - Settlement Conference; August 20, 2013 - Rebuttal Testimony; September 24, 2013 - Surrebuttal and Cross-Surrebuttal Testimony; September 26, 2013 - Settlement Conference Call; October 7, 2013 - Last day to serve discovery; October 11, 2013 - List and Order of Issues/Witnesses; October 15, 2013 - Joint Stipulation of Facts; October 21, 2013 - Position Statements; October 24-25, 2013 - Evidentiary Hearing; November 22, 2013 - Post-Hearing Briefs; and December 10, 2013 - Reply Briefs.
State Cases Docket Number Short Description Summary
On July 12, 2013, Bary Warren filed Direct Testimony on behalf of Empire.
New Mexico 13-00031-UT
In the Matter of Southwestern Public Service Company's (“SPS”) Interim Report on its Participation in the Southwest Power Pool Regional Transmission Organization (“RTO”)
Discovery in this proceeding is ongoing.
Texas 41430
Joint Report and Application of Sharyland Utilities, L.P. ("Sharyland"), Sharyland Distribution & Transmission Services, L.L.C. ("SDTS"), and Southwestern Public Service Company ("SPS") for Approval of Purchase and Sale of Facilities, for Approval of Regulatory Accounting Treatment of Gain or Sale, and for Transfer of Certain Rights
On April 29, 2013, Sharyland, SDTS, and SPS filed a Joint Report and Application for Approval of Purchase and Sale of Facilities, for Approval of Regulatory Accounting Treatment of Gain or Sale, and for Transfer of Certain Rights. On May 6, 2013, Sharyland, SDTS, and SPS filed a Joint Request for Referral to the State Office of Administrative Hearings (“SOAH”). On May 14, 2013, SOAH Order No. 1, Filing Description; Procedures; and Notice of Prehearing Conference, was issued. A prehearing conference is scheduled for June 11, 2013. On May 21, 2013, the Parties filed Proposed List of Issues. A pre-hearing conference was held on June 11, 2013. On June 17, 2013, SOAH issued Order No. 2, Memorializing Prehearing Conference, Granting Interventions, Adopting Protective Order, and Setting Procedural Schedule and Hearing on the Merits. SPP's Motion to Intervene was granted, along with several others. On June 18, 2013, the Applicants filed Supplemental Direct Testimony. On June 19, 2013, the PUCT issued a Preliminary Order. A technical conference was held on July 1, 2013. Another technical conference is scheduled for July 22, 2013. The remainder of the procedural schedule is as follows: August 2, 2013 - Intervenor Direct Testimony; August 9, 2013 - Staff Direct Testimony;
State Cases Docket Number Short Description Summary
August 15, 2013 - Staff and Intervenor Cross-Rebuttal Testimony; August 16, 2013 - Applicant Rebuttal Testimony; September 3-4, 2013 - Hearing on the Merits to begin at 2 PM; September 13, 2013 - Initial Briefs; and September 20, 2013 - Reply Briefs.
Regulatory Outlook
13-WSEE-676-MIS
7/2/2013State of Kansas Staff/Intervenor Responsive Testimony to Public Comments due by 3 PM (Order Setting Procedural
Schedule issued May 8, 2013)
AD12-12
7/5/2013FERC SPP to file response to follow-up questions regarding SPP's presentation to the Commission on May 16,
2013 (Request for Additional Information issued on June 4, 2013)
RM13-6
7/8/2013FERC Comments due in response to NOPR proposing to remand the proposed interpretation of Reliability
Standard BAL-002-1, Disturbance Control Performance, Requirements R4 and R5 (Notice of Proposed
Rulemaking issued May 16, 2013)
13-ITCE-677-MIS
7/9/2013State of Kansas Staff/Intervenor Response to Public Hearing Comments due by 3 PM (Order Adopting Procedural
Schedule issued May 8, 2013)
AD13-6
7/9/2013FERC Reliability Technical Conference to be held from 9 AM to 5 PM Eastern Time to discuss policy issues
related to the reliability of the Bulk-Power System (Notice of Technical Conference issued on May 7,
2013)
ER12-1179
7/9/2013FERC Settlement Conference related to grandfathered agreements (Notice of Upcoming Settlement
Conferences issued June 26, 2013)
RM10-23
7/10/2013FERC Compliance filing due to submit revised Attachment K of the pro forma OATT and any other Commission
jurisdictional documents to include an interregional transmission coordination procedure or procedures
consistent with the requirements of Final Rule (Notice Granting an Extension of Time to Submit
Interregional Compliance Filings issued February 26, 2013; Section IV.C. of Order No. 1000 issued July
21, 2011)
RM10-23
7/10/2013FERC Compliance filing due to submit revised Attachment K of the pro forma OATT and any other Commission
jurisdictional documents to include a cost allocation method or methods for interregional cost allocation
consistent with the principles of Final Rule (Notice Granting an Extension of Time to Submit Interregional
Compliance Filings issued February 26, 2013; Section IV.D. of Order No. 1000 issued July 21, 2011)
7/12/2013 4:39:53 PM Page: 1
Regulatory Outlook
UD-12-01
7/10/2013State of LA - New Orleans Applicant Rejoinder Testimony due (Order issued April 5, 2013; Order issued March 22, 2013; Resolution
R-12-390, Resolution and Order Establishing Procedural Schedule, issued October 18, 2012)
13-WSEE-676-MIS
7/12/2013State of Kansas Westar Rebuttal Testimony to Public Comments due by 3 PM (Order Setting Procedural Schedule
issued May 8, 2013)
EO-2012-0269
7/12/2013State of Missouri Empire's Direct Testimony is due (Order Approving Jointly Proposed Procedural Schedule issued June
12, 2013)
ER12-1179
7/15/2013FERC SPP to file additional Informational Filing reporting on settlement discussions regarding grandfathered
agreements
13-ITCE-677-MIS
7/16/2013State of Kansas ITC Great Plains/Mid-Kansas Rebuttal to Staff/Intervenor Response to Public Hearing Comments due by
3 PM (Order Adopting Procedural Schedule issued May 8, 2013)
ER12-1179
7/16/2013FERC Settlement Conference related to grandfathered agreements (Notice of Upcoming Settlement
Conferences issued June 26, 2013)
13-041-U
7/19/2013State of Arkansas Applicant Rebuttal Testimony due by Noon (APSC Order No. 7 issued on May 24, 2013)
RM12-22
7/22/2013FERC Effective date of Order No. 779, Final Rule directing the North American Electric Reliability Corporation to
submit to the Commission for approval proposed Reliability Standards that address the impact of
geomagnetic disturbances on the reliable operation of the Bulk-Power System (Order No. 779 issued on
May 16, 2013)
UD-12-01
7/23/2013State of LA - New Orleans Evidentiary Hearing begins (Resolution R-12-390, Resolution and Order Establishing Procedural
Schedule, issued October 18, 2012)
13-ITCE-677-MIS
7/23/2013State of Kansas Prehearing Motion and Discovery Cutoff; List of Disputed Issues due by 3 PM (Order Adopting
Procedural Schedule issued May 8, 2013)
7/12/2013 4:39:53 PM Page: 2
Regulatory Outlook
ER12-1179
7/23/2013FERC Settlement Conference related to grandfathered agreements (Notice of Upcoming Settlement
Conferences issued June 26, 2013)
13-WSEE-676-MIS
7/24/2013State of Kansas Prehearing Conference begins at 9:30 AM (Order Setting Procedural Schedule issued May 8, 2013)
13-WSEE-676-MIS
7/24/2013State of Kansas Prehearing Motion and Discovery Cutoff; List of Disputed Issues due (Order Setting Procedural Schedule
issued May 8, 2013)
13-ITCE-677-MIS
7/30/2013State of Kansas Prehearing Conference begins at 9:30 AM (Order Adopting Procedural Schedule issued May 8, 2013)
41430
8/2/2013State of Texas Intervenor Direct Testimony is due (SOAH Order No. 2, Memorializing Prehearing Conference, Granting
Interventions, Adopting Protective Order, and Setting Procedural Schedule and Hearing on the Merits
issued June 17, 2013)
EO-2012-0269
8/6/2013State of Missouri Settlement Conference (Order Approving Jointly Proposed Procedural Schedule issued June 12, 2013)
13-ITCE-677-MIS
8/6/2013State of Kansas Evidentiary Hearing begins at 9 AM (Order Granting Motion to Modify Procedural Schedule issued July 9,
2013; Order Adopting Procedural Schedule issued May 8, 2013)
13-WSEE-676-MIS
8/7/2013State of Kansas Evidentiary Hearing begins at 9 AM (Order Setting Procedural Schedule issued May 8, 2013)
13-041-U
8/7/2013State of Arkansas Staff and Intervenor Surrebuttal Testimony due by Noon (APSC Order No. 7 issued on May 24, 2013)
41430
8/9/2013State of Texas Staff Direct Testimony is due (SOAH Order No. 2, Memorializing Prehearing Conference, Granting
Interventions, Adopting Protective Order, and Setting Procedural Schedule and Hearing on the Merits
issued June 17, 2013)
7/12/2013 4:39:53 PM Page: 3
Regulatory Outlook
13-ITCE-677-MIS
8/12/2013State of Kansas ITC Great Plains/Mid-Kansas Initial Post-Hearing Briefs due by 3 PM (Order Adopting Procedural
Schedule issued May 8, 2013)
13-WSEE-676-MIS
8/14/2013State of Kansas Simultaneous Initial Briefs due by 3 PM (Order Setting Procedural Schedule issued May 8, 2013)
41430
8/15/2013State of Texas Staff and Intervenor Cross-Rebuttal Testimony is due (SOAH Order No. 2, Memorializing Prehearing
Conference, Granting Interventions, Adopting Protective Order, and Setting Procedural Schedule and
Hearing on the Merits issued June 17, 2013)
41430
8/16/2013State of Texas Applicant Rebuttal Testimony is due (SOAH Order No. 2, Memorializing Prehearing Conference, Granting
Interventions, Adopting Protective Order, and Setting Procedural Schedule and Hearing on the Merits
issued June 17, 2013)
13-ITCE-677-MIS
8/19/2013State of Kansas Staff/Intervenor Post-Hearing Briefs due by 3 PM (Order Adopting Procedural Schedule issued May 8,
2013)
EO-2012-0269
8/20/2013State of Missouri Rebuttal Testimony is due (Order Approving Jointly Proposed Procedural Schedule issued June 12,
2013)
13-WSEE-676-MIS
8/21/2013State of Kansas Simultaneous Responsive Briefs due by 3 PM (Order Setting Procedural Schedule issued May 8, 2013)
13-041-U
8/21/2013State of Arkansas Applicant Sur-Surrebuttal Testimony due by Noon (APSC Order No. 7 issued on May 24, 2013)
13-ITCE-677-MIS
8/23/2013State of Kansas ITC Great Plains/Mid-Kansas Reply Brief due by 3 PM (Order Adopting Procedural Schedule issued May
8, 2013)
13-041-U
8/26/2013State of Arkansas Hearing begins at 9:30 AM (APSC Order No. 7 issued on May 24, 2013)
7/12/2013 4:39:53 PM Page: 4
Regulatory Outlook
RM13-8
8/27/2013FERC Comments due in response to NOPR proposing to approve the retirement of 34 requirements within 19
Reliability Standards identified by NERC in its Petition filed on February 28, 2013 (Notice of Proposed
Rulemaking issued on June 20, 2013)
ER06-451
9/1/2013FERC SPP Demand Response Status Report Due
41430
9/3/2013State of Texas Hearing on the Merits begins at 2 PM (SOAH Order No. 2, Memorializing Prehearing Conference,
Granting Interventions, Adopting Protective Order, and Setting Procedural Schedule and Hearing on the
Merits issued June 17, 2013)
41430
9/13/2013State of Texas Initial Briefs are due (SOAH Order No. 2, Memorializing Prehearing Conference, Granting Interventions,
Adopting Protective Order, and Setting Procedural Schedule and Hearing on the Merits issued June 17,
2013)
41430
9/20/2013State of Texas Reply Briefs are due (SOAH Order No. 2, Memorializing Prehearing Conference, Granting Interventions,
Adopting Protective Order, and Setting Procedural Schedule and Hearing on the Merits issued June 17,
2013)
EO-2012-0269
9/24/2013State of Missouri Surrebuttal and Cross-Surrebuttal Testimony is due (Order Approving Jointly Proposed Procedural
Schedule issued June 12, 2013)
12-1232
9/25/2013United States Court of Respondents's Brief is due (Order issued by U.S. Court of Appeals on March 5, 2013)
AD13-7
9/25/2013FERC Technical Conference to be held in order to consider how current centralized capacity market rules and
structures are supporting the procurement and retention of resources necessary to meet future reliability
and operational needs (Notice of Technical Conference issued on June 17, 2013)
EO-2012-0269
9/26/2013State of Missouri Settlement Conference call (Order Approving Jointly Proposed Procedural Schedule issued June 12,
2013)
7/12/2013 4:39:54 PM Page: 5
Regulatory Outlook
EO-2009-0179
9/30/2013State of Missouri KCP&L Greater Missouri Operations Company's Interim Period Ends (participation in SPP RTO)
(January 27, 2009 Stipulation and Agreement approved by MoPSC on February 4, 2009)
EO-2006-0142
10/1/2013State of Missouri Kansas City Power & Light Company's Interim Period Ends (participation in SPP RTO) (February 24,
2006 Stipulation and Agreement approved by MoPSC on July 13, 2006)
EO-2012-0269
10/11/2013State of Missouri List and Order of Issues/Witnesses due (Order Approving Jointly Proposed Procedural Schedule issued
June 12, 2013)
09-1029
10/15/2013FERC Offer Cap Filing due (annual filing) (Docket number TBD)
ER05-652
10/15/2013FERC File Informational Report on SPP Aggregate Study (Safe Harbor Report) (April 22, 2005 Order)
EO-2012-0269
10/15/2013State of Missouri Joint Stipulation of Facts due (Order Approving Jointly Proposed Procedural Schedule issued June 12,
2013)
12-1232
10/16/2013United States Court of Intervenors in Support of Respondent Briefs are due (Order issued by U.S. Court of Appeals on March 5,
2013)
AD12-12
10/17/2013FERC Each Regional Transmission Organization and Independent System Operator to appear before the
Commission in order to share its experiences from the summer and fall. Each RTO and ISO should
describe the progress it has made in refining existing practices to provide better coordination between
the natural gas and electric industries and ensure adequate fuel supplies. This discussion also should
address any natural gas transportation concerns that arise during the winter heating season and should
identify any generator outages during the winter and spring that are fuel related (Order Directing Further
Conferences and Reports issued November 15, 2012)
EO-2012-0269
10/21/2013State of Missouri Position Statements due (Order Approving Jointly Proposed Procedural Schedule issued June 12, 2013)
7/12/2013 4:39:54 PM Page: 6
Regulatory Outlook
EO-2012-0269
10/24/2013State of Missouri Evidentiary Hearing (Order Approving Jointly Proposed Procedural Schedule issued June 12, 2013)
ER08-1338
11/1/2013FERC SPP to file its Annual Budget in FERC Docket Nos. ER04-48, ER08-1338, RT04-1
RM10-11
11/12/2013FERC Order No. 764 Compliance Filing due to 1) offer intra-hourly transmission scheduling; 2) incorporate
provisions into the pro forma Large Generator Interconnection Agreement requiring interconnection
customers whose generating facilities are Variable Energy Resources (VERs) to provide meteorological
and forced outage data to the public utility transmission provider for the purpose of power production
forecasting (Order on Rehearing and Clarification and Granting Motion for Extension of Time issued
December 20, 2012; Final Rule issued June 21, 2012)
12-1232
11/15/2013United States Court of Reply Briefs are due (Order issued by U.S. Court of Appeals on March 5, 2013)
EO-2012-0269
11/22/2013State of Missouri Post-Hearing Briefs due (Order Approving Jointly Proposed Procedural Schedule issued June 12, 2013)
EO-2012-0269
12/10/2013State of Missouri Reply Briefs due (Order Approving Jointly Proposed Procedural Schedule issued June 12, 2013)
10-00143-UT
12/16/2013State of New Mexico Lea County Electric Cooperative, Inc. to file Interim Report regarding LCEC's continued participation in
the SPP RTO (October 1, 2010 Uncontested Stipulation; December 16, 2010 Final Order Adopting
Certification of Stipulation)
RM05-5
12/31/2013FERC Each RTO/ISO to revise its Tariff to include the NAESB Energy Efficiency and Phase II Demand
Response M&V Standards. For standards that do not require implementing tariff provisions, the
Commission will allow the RTO/ISO to incorporate WEQ standards by reference in its Tariff (Order No.
676-G issued February 21, 2013)
7/12/2013 4:39:54 PM Page: 7
1
SPP RE Update to Board of Directors
July 30, 2013
John Meyer Chairman, SPP RE Trustees
Major Topics
1. New Definition of Bulk Electric System
– On 6/13/13, FERC accepted the request from NERC to delay implementation until 7/1/14
– Registered Entities should be compiling a list of self-nominated ‘exclusions’ (facilities that meet one of the listed exclusions)
2. Facility Ratings Alert
– 3.5 years into 4-year program to review ratings and remediate discrepancies
– 23,000 discrepancies found nationwide
– 2,600 discrepancies found in SPP RE region to date
– Remediation required within one year of discovery
2
2
Major Topics
3. Transition from CIP Version 3 to Version 5
– NERC published transition guidance on 4/11/13
– NERC published draft revised guidance 7/17/13
4. NERC “Blue Ribbon Panel”
– Five independent industry experts
– Top-to-bottom review of the “693” reliability standards
– Published report 7/13 (not yet approved by NERC Board of Trustees)
– Four key findings and five near- and long-term recommendations
3
Independent Experts’ Key Findings
1. Recommended retiring 147 requirements and consolidating remaining requirements for overall 43% reduction
2. Of the 257 retained requirements, 81 are in “Steady-State” (no work needed) and 176 need enhancement
3. Identified gaps:
a. Outage coordination
b. Governor frequency response
c. Situational awareness models
d. Clear three-part communications
4. While newer standards are improved, the majority are not at Steady-State
4
3
Independent Experts’ Recommendations
1. Retire 147 requirements and focus initial improvement efforts on 16 high-risk standards
2. Continue developing risk-based approaches to identify high priority reliability issues
3. Realign standards from the current 14 families into 10 families grouped by reliability functions
4. Address identified gaps
5. At an appropriate time in CIP standards’ development, use a team of experts to evaluate the CIP requirements
5
6
Most Violated Standards Based on rolling 12 months through 6/30/13 [Represents ~ 80% of total violations]
* As of 12-31-12 ** Not in NERC Rolling 12 month Top Ten
(HI) Standards in RED include requirements designated as High Impact Violations
SPP RE
Rank
NERC 12 Month
Rank* Standard Description
Number Violations
Risk Factor
1 1 CIP-007 Systems Security Management (HI) 37 Med./Lower
2 2 CIP-005 Electronic Security Perimeters (HI) 30 Med./Lower
3 3 CIP-006 Physical Security-Critical Assets 26 Med./Lower
4 4 PRC-005 Protection System Maintenance (HI) 9 High
5 6 CIP-004 Personnel & Training 9 Lower
6 7 CIP-003 Security Management Controls 9 Lower/Med.
7 5 CIP-002 Critical Cyber Asset Identification (HI) 7 Medium
8 8 VAR-002 Network Voltage Schedules 5 Med./Lower
9 ** TOP-004 Transmission Operations (HI) 4 High/Med.
10 ** PRC-008 UFLS Relay Maintenance 4 Medium
4
SPP RE Region Misoperation Report -1Q 2013
7
76%
78%
80%
82%
84%
86%
88%
90%
92%
94%
Q1-11 Q2-11 Q3-11 Q4-11 Q1-12 Q2-12 Q3-12 Q4-12 Q1-13
Correct Operations
Rolling 4 Quarter Average
Relay Operational Performance – Success Rate
NERC Reports
• NERC 2Q 2013 Vegetation Management Report
– No reportable contacts in SPP RE footprint
• National Misoperations Report and Q&A
– ~65% of misoperations grouped under three cause codes:
1. Incorrect settings/logic/design errors
2. Relay failures/malfunctions
3. Communication failures
– Summarizes ways to potentially reduce future misoperations
8
5
Outreach • Fall Workshop, Oct. 8-9, in Little Rock and via webinar
Agenda includes:
– NERC Guidance on CIP Version Transition
– Entity Perspectives on Internal Controls
– NERC’s Committee Structure/RAI Update
– Company-Wide Compliance Forums
– 12 break-out sessions
• Four new videos posted to video training webpage – CIP-005 R3
– Firewalls: 13 Ways to Break Through
– NetAPT Demo
– CIP-007 R3 and R4
• Webinars – 8/27/13, Standards Development Status Report presented by NERC
– 9/19/13, Winter Reliability Assessment
– 9/20/13, Determining and Communicating TOP System Operating Limits 9
Southwest Power Pool
BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Hilton Kansas City Airport, Kansas City, MO
April 30, 2013
- Summary of Action Items -
1. Approved Consent Agenda items: a. Approve January 29, 2013 minutes
b. Markets and Operations Policy Committee
i. ORWG - CRR001 ii. MWG - MPRR91, MPRR 95, MPRR100, MPRR102, MPRR113 iii. RTWG - TRR079, TRR090, TRR092
c. Finance Committee
i. Annual Financial Audit ii. Benefit Plan Funding
2. Approved the Corporate Governance Committee’s recommendation that the Board of Directors
approve the appointment of Mr. Bill Grant (SPS/Xcel) to serve on the Strategic Planning Committee.
3. Approved the Corporate Governance Committee’s recommendation that the Board of Directors approve the Project Cost Working Group charter as presented.
4. Approved the Corporate Governance Committee’s recommendation that the Board of Directors approve the Bylaws and Membership Agreement revisions to address withdrawal obligations.
5. Approved the Corporate Governance Committee’s recommendation that the Board of Directors approve the indemnification provisions for the Consolidated Balancing Authority and the necessary revisions to the Bylaws to support implementation of those provisions.
6. Approved the Corporate Governance Committee’s recommendation that the Board of Directors
approve removal of the detailed listings of duties for each committee reporting to the Board in Section 6.0 and revisions of the Bylaws accordingly.
7. Approved the Markets and Operations Policy Committee’s recommendation that the Board of
Directors approve the whitepaper on “Proposal for Improvement of the Generator Interconnection Study Process” with necessary tariff language to be developed and presented for approval in July.
8. Approved the Markets and Operations Policy Committee’s recommendation that the Board of
Directors approve the whitepaper on “Proposal for Improvement of the Aggregate Transmission Service Study Process” and the whitepaper on the “Aggregate Transmission Service Study Backlog Clearing Process” with necessary tariff language to be developed and presented for approval in October.
9. Approved the Markets and Operations Policy Committee’s recommendation that the Board of
Directors approve TRR085 to implement the Crediting Process Task Force whitepaper.
10. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors approve TRR 089 allowing the Regional Tariff Working Group to make non-substantive changes as needed.
SPP Board of Directors/Members Committee Minutes April 30, 2013
2
11. Approved the Markets and Operations Policy committee’s recommendation that the Board of Directors approve to suspend ITP10 projects: Tuco – New Deal 345 kV; Tuco – Amoco – Hobbs 345 kV; and Grassland – Wolfforth and reassess in 2014; and issue NTC using CPE as baseline for Woodward – Tatonga – Matthewson – Cimarron 345 kV.
3
MINUTES NO. 151
Southwest Power Pool
BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Hilton Kansas City Airport, Kansas City, MO
April 30, 2013 Agenda Item 1 - Administrative Items
SPP Chair Mr. Jim Eckelberger called the meeting to order at 8:00 a.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy:
Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Ricky Bittle, Arkansas Electric Cooperative Mr. Julian Brix, director Mr. Nick Brown, director Mr. Phil Crissup, Oklahoma Gas and Electric Mr. Mike Deggendorf, Kansas City Power and Light Mr. Jim Foley, proxy for Mr. Mo Doghman, Omaha Public Power District Mr. Jim Eckelberger, director Mr. Dennis Reed, proxy for Mr. Kelly Harrison, Westar Energy Mr. Dave Osburn, proxy for Ms. Cindy Holman, Oklahoma Municipal Power Authority Mr. Rob Janssen, Dogwood Energy Mr. Tom Kent, Nebraska Public Power District Mr. Jeff Knottek, City Utilities of Springfield Mr. Brett Kruse, Calpine Energy Services Mr. Josh Martin, director Mr. Roy Klusmeyer, proxy for Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Kevin Smith, Tenaska Mr. Stuart Solomon, American Electric Power Mr. Richard Ross, proxy for Mr. Stuart Solomon, American Electric Power (after 2:00 p.m.) Mr. Noman Williams, Sunflower Electric Power Corporation Mr. Mike Wise, Golden Spread Electric Cooperative
There were 128 persons in attendance either in person or via phone representing 33 members (Attendance List - Attachment 1). Mr. Nick Brown reported proxies and a quorum was declared (Proxies - Attachment 2). Agenda Item 2 – Board Reports President’s Report Mr. Nick Brown provided the President’s Report (President’s Report – Attachment 3). Mr. Brown thanked everyone for attending dinner the previous evening. It is considered a worthwhile investment of time and energy to cultivate relationships with the Board, staff, members, customers, regulators and vendors. Mr. Brown attended a dedication ceremony of the John Turk Power Plant three weeks ago hosted by AEP – SWEPCO and Ms. Venita McCellan-Allen. This plant is co-owned by American Electric Power (AEP), Arkansas Electric Cooperative (AECC), Oklahoma Municipal Power Authority (OMPA) and East Texas Electric Cooperative (ETEC). This was an historic event as it arguably may be the last coal-fired plant to be constructed. Mr. Brown announced that as of April 1, Mr. Mike Ross left SPP to run for the office of Governor of Arkansas. Mr. Ross brought a unique prospective to SPP and Mr. Paul Suskie and his staff will continue to implement Mr. Ross’s plan.
SPP Board of Directors/Members Committee Minutes April 30, 2013
4
The Mid-America Regulatory Conference (MARC) Annual Meeting will be in Little Rock June 8 – 12 hosted by the Arkansas Public Service Commission. This falls at the same time as the SPP Board of Directors Educational Workshop scheduled for June 10 – 11. There will be some opportunity for the groups to interact.
Mr. Brown referred to the SPP Metrics included in the background material and opened the floor for any questions. There was indication of high congestion due to unit outages, increased maintenance, and outages for new construction. While there were wind curtailments, there was a 20% increase in efficiency of generation over the same time last year. Currently there is capability of 8500 MW of wind.
Mr. Brown called attention to the 2012 SPP Annual Report, which was distributed at the meeting.
Mr. Brown announced there would be an Executive Session following the meeting. Input is needed from Members regarding a FERC Enforcement investigation.
Regional State Committee Report Mr. Tom Wright (Kansas Corporation Commission) presented the Regional State Committee (RSC) report. Mr. Wright stated the RSC met on April 29 beginning with a morning educational session on the SPP’s budget process and thanked Mr. Harry Skilton for the presentation. The following items were discussed in the RSC meeting:
• The selection of Thomas & Thomas to perform the 2012 RSC Audit. • The revision of the existing consultant contract as a tool to use going forward. • Heard reports regarding:
o Order 1000 Regional and Interregional Compliance o Long-Term Financial Transmission Rights o Regional Cost Allocation Review o Integrated Marketplace o Rate Impact Task Force
• Appointed Ms. Dana Murphy and Mr. Steve Stoll as liaisons to the Cost Allocation Working Group in lieu of forming a task force to review proposed improvements to SPP’s Aggregate Transmission Service Study process.
Federal Energy Regulatory Commission Report Mr. Patrick Clarey provided an update on recent FERC activities. The Commission’s focus has been on issuing the Order 1000 regional compliance orders, which started in February. In the first order, FERC rejected a proposal by Alcoa Power Generating Inc. (Yadkin) and the North Carolina utility subsidiaries of Duke Energy Corp. for failing to form a transmission planning region that meets the regional scope requirements of Order No. 1000. In the second order, FERC waived the regional transmission planning requirements for Maine Public Service Company, citing a unique geographic and electrical situation that makes it impossible for Maine Public Service to meet the regional scope requirement. At the March open meeting, the Commission issued its first orders on the merits of filings submitted to comply with the regional requirements of Order No. 1000. The Commission acted on filings from PJM, Midwest Independent Transmission System Operator and WestConnect.
In April, FERC continued to act on the regional compliance filings of the CAISO, NYISO, South Carolina Electric and Gas and NorthWestern Corp. Regional Entity Trustee Report Mr. Gerry Burrows presented the Regional Entity Trustee report (RE Report – Attachment 4). The report included updates on:
• Transition for CIP Version 3 to V4 to V5 • Paragraph 81 Project
SPP Board of Directors/Members Committee Minutes April 30, 2013
5
• Violated Standards • Operations Success Rate • NERC 4Q 2012 Vegetation Management
Human Resources Committee Report Ms. Phyllis Bernard provided the Human Resources Committee report (HRC Report – Attachment 5). The HRC last met on April 23 and discussed the following:
• 2012 Performance Compensation Process Review • HRC Scope • HR staff activities • Status of the 2013 Compensation Survey
Ms. Bernard pointed out that SPP salaries and benefits continue to be a major expense at 47% of the operating budget. Compensation is reviewed annually; every three years a comprehensive compensation study is conducted. Mercer has been retained for this purpose and is currently gathering data. Finance Committee Report Mr. Harry Skilton presented the Finance Committee report (FC Report – Attachment 6). Mr. Skilton highlighted the group’s activities since January. Two items are listed on the Consent Agenda requesting approval of the 2012 Financial Audit and the 2013 Benefit Plan Funding. The committee approved a 9% increase of the Integrated Marketplace capital budget; is beginning to reexamine a corporate aircraft; and is considering outside expertise for pension fund management. Agenda Item 3 – Consent Agenda
Mr. Eckelberger presented the following Consent Agenda items for approval (Consent Agenda – Attachment 7):
a. Approve January 28, 2013 minutes
b. Markets and Operations Policy Committee recommendations:
i. ORWG - CRR001 ii. MWG - MPRR91, MPRR 95, MPRR100, MPRR102, MPRR113
iii. RTWG - TRR079, TRR090, TRR092
c. Finance Committee recommendations:
i. Annual Financial Audit ii. Benefit Plan Funding
Mr. Eckelberger asked for requests to remove any items from the Consent Agenda or a motion to approve. Mr. Harry Skilton moved to approve the Consent Agenda items; Mr. Nick Brown seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Agenda Item 4 – Oversight Committee Report
Mr. Josh Martin provided the Oversight Committee Report. The Committee held its regular quarterly meeting in March with the following quarterly reports from Internal Audit, Compliance, and Market Monitoring staff.
• Internal Audit continues its regular audits, as well as its oversight role in the Integrated Marketplace initiatives. Plans are to continue the focus on higher-risk areas, and particularly those that intersect with the Integrated Marketplace initiative.
• A Compliance Forum was held March 7 in Dallas. The Regional Compliance Working Group has initiated its work to provide more formalized engagement in the stakeholder process in the
SPP Board of Directors/Members Committee Minutes April 30, 2013
6
Compliance area. Staff continues preparations for SPP’s first full CIP audit this summer, as well as its second 693 Audit and the Consolidated Balancing Authority certification, both in the fall.
• The Market Monitoring Unit staff remains engaged in the Integrated Marketplace initiative, developing the various new metrics that will be necessary to monitor the new markets.
Mr. Martin introduced three additional reports: Market Monitoring with the 2012 Annual State of the Market Report; Boston Pacific with the Looking Forward Report; and a Compliance overview of the various Compliance Support Services available to member companies. 2012 State of the Market Report Mr. Alan McQueen (MMU for SPP) presented the 2012 Annual State of the Market Report (ASOM Report – Attachment 8). Mr. McQueen addressed the following items:
• Market Conditions and Performance • Intensity of Congestion Increasing • Wind Impacts Increasing • Market Summary
Looking Forward Report Mr. Craig Roach (Boston Pacific) presented the Looking Forward report (Looking Forward Report – Attachment 9). Mr. Roach provided a view from a strategic planning context for issues beyond the next four quarters, the most important issues including: the shale gas revolution and EPA’s continuing campaign on coal. Compliance Outreach Program Mr. Philip Propes provided a report on the Compliance Outreach Program (Compliance Outreach Program – Attachment 10) outlining services offered to all registered entities. The Oversight Committee’s next scheduled meeting is June 10 in Little Rock. Agenda Item 5 – Corporate Governance Committee Report
Mr. Nick Brown presented the Corporate Governance Committee report (CGC Report – Attachment 11). In accordance with SPP’s Bylaws, the Corporate Governance Committee fills committee vacancies and recommends a candidate to the Board of Directors for consideration and appointment. Due to Mr. David Hudson’s (SPS/Xcel) resignation from the Strategic Planning Committee, Mr. Brown made the following motion:
The Corporate Governance Committee recommends the appointment of Mr. Bill Grant (SPS/Xcel) to serve on the Strategic Planning Committee.
Mr. Harry Skilton seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Mr. Brown stated that the Markets and Operations Policy Committee (MOPC) established the Project Cost Working Group to oversee project cost estimates for regional transmission projects. The group recently recommended revisions to its charter. Mr. Brown presented the revised group charter and moved for approval.
The Corporate Governance Committee recommends approval of the Project Cost Working Group charter as presented.
Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.
SPP Board of Directors/Members Committee Minutes April 30, 2013
7
Mr. Brown reported SPP has a formula for calculating the withdrawal fee for an exiting Member to cover that Member’s pro rata share of SPP, Inc.’s financial obligations at the effective date of the withdrawal. With the implementation of regional cost allocation for transmission projects, it is necessary for SPP to revise its governing documents to address an exiting Member’s obligations for transmission costs allocated to the Member’s load as well as revenues due. In considering how the organization and the planning process would be impacted in the event a Member withdraws from SPP, Bylaws and Membership Agreement revisions are recommended to provide clarity, transparency and fairness, and also align with the Tariff. The Corporate Governance Committee and SPP members were commended for all their due diligence in this effort. Mr. Brown moved to approve these revisions as presented in the attached committee report:
The Corporate Governance Committee recommends approval of the Bylaws and Membership Agreement revisions to address withdrawal obligations. The CGC concurs with the Tariff revisions approved by RTWG and MOPC that complement the revisions recommended here.
Ms. Phyllis Bernard seconded the motion. Mr. Rob Janssen noted the MOPC endorsed the Bylaws and Membership Agreement changes as well. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Mr. Brown reported the CGC was assigned the responsibility for recommending indemnification revisions for the Balancing Authority Agreement (Attachment AN of the Tariff). Mr. Brown moved to approve these revisions and the corresponding Bylaws revisions as presented in the attached committee report.
The Corporate Governance Committee recommends approval of the indemnification provisions for the Consolidated Balancing Authority and the necessary revisions to the Bylaws to support implementation of those provisions.
Mr. Brown pointed out the detail of duties outlined in the Bylaws has become cumbersome. Each change requires a FERC filing. It is recommended to remove the detail of duties from the Bylaws and reflect them in the groups’ respective charters to allow more flexibility. Mr. Brown moved to approve the CGC recommendation.
The Corporate Governance Committee recommends removal of the detailed listings of duties for each committee reporting to the Board in Section 6.0 and revisions of the Bylaws accordingly.
Mr. Josh Martin seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Agenda Item 6 – Markets and Operations Policy Committee Report
Mr. Rob Janssen provided the Markets and Operations Policy Committee report (MOPC Report – Attachment 12). Mr. Janssen reported briefly on the following informational items (details in attached report):
• BPWG – BPR033 • SSC – Order 1000 • RTWG - Crediting • MWG – MPRR94, MPRR109, MPRR112 • PCWG – Project Cost Review • ESWG – ITP20/ITP10 Update • ORWG – CRR002 • Standard Process Manual • Staff
o Balanced Portfolio o Project Costs o RCAR Status
SPP Board of Directors/Members Committee Minutes April 30, 2013
8
o Probabilistic Planning Mr. Janssen then presented the following action items for approval:
Generator Interconnection Study Process Improvement Concepts
Mr. Lanny Nickell provided background regarding the Generator Interconnection study process improvements. He outlined the problems, milestones for entering the Definitive Interconnection System Impact Study (DISIS) queue, and plans to revamp DISIS for better customer service as well as other revisions. Following much discussion, Mr. Jim Eckelberger recommended rethinking the time period for open seasons, which was shown as 120 days, to something shorter. Mr. Nickell presented the following motion for approval:
MOPC recommends approval of the whitepaper on “Proposal for Improvement of the Generator Interconnection Study Process” with necessary tariff language to be developed and presented for approval in July.
Mr. Larry Altenbaumer moved to approve the whitepaper; Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Aggregate Transmission Service Study (ATSS) Improvement Concepts
Mr. Nickell then presented detailed background for the Aggregate Transmission Service Study process improvements and the backlog clearing process. Following considerable discussion, he presented the following recommendation:
MOPC recommends approval of the whitepaper on “Proposal for Improvement of the Aggregate Transmission Service Study Process” and the whitepaper on the “Aggregate Transmission Service Study Backlog Clearing Process” with necessary tariff language to be developed and presented for approval in July.
Mr. Julian Brix moved to approve the ATSS whitepaper with tariff language to be developed and presented in October rather than July; Ms. Phyllis Bernard seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. TRR 085, TRR 089
Mr. Nickell provided information regarding the TRR 085 and the Credit Practices Task Force (CPTF) whitepaper.
MOPC recommends TRR 085 be approved to implement the CPTF whitepaper. Mr. Julian Brix moved to approve TRR085; Mr. Nick Brown seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed.
Mr. Nickell then provided information for TRR089 regarding interregional transmission planning requirements of Order 1000. This filing is due July 10 and may require a special meeting to meet this deadline. Mr. Nickell then asked for approval of the following recommendation:
MOPC recommends approval of TRR 089 allowing the RTWG to make non-substantive changes as needed.
Mr. Harry Skilton moved to approve TRR 089; Mr. Nick Brown seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. ITP10 Projects – Suspensions/NTCs Issued
Mr. Nickell provided information for ITP10 projects. He requested approval and actions for the following projects:
TTuuccoo –– NNeeww DDeeaall 334455 kkVV SSuussppeenndd NNTTCC--CC//RReeaasssseessss iinn 22001144
SPP Board of Directors/Members Committee Minutes April 30, 2013
9
TTuuccoo –– AAmmooccoo –– HHoobbbbss 334455 kkVV SSuussppeenndd NNTTCC--CC//RReeaasssseessss iinn 22001144
GGrraassssllaanndd -- WWoollffffoorrtthh SSuussppeenndd NNTTCC--CC//RReeaasssseessss iinn 22001144
WWooooddwwaarrdd –– TTaattoonnggaa –– MMaatttthheewwssoonn –– CCiimmaarrrroonn 334455 kkVV IIssssuuee NNTTCC//UUssee CCPPEE aass BBaasseelliinnee
Mr. Nick Brown moved to approve the ITP10 projects and actions as requested; Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Mr. Jim Eckelberger directed the staff to come back with a high priority study to evaluate high load growth.
Agenda Item 7 – Integrated Marketplace Update
Mr. Bruce Rew provided an update on the Integrated Marketplace (Integrated Marketplace – Attachment 13). He outlined some favorable budget variances as well as some unfavorable variances. The unfavorable variances have resulted from both direct market design changes and delay impacts. As a result Mr. Rew requested approval of the following capital budget modification:
SPP staff recommends a modification of the Integrated Marketplace capital budget to a total of $115 million, representing a 9% increase.
Mr. Harry Skilton moved to approve the Integrated Marketplace capital budget modification; Mr. Julian Brix seconded. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Agenda Item 8 – Standards Process Manual Task Force Report
Ms. Emily Pennel provided the Standards Process Manual Task Force report (SPMTF Report – Attachment 14). Ms. Pennel outlined proposed revisions to the Standards Process Manual, the voting process and requested approval of the following recommendation:
The SPMTF recommends the BOD/MC concur with the stakeholder approval and MOPC-endorsed revisions to the SPP RE Regional Standards Development Process Manual.
Mr. Josh Martin moved to endorse the revisions as submitted; Mr. Nick Brown seconded the motion. The Members Committee voted indicated unanimous support. The Board voted; the motion passed. Agenda Item 9 – Future Meetings
Mr. Eckelberger reminded the group he next SPP Board of Directors meeting will be the annual educational workshop on June 10 – 11 in Little Rock. The next regular meeting will be held July 30 in Denver, CO (Future Meetings – Attachment 15). Adjournment
With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 3:30 p.m. Stacy Duckett, Corporate Secretary Executive Session The group discussed a pending FERC Enforcement matter and provided staff direction.
Southwest Power Pool
BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Teleconference
July 1, 2013
- Summary of Action Items -
1. Approved the Markets and Operations Policy Committee’s recommendation that the Board of Directors approve TRR 098 with the addition that SPP Staff first seek a waiver from Order 1000 Interregional Requirements with the Southeastern Regional Transmission Planning Process (SERTP) region.
2
MINUTES NO. 152
Southwest Power Pool
BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING Teleconference
July 1, 2013 Agenda Item 1 - Administrative Items
SPP Chair Mr. Jim Eckelberger called the meeting to order at 9:25 a.m. The following Board of Directors/Members Committee members were in attendance or represented by proxy:
Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Julian Brix, director Mr. Nick Brown, director Mr. Mike Deggendorf, Kansas City Power and Light Mr. Jim Eckelberger, director Mr. Kelly Harrison, Westar Energy Ms. Cindy Holman, Oklahoma Municipal Power Authority Mr. Rob Janssen, Dogwood Energy Mr. Paul Malone, proxy for Mr. Tom Kent, Nebraska Public Power District Mr. Brett Kruse, Calpine Energy Services Mr. Gary Roulet, Western Farmers Electric Cooperative Mr. Harry Skilton, director Mr. Kevin Smith, Tenaska Mr. Stuart Solomon, American Electric Power Mr. Noman Williams, Sunflower Electric Power Corporation
Mr. Nick Brown declared a quorum (Proxies - Attachment 1). Agenda Item 2 – Markets and Operations Policy Committee Recommendation Mr. Jim Eckelberger presented the Markets and Operations Policy Committee (MOPC) recommendation regarding TRR 098 (Attachment 2):
MOPC recommends the approval of TRR 098 with the addition that SPP Staff first seek a waiver from Order 1000 Interregional Requirements with the Southeastern Regional Transmission Planning Process (SERTP) region.
Mr. Harry Skilton moved to approve; Mr. Larry Altenbaumer seconded the motion. During discussion, Mr. Eckelberger asked if the Tariff language would support three items: 1) interregional projects would not be limited to voltage or mileage, 2) cost benefits would be significant/defined, and 3) would not limit the project type to any one category. It was agreed the language would allow for these items. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Adjournment
With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting at 9:45 a.m. Stacy Duckett, Corporate Secretary
RTWG TRR 093 & 095 Recommendations to MOPC 7 16-17 2013.docx Page 1 of 2
Southwest Power Pool, Inc.
MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors
TRRs 093 and 095
July 29-30, 2013
Organizational Roster The following persons are members of the Regional Tariff Working Group:
Dennis Reed, WR (Chair) Charles Locke, KCPL (Vice-Chair) Richard Andrysik, LES Bill Dowling, Midwest Energy Luke Haner, OPPD Tom Hestermann, Sunflower Rob Janssen, Dogwood David Kays, OGE Lloyd Kolb, Golden Spread David Linton, ITC Great Plains Tom Littleton, OMPA Bernie Liu, Xcel
Paul Malone, NPPD Adam McKinnie, MoPSC Robert Pennybaker, AEP Neil Rowland, KMEA Robert Shields, AECC Keith Tynes, ETEC John Varnell, Tenaska Bary Warren, EDE Mitch Williams, WFEC Brenda Fricano, SPP (Staff Secretary)
Background Please see the TRR Recommendation Reports for TRRs 093and 095 that were included in the MOPC July 16-17, 2013 background materials.
Analysis Please see the TRR Recommendation Reports for TRRs 093 and 095 that were included in the MOPC July 16-17, 2013 background materials.
Recommendation The MOPC recommends that the BOD approve its request regarding TRRs 093 and 095.
Action Requested: Approval of RTWG’s request on TRRs 093 and 095.
APPROVED: MOPC July 16-17, 2013
Approved Unanimously
RTWG TRR 093 & 095 Recommendations to MOPC 7 16-17 2013.docx Page 2 of 2
TRR Number
Description RTWG Meeting Vote
093
Removes in its entirety from Attachment L: 1) Section VI., Exception to the Provisions of Section II.C of this Attachment L, and 2) Section 6, Agreement of the Southwest Power Pool Transmission Owners And Southwest Power Pool For The Upgrade of The LaCygne to Stilwell 345 kV Transmission Line
April 25, 2013
Approved unanimously
095 Revision of Index of Grandfathered Agreements, Attachment W.
June 27, 2012
Approved unanimously
Tariff Revision Request (TRR)
Page 1 of 8
TRR Number 093 TRR
Title Removal of revenue distribution methodology for the upgrade of the LaCygne-Stillwell Circuit
Cross Reference # PRR BRR Other (Specify) _ _____________
Sponsor Name Alfred Busbee E-mail Address [email protected] Company Southwest Power Pool Phone Number 501-688-8309 Date 04/15/2013
Tariff Section(s) Requiring Revision
Section No and Titles: 1) Attachment L, Section VI, Exception to the Provisions of Section II.C of this Attachment L and 2) Attachment L, Section, Agreement of the Southwest Power Pool Transmission Owners And Southwest Power Pool For The Upgrade of The LaCygne to Stilwell 345 kV Transmission Line Tariff Version (effective date) April 10, 2003
Requested Resolution Normal Urgent (provided justification below for urgent
request)
Revision Description
Remove in its entirety from Attachment L: 1) Section VI., Exception to the Provisions of Section II.C of this Attachment L, and 2) Section, Agreement of the Southwest Power Pool Transmission Owners And Southwest Power Pool For The Upgrade of The LaCygne to Stilwell 345 kV Transmission Line
Reason for Revision
In Docket No. ER03-547, the Commission accepted on April 10, 2003, an agreement between Southwest Power Pool, Inc. (SPP) and the SPP transmission owners that was subsequently incorporated into Attachment L. The agreement specified the terms and conditions concerning cost recovery for upgrades to the LaCygne toStillwell 345 kV transmission line (LaCygne-Stillwell Circuit). To compensate KCP&L for the costs of the upgrade, the Parties agreed to modify the existing revenue distribution methodology under the SPP OATT creating an exception to the exiting revenue distribution methodology until the costs for the LaCygne-Stillwell Circuit had been recovered. The cost of the upgrade has been fully recovered.
Tariff Revision Request (TRR)
Page 2 of 8
The exception and governing agreement are no longer in effect.
Stakeholder Approval Required (specify date and record outcome of vote; n/a for those stakeholders not required)
MWG BPWG (n/a) TWG (n/a) ORWG (n/a) Other (specify) (n/a) RTWG - 4-25-2013 – Approved MOPC Board of Directors
Legal Review Completed
Yes (Include any comments resulting from the review)
No
Market Protocol Implications or Changes
Yes (Include a summary of impact and/or specific changes & PRR #)
No
Business Practice Implications or Changes
Yes (Include a summary of impact and/or specific changes & BPR #)
No
Criteria Implications or Changes
Yes (Include a summary of impact and/or specific changes)
No Other Corporate Documents Implications (i.e., SPP By-Laws, Membership Agreement, etc.)
Yes (Include which corporate documents)
No
Tariff Revision Request (TRR)
Page 3 of 8
Credit Implications
Yes (Include a summary of impact and/or specific changes)
No
Impact Analysis Required
Yes
No
Proposed Tariff Language Revisions (Redlined)
VI. Exception to the Provisions of Section II.C of this Attachment L
Pursuant to the Agreement of the Southwest Power Pool Transmission Owners and Southwest
Power Pool for the Upgrade for the LaCygne to Stilwell 345 kV Transmission Line (“LaCygne-Stilwell
Agreement”) submitted to the FERC on February 20, 2003 in Docket No. ER03-547, and conditionally
accepted by the Commission in an order dated April 10, 2003, the Transmission Provider and the
Transmission Owners agreed to create an exception to the provisions of this attachment L for the sole
purpose of distributing revenues associated with upgrades to the LaCygne to Stilwell 345 kV line, as set
forth in the LaCygne-Stilwell Agreement, which has been incorporated into this Attachment L.
6 Agreement of the Southwest Power Pool Transmission Owners And Southwest Power Pool
For The Upgrade of The LaCygne to Stilwell 345 kV Transmission Line
This Agreement, entered into this 20th day of February, 2003, by and between Southwest Power
Tariff Revision Request (TRR)
Page 4 of 8
Pool, Inc. (“SPP”) and the Participating SPP Transmission Owners (collectively, “the Parties”).
WHEREAS, SPP provides regional transmission service over the transmission systems of the SPP
Transmission Owners pursuant to an Open Access Transmission Tariff (“OATT”) filed consistent with
the Order No. 888 pro forma OATT;
WHEREAS, SPP did not foresee an obligation under the policies of the Federal Energy
Regulatory Commission (“FERC”) to renew a number of Firm Point-to-Point transmission reservations
previously granted under the SPP OATT;
WHEREAS, SPP does not presently have sufficient Available Transfer Capability (“ATC”) on the
LaCygne to Stilwell line (“the Circuit”) to renew Firm Point-to-Point transmission service for such
reservations;
WHEREAS, FERC’s recent order in Exelon Generation Co., LLC v. Southwest Power Pool, Inc.,
99 FERC ¶ 61,235, reh’g denied, 101 FERC ¶ 61,226 (2002), obligates SPP to renew said firm
transmission reservations, even though the SPP transmission system was not expanded in anticipation of
renewing said firm transmission reservations;
WHEREAS, SPP has experienced Level 5 Transmission Loading Relief due to the Circuit
limitation;
WHEREAS, the Parties desire to remedy system constraints posed by the Circuit by
reconductoring and upgrading its capacity from 1,251 MVA to 1,793 MVA;
WHEREAS, SPP anticipates a merger between it and the Midwest Independent Transmission
System Operator, Inc., forming the Resulting Company, that may occur before the project costs are fully
paid to Kansas City Power & Light Company (“Kansas City Power & Light”) and that subsequent to the
effective date of that merger, service will be provided to the Participating SPP Transmission Owners
under the Resulting Company OATT as successor to the SPP OATT;
WHEREAS, the elimination of the Circuit limitation will provide additional ATC and allow the provision of additional point-to-point transmission service under the SPP OATT and the Resulting Company OATT
and provide significant additional revenue that would be allocable to the Parties; and WHEREAS, the Parties agree that capitalized terms used herein shall have the same meaning as in
the SPP OATT.
NOW, THEREFORE, in consideration of the mutual covenants and agreements herein, the Parties
Tariff Revision Request (TRR)
Page 5 of 8
agree as follows:
1.0 Kansas City Power & Light agrees to upgrade the Circuit by reconductoring it and increasing the
Circuit’s capacity. Kansas City Power & Light also agrees to use its best efforts to complete the
upgrade by July 1, 2003. Furthermore, Kansas City Power & Light agrees to use its best efforts to
not exceed the upgrade estimated cost of $6,557,000.
2.0 The Parties agree to initially treat Kansas City Power & Light’s upgrade of the Circuit in the same
manner that a Direct Assignment Facility would be treated under the SPP OATT and the revenue
allocation provisions of Attachment L, Section III.7. The Parties agree that the circumstances here
are unique and that they are not by their Agreement here agreeing in any way that this same
treatment would be appropriate in other circumstances. Future circumstances similar to this one
will need to be evaluated on a case-by-case basis.
3.0 The Parties agree that SPP and the Resulting Company shall allocate to Kansas City Power &
Light any and all transmission service revenues resulting from transmission service agreements
under Schedules 7 and 8 of the SPP Tariff entered into after the date of this Agreement, that could
not have been approved but for the reconductoring of the Circuit. At such time as Kansas City
Power & Light’s project cost (plus a return on invested capital) for the Circuit upgrade is
recovered, subject to the provisions of paragraph 4.0 below, SPP and the Resulting Company shall
thereafter allocate transmission service revenues from service agreements made possible by the
reconductoring of the Circuit pursuant to the applicable provisions of the SPP OATT or the
Resulting Company Transmission Owner Agreement.
4.0 In the event that the actual cost for the project exceeds the estimated project cost of $6,557,000,
the recognized project cost to Kansas City Power & Light shall be limited to no more than
$7,541,000 (115% of the estimated Cost). Any project expenditure in excess $7,541,000 will be
solely borne by Kansas City Power & Light. Additionally, Kansas City Power & Light shall be
allocated a return on invested capital at a rate of 8.25 percent per annum, applied and paid monthly
on the outstanding capital balance.
5.0 Kansas City Power & Light agrees to provide the SPP, the Resulting Company and/or the other
Participating SPP Transmission Owners access to its books and records that pertain to this project
Tariff Revision Request (TRR)
Page 6 of 8
for the purpose of any necessary audit of the costs incurred in completing the upgrade of the
Circuit.
6.0 In the event that a Participating SPP Transmission Owner terminates its provision of service under
the SPP OATT or the Resulting Company OATT, such transmission owner shall be under no
further obligation pursuant to this agreement and the revenues reallocated from the remaining
Participating SPP Transmission Owners shall be adjusted to reflect the revenue allocations that
would result after the withdrawal of the terminating Transmission Owner.
7.0 The SPP will provide monthly reports to each of the Participating SPP Transmission Owners
detailing the amount of transmission revenue allocated on behalf of each party to Kansas City
Power & Light for any month in which such revenues are allocated. The SPP will provide
monthly summary reports and quarterly detailed reports to each of the Participating SPP
Transmission Owners detailing the transmission service agreements under Schedules 7 and 8 of
the OATT entered into after the date of the Agreement that could not have been approved but for
the reconductoring of the Circuit.
8.0 The Parties agree that consideration will be given to recognizing the contributions of each Party to
the construction of the facility upgrade at such time as the methodologies for allocation of
Financial Transmission Rights (“FTR’s”), Congestion Revenue Rights (“CRR’s”), or other
assigned transmission rights are developed, consistent with the requirements of authorities having
jurisdiction over such allocation.
9.0 [Reserved]
10.0 This Agreement shall be binding on the successors and assigns of the Parties.
11.0 Any notice or request made to or by a Party regarding this Agreement shall be made to the
representatives of all other Parties as indicated below. Such representative and address for notices
or requests may be changed from time to time by notice by any Party.
Southwest Power Pool:
415 N. McKinley, 800 Plaza West
Little Rock, AR 72205
Tariff Revision Request (TRR)
Page 7 of 8
Proposed Market Protocol Language Revision (Redlined) n/a
Proposed Business Practices Language Revision (Redlined)
n/a
Tariff Revision Request (TRR)
Page 8 of 8
Proposed Criteria Language Revision (Redlined)
n/a
Revisions to Other Corporate Documents (Redlined)
n/a
Tariff Revision Request (TRR)
TRR Number 095 TRR
Title Revisions to Attachment W – Index of Grandfathered Agreements
Cross Reference # MPRR BRR Other (Specify) _ _____________
Sponsor Name Sherry Hamilton E-mail Address [email protected] Company SPP Phone Number 501-614-3962 Date 6-12-13
Tariff Section(s) Requiring Revision
Section No. Attachment W Titles Index of Grandfathered Agreements Tariff Version Sixth Revised Volume No. 1
Requested Resolution Normal Urgent (provided justification below for urgent
request)
Revision Description Revision of Index of Grandfathered Agreements, Attachment W
Reason for Revision Grandfathered Agreements have expired or terminated and termination provisions for some have changed.
Tariff Revision Request (TRR)
Stakeholder Approval Required (specify date and record outcome of vote; n/a for those stakeholders not required)
MWG (n/a) BPWG (n/a) TWG (n/a) ORWG (n/a) Other (specify) (n/a) RTWG - 6-27-2013 – RTWG Approved MOPC Board of Directors
Legal Review Completed
Yes (Include any comments resulting from the review)
No
Market Protocol Implications or Changes
Yes (Include a summary of impact and/or specific changes & PRR #)
No
Business Practice Implications or Changes
Yes (Include a summary of impact and/or specific changes & BPR #)
No
Criteria Implications or Changes
Yes (Include a summary of impact and/or specific changes)
Tariff Revision Request (TRR)
No
Other Corporate Documents Implications (i.e., SPP By-Laws, Membership Agreement, etc.)
Yes (Include which corporate documents)
No
Credit Implications
Yes (Include a summary of impact and/or specific changes)
No
Impact Analysis Required
Yes
No
Tariff Revision Request (TRR)
Proposed Tariff Language Revisions (Redlined) SEE BELOW
Tariff Revision Request (TRR)
ATTACHMENT W
INDEX OF GRANDFATHERED AGREEMENTS
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
1
GRDA/KAMO Generation Participation
Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover provisions thereafter
2 East Miami Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2014 with rollover provisions thereafter
3 OMPA Generation Grand River Dam Authority
Oklahoma Municipal Power Authority Point To Point
Through 12/31/2010 with rollover provisions thereafter
4 City of Springfield, Mo Grand River Dam Authority
City Utilities of Springfield, MO Point To Point
Through 12/31/2010 with rollover provisions thereafter
5 Byng & Chickasaw Nation
Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 6/30/2015 with rollover provisions thereafter
6 City of Skiatook Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover provisions thereafter
7 345/KV Transmission Agreement
Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover provisions thereafter
8 345/KV Transmission Agreement
Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover provisions thereafter
9 OMPA Generation Grand River Dam Authority
Oklahoma Municipal Power Authority Point To Point
Through 12/31/2010 with rollover provisions thereafter
10 WFEC/BANK Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover provisions thereafter
11 WFEC/BANK Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover
Tariff Revision Request (TRR)
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions provisions thereafter
12 City of Poplar Bluff Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover provisions thereafter
13 City of Paragould Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover provisions thereafter
14
CSWS/GRDA Network Load/Ramona
Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover provisions thereafter
15
CSWS/GRDA Network Load/Pryor Others
Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2010 1/1/2035 with rollover provisions thereafter
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
16
AECI/GRDA Interconnect Agreement
Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2002 1/1/2035 with rollover provisions thereafter
17
AECI/GRDA Interconnect Agreement
Grand River Dam Authority
Grand River Dam Authority Point To Point
Through 12/31/2002 1/1/2035 with rollover provisions thereafter
18
Agreement between Western Farmers Electric Cooperative and the Anadarko Public Works Authority, Anadarko, Oklahoma
Western Farmers Electric Cooperative
Anadarko, Oklahoma Public Works Authority
All requirements wholesale power supply agreement
Agreement shall remain in effect until cancelled by either party giving written notice to the other delivered at least two years prior to July 31, 2007, or thereafter upon one years' written notice on any annual anniversary of agreement.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
19
Agreement between Western Farmers Electric Cooperative and the Broken Bow Public Works Authority, Broken Bow, Oklahoma
Western Farmers Electric Cooperative
Broken Bow, Oklahoma Public Works Authority
All requirements wholesale power supply agreement
Agreement shall remain in effect until cancelled by either party giving written notice to the other delivered at least two years prior to December 31, 2004, or thereafter upon one years' written notice on any annual anniversary of agreement.
20
Agreement between Western Farmers Electric Cooperative and the Clarksville Light and Water Co.
Western Farmers Electric Cooperative
Clarksville, Arkansas Light and Water Co.
All requirements wholesale power supply agreement
Agreement shall remain in effect until cancelled by either party giving written notice to the other delivered at least one years prior to May 31, 2003, or thereafter upon one years' written notice on any annual anniversary of agreement.
21
Agreement between Western Farmers Electric Cooperative and the New Cordell Utility Authority, Cordell, Oklahoma
Western Farmers Electric Cooperative
New Cordell Utility Authority
All requirements wholesale power supply agreement
Agreement shall remain in effect until cancelled by either party giving written notice to the other delivered at least two years prior to August 31, 2007, or thereafter upon one years' written notice on any annual anniversary of agreement.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
22
Interchange Agreement between Western Farmers Electric Cooperative and the City of Electra, Texas
Western Farmers Electric Cooperative City of Electra, Texas
All requirements wholesale power supply agreement
Agreement shall remain in effect until cancelled by either party giving written notice to the other delivered at least two years prior to May 31, 2007, or thereafter upon one years' written notice on any annual anniversary of agreement.
23
Wholesale Power Contract with Member Cooperatives
Western Farmers Electric Cooperative
Western Farmers Electric Cooperative and its Member Co-ops
All requirements wholesale power supply agreement (currently approximately 800 MW)
Agreement shall continue in effect until July 1, 2025, and thereafter until terminated by either party's giving to the other not less than six months' written notice of its desire to terminate.
24
Agreement between Western Farmers Electric Cooperative and the Mooreland Public Works Authority, Mooreland, Oklahoma
Western Farmers Electric Cooperative
Morland Public Works Authority
All requirements wholesale power supply agreement
Agreement shall remain in effect until cancelled by either party giving written notice to the other delivered at least one years prior to March 31, 2007, or thereafter upon one years' written notice on any annual anniversary of agreement.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
25
Transmission Service and Coordination Agreement
Western Farmers Electric Company
Oklahoma Municipal Power Authority
Network Integration and Long-Term Point-To-Point Transmission Service Agreement executed before February 1, 2000
Agreement shall remain in effect until cancelled by either party giving written notice to the other delivered at least four years prior to the end of the initial term or four years prior to such later specified date for termination.
26
Agreement between Western Farmers Electric Cooperative and the City of Watonga, Oklahoma
Western Farmers Electric Company
City of Watonga, Oklahoma
All requirements wholesale power supply agreement
Agreement shall remain in effect until cancelled by either party giving written notice to the other delivered at least one years prior to March 31, 2007, or thereafter upon one years' written notice on any annual anniversary of agreement.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
27
Transmission Service Agreement between Southwestern Electric Power Company and City of Lafayette, Louisiana
Southwestern Electric Power Company
City of Lafayette, Louisiana n/aFirm TS year-to-year
28
Transmission Service Agreement between KAMO Electric Cooperative, Inc. and Public Service Company of Oklahoma
Public Service Company of Oklahoma
KAMO Electric Cooperative, Inc. n/aFirm TS year-to-year
29
Contract for Electric Service between Public Service Company of Oklahoma and South Coffeyville Public Works Authority
Public Service Company of Oklahoma
City of S. Coffeyville, Oklahoma n/aFull RQ year-to-year
30
Transmission Service Agreement between Public Service Company of Oklahoma and Southwestern Public Service Company
Public Service Company of Oklahoma
Southwestern Public Service Company n/a
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
31
Agreement for Interchange of Electric Power and Energy between PSO and the United States of America, acting through the Secretary of Energy as presented by the Administrator, Southwestern Power Administration
Public Service Company of Oklahoma
Southwestern Power Administration n/a -
32
Contract for Electric Service between Public Service Company of Oklahoma and City of Collinsville, Oklahoma
Public Service Company of Oklahoma
City of Collinsville, Oklahoma n/a year-to-year
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
33
Electric System Interconnection Agreement Between Cajun Electric Power Cooperative, Inc. and Southwestern Electric Power Company
Southwestern Electric Power Company Louisiana Generation n/a year-to-year
34
Transmission Service Agreement between Western Farmers Electric Cooperative and Public Service Company of Oklahoma
Public Service Company of Oklahoma
Western Farmers Electric Cooperative n/a "network type"
year-to-year after 5/31/03 with 24 month notice to terminate
35
Power Supply Agreement between Southwestern Electric Power Co. and City of Minden, Louisiana
Southwestern Electric Power Company City of Minden, Louisiana
Network (via SWE) year-to-year
36
System Network Integration Service and Network Operating Agreement
Southwestern Electric Power Company
East Texas Electric Cooperative
Service Agreement No. 456 Network 12/31/2004
37
System Network Integration Service and Network Operating Agreement
Southwestern Electric Power Company
Northeast Texas Electric Cooperative
Service Agreement No. 398 Network 12/31/2004
38
Contract for Electric ServiceContract No. 3950003
Public Service Company of Oklahoma
Northeast Oklahoma Electric Cooperative, Inc. n/aFull RQ
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
39
Amended Agreement for Interchange of Electric Power and Energy between Grand River Dam Authority and Public Service Company of Oklahoma
Public Service Company of Oklahoma
Grand River Dam Authority n/aFirm TS until canceled
40
Amended Agreement for Interchange of Electric Power and Energy between Grand River Dam Authority and Public Service Company of Oklahoma
Grand River Dam Authority
Public Service Company of Oklahoma n/a until canceled
41 Network Service Agreement
Central and Southwest Services Operating Companies
Oklahoma Municipal Power Authority Network
Dec. 31, 2003 with evergreen and twelve-month notice.
42
Agreement for Purchase and Sale of Electric Power and Energy between Southwestern Electric Power Co. and City of Hope, Arkansas
Southwestern Electric Power Company City of Hope, Arkansas n/a year-to-year
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
43
Flint Creek Power Plant Power Coordination, Interchange and Transmission Service Agreement between Arkansas Electric Cooperative Corporation and Southwestern Electric Power Company
Southwestern Electric Power Company
Arkansas Electric Cooperative Corporation 72 "network like"
year-to-year, but notice has been given.
44
Power Supply Agreement between Southwestern Electric Power Co. and City of Bentonville, Arkansas
Southwestern Electric Power Company
City of Bentonville, Arkansas n/a year-to-year
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
45
Power Supply Agreement between Southwestern Electric Power Co. and Tex-La Electric Cooperative of Texas, Inc.
Southwestern Electric Power Company
Tex-La Electric Cooperative of Texas 110
Network-like bundled svc. 12-31-04 (transmission)
46
Power Supply Agreement between Southwestern Electric Power Co. and Rayburn Country Electric Cooperative
Southwestern Electric Power Company Rayburn Country
Network-like bundled svc.Full RQ year-to-year
47
Firm Point to Point Transmission Service Agreement
Central and Southwest Services Operating Companies City of Coffeyville, KS Point To Point none
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
48 Network Service Agreement
Central and Southwest Services Operating Companies
Public Service Company of Oklahoma, Southwestern Electric Power Company Network year-to-year
49
Service Agreement For Network Integration Transmission Service Between South Plains Electric Cooperative, Inc and Southwestern Public Service Company
Southwestern Public Service Company
South Plains Electric Cooperative
Service Agreement No. 161 under FERC Electric Tariff, Second Revised Volume No. 1 Network
Year-to-year unless terminated by either party
50
Service Agreement For Network Integration Transmission Service Between Golden Spread Electric Cooperative, Inc. and Southwestern Public Service Company
Southwestern Public Service Company
Golden Spread Electric Cooperative
Service Agreement No. 151 under FERC Electric Tariff, Second Revised Volume No. 1 Network
Year-to-year unless terminated by either party
51
Interconnection Agreement between Public Service Company of New Mexico and Southwestern Public Service Company
Southwestern Public Service Company
Public Service Company of New Mexico
FERC Rate Schedule No. 102 Point To Point
Year-to-year unless terminated by either party
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
52
Electric Power Service Agreement between the Empire District Electric Company and Southwestern Public Service Company
Southwestern Public Service Company
Empire District Electric Company
FERC Rate Schedule No. 124 Point To Point
Year-to-year unless terminated by either party
53
CONTRACT FOR THE SALE AND PURCHASE OF ELECTRIC POWER AND ENERGY between CITY OF SPRINGFIELD, MISSOURI and CITY OF FULTON, MISSOURI
City Utilities of Springfield, MO Fulton, MO Point To Point Yes
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
54
SPRINGFIELD - MALDEN POWER SALE AGREEMENT
City Utilities of Springfield, MO Malden, MO Point To Point Yes
55
ELECTRICAL POWER SUPPLY AGREEMENT BETWEEN MISSOURI JOINT MUNICIPAL ELECTRIC UTILITY COMMISSION AND CITY UTILITIES OF SPRINGFIELD, MISSOURI
City Utilities of Springfield, MO MJMEUC Point To Point Yes
56
ELECTRICAL CAPACITY, ENERGY, AND SERVICE SALES AGREEMENT BETWEEN CITIES OF NIXA AND SPRINGFIELD, MISSOURI
City Utilities of Springfield, MO Nixa, MO Point To Point Yes On-going
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
57
AMENDED INTERCHANGE AGREEMENT BY AND AMONG ASSOCIATED ELECTRIC COOPERATIVE, INC., THE EMPIRE DISTRICT ELECTRIC COMPANY, GRAND RIVER DAM AUTHORITY, SOUTHWESTERN ELECTRIC POWER COMPANY, AND BOARD OF PUBLIC UTILITIES OF SPRINGFIELD, MISSOURI FOR THE GRDA COAL PLANT - FLINT CREEK POWER PLANT – BROOKLINE – MORGAN 345 KILOVOLT INTERCONNECTION Point To Point On-going
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
58
UNITED STATES DEPARTMENT OF ENERGY SOUTHWESTERN POWER ADMINISTRATION POWER SALES CONTRACT between UNITED STATES OF AMERICA and BOARD OF PUBLIC UTILITIES OF THE CITY OF SPRINGFIELD, MISSOURI
City Utilities of Springfield, MO
Southwestern Power Administration Point To Point
6/30/2015(Will be extended) On-going
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
MISSOURI
59
GRDA Bulk Transmission Service Contract
Grand River Dam Authority
Oklahoma Municipal Power Authority
Grand River Dam Authority agrees to receive and deliver energy and power pursuant to Section of the Unit Power Sales Agreement.
Contract will terminate when Unit Power Sales Agreement is no longer in effect.
60
Public Service Company of Oklahoma Interconnection and Power Supply Agreement
Public Service Company of Oklahoma
Oklahoma Municipal Power Authority
Transmission interconnections.
Either party may terminate on the anniversary of this agreement having given the other party 6 years written notice of its intention to terminate.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
61 Oklahoma Gas and Electric Company
Oklahoma Gas and Electric Co
Oklahoma Municipal Power Authority
Firm transmission supporting an agreement by OMPA to purchase power from OGE.
Requires mutual agreement.
62 Transmission Service Contract
Ponca City Utility Authority
Oklahoma Municipal Power Authority
Ponca City Utility Authority agrees to receive power energy not to exceed the Interconnection Capacity.
May be terminated by either party after December 31, 2014, on any December 31st with a 5 year prior written notice to the other party.
63 SPA Transmission Service Contract
Southwestern Power Administration
Oklahoma Municipal Power Authority
Either party can terminate the contract provided they give 30 days notice to the other party.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
64
Oklaunion Unit No. 1 Transmission (OKTS) Service Schedule
Public Service Company of Oklahoma
Oklahoma Municipal Power Authority
Firm power transmission service from the SPP side of the North HVDC Interconnection.
65
SWEPCO Transmission Service Agreement
Southwestern Electric Power Co
Oklahoma Municipal Power Authority
Transmission of the power and energy from generating units.
Agreement in effect as long as Ownership Agreement in either generating unit remains in effect.
66
HVDC-TS Transmission Service Agreement
Public Service Co Oklahoma
Oklahoma Municipal Power Authority
Transmission of electric power at 60 Hertz, 3 phase, through the HVDC Tie.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
67 WFEC Transmission Service Agreement
Western Farmers Electric Cooperative
Oklahoma Municipal Power Authority
Long term firm transmission agreement allowing for delivery of power and energy from OMPA Network Resources to OMPA Network Load located in Western Farmers load control area Mutual Agreement.
68 WTU Transmission Service Agreement West Texas Utilities
Oklahoma Municipal Power Authority
Transmission for the unit capacity entitlement in Oklaunion Unit No. 1 to the south terminal of the Oklaunion HVDC Tie.
Cessation of Oklaunion Unit No. 1 in terms of ownership or abandon and retirement.
69
Coordination Transmission Service Agreement
Southwestern Electric Power Co and Public Service Co of Oklahoma
Oklahoma Municipal Power Authority Mutual Agreement.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
70
Hydro Peaking Power Purchase contract - BPU and EDE
Empire District Electric Company
Board of Public Utilities, Kansas City , KS Point To Point 3 years after written notice
71
Hydro Peaking Power Purchase contract - Higginsville and EDE
Empire District Electric Company Higginsville, MO Point To Point 3 years after written notice
72
Hydro Peaking Power Purchase contract - KMEA and EDE
Empire District Electric Company KMEA Point To Point 3 years after written notice
73
Hydro Peaking Power Purchase contract - Kaw Valley and EDE
Empire District Electric Company Kaw Valley Point To Point/NF 3 years after written notice
74
Hydro Peaking Power Purchase contract - KEPCO and EDE
Empire District Electric Company KEPCO Point To Point 5/31/2008 no rollover
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
75
Hydro Peaking Power Purchase contract - Coffeyville and EDE
Empire District Electric Company Coffeyville, KS Point To Point 3 years after written notice
76
Hydro Peaking Power Purchase contract - KMEA and EDE
Empire District Electric Company KMEA Point To Point 3 years after written notice
77 Service Schedule JP KGE and EDE Westar Energy
Empire District Electric Company
FERC Rate Schedule No. 273 Point To Point 5/31/2010
78 Electric Interchange Agreement - Iatan
Kansas City Power and Light
Empire District Electric Company Point To Point year to year
79
OMPA Transmission Service Agreement (TSA)
Oklahoma Gas and Electric Company
Oklahoma Municipal Power Authority
FERC Rate Schedule No. 121
Pre- Order 888 Transmission Service Agreement
36 Month written Notice prior to December 20, 2003
80 OMPA DLRA (Dispatch and Load
Oklahoma Gas and Electric Company
Oklahoma Municipal Power Authority
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
Regulation).
81 Paris Ark. OATT, SWPA customer
Oklahoma Gas and Electric Company
City of Paris, Southwestern Power Administration
FERC Electric Tariff, Second
Revised Volume No.2- OATT
NSA- SVC Agmnt #29, NOA- SVC
Agmnt # 30 OG&E OATT- Network SVC
The OATT Agreement listed is subject to OATT extension and termination provisions, There are no special provisions.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
82 Purcell Okla. OATT, SWPA customer
Oklahoma Gas and Electric Company
Purcell Public Works Authority, Southwestern Power Administration
FERC Electric Tariff, Second
Revised Volume No.2- OATT
NSA- SVC Agmnt #27, NOA- SVC
Agmnt # 28 OG&E OATT- Network SVC
The OATT Agreement listed is subject to OATT extension and termination provisions, There are no special provisions.
83
Southwest Power Administration (SWPA) OATT
Oklahoma Gas and Electric Company
Southwestern Power Administration
FERC Electric Tariff, Second
Revised Volume No.2- OATT NSA- SVC
Agmnt, NOA- SVC Agmnt
OG&E OATT- Network SVC
The OATT Agreement listed is subject to OATT extension and termination provisions, There are no special provisions.Current contract will terminate on 5/31/2014
84 Geary Okla. OATT Oklahoma Gas and Electric Company Geary Utilities Authority
FERC Electric Tariff, Second
Revised Volume No.2- OATT
NSA- SVC Agmnt #43, NOA- SVC
Agmnt #43-Sup.#1
OG&E OATT- Network SVC
The OATT Agreement listed is subject to OATT extension and termination provisions, There are no special provisions.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
85 Orlando Okla. OATT Oklahoma Gas and Electric Company
City of Orlando Public Works Authority
FERC Electric Tariff, Second
Revised Volume No.2- OATT
OG&E OATT- Network SVC
The OATT Agreement listed is subject to OATT extension and termination provisions, There are no special provisions.
86
OKLAHOMA GAS AND ELECTRIC COMPANY ELECTRIC SERVICE AGREEMENT (Wholesale for Resale)
Oklahoma Gas and Electric Company City of Watonga Okla.
FERC Electric Tariff 1st Revised
Volume No. 1 Rate Schedule
WM-1 Discounted Rate Option
Pre-Order 888- Full Requirements
24 month notice Given 2/16/99
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
87 City of Paris Ark Maple Street
Oklahoma Gas and Electric Company City of Paris
FERC Electric Tariff 1st Revised
Volume No. 1 Rate Schedule
WM-1
Pre-Order 888- Full Requirements 24 month notice
88
Mannford Okla. Public Works Authority
Oklahoma Gas and Electric Company City of Mannford
OG&E/KAMO Power Exchange
Agreement. FERC Rate
Schedule No. 125
Pre-Order 888- Full Requirements 12 month notice
89 KAMO Oklahoma Gas and Electric Company KAMO
FERC Electric Tariff 1st Revised
Volume No. 1 Rate Schedule
WC-1
Pre-Order 888- Full Requirements
30 month notice by either Party
90
Arkansas Valley Electric Cooperative (AVEC)
Oklahoma Gas and Electric Company AVEC
FERC Electric Tariff 1st Revised
Volume No. 1 Rate Schedule
WC-1
Pre-Order 888- Full Requirements
30 month notice after 12/1/2001
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
91
Agreement Between Public Service Company of Oklahoma and Oklahoma Gas and Electric Company
Oklahoma Gas and Electric Company
Public Service Company of Oklahoma (AEP) N/A
OG&E OATT- Network SVC
6 month notice after 6/30/1983
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
92
Agreement Between Southwestern Electric Power Company and Oklahoma Gas and Electric Company Providing for Allocation of Fixed Charges and Costs of Operation and Maintenance of the 66 kV Element of Oklahoma Gas and Electric Company's Van Buren Interconnection Substation Near Van Buren, Arkansas
Oklahoma Gas and Electric Company
Southwestern Electric Power Company (AEP) N/A
OG&E OATT- Network SVC
12 months after December 8 of the year notice given to cancel contract
93 Federal Southwestern Power Administration Augusta, AR
Pre-Order 888 Service With Redirect Rights Firm in nature None
94 Federal Southwestern Power Administration Arkansas Electric Co-op
Pre-Order 888 Service With Redirect Rights Firm in nature None
95 Federal Southwestern Power Administration Arkansas Electric Co-op
Pre-Order 888 Service With Redirect Rights Firm in nature None
96 Federal Southwestern Power Administration Arkansas Electric Co-op
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
97 Federal Arkansas Electric Co-op
Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
98 Federal Arkansas Electric Co-op
Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
99 Federal Southwestern Power Administration Arkansas Electric Co-op
Pre-Order 888 Service With Redirect Rights Firm in nature None
100 FederalSPA Pre-OATT Service
Arkansas Electric Co-opSouthwestern Power Administration
Southwestern Power AdministrationArkansas Electric Co-op
Pre-Order 888 Service With Redirect Rights Firm in nature
None Through 6/30/2020 with roll-over rights to SPP Tariff service
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
101 FederalSPA OATT NITSA
Arkansas Electric Co-opSouthwestern Power Administration
Southwestern Power AdministrationArkansas Electric Co-op
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 12/31/2020 with roll-over rights to SPP Tariff service
102 Federal Southwestern Power Administration Associated Electric
Pre-Order 888 Service With Redirect Rights Firm in nature None
103 Federal Associated Electric Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
104 Federal Southwestern Power Administration Associated Electric
Pre-Order 888 Service With Redirect Rights Firm in nature None
105 Federal Associated Electric Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
106 FederalSPA OATT NITSA
Southwestern Power Administration Associated Electric
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 5/31/2020 with roll-over rights to SPP Tariff service
107 FederalSPA Pre-OATT Service
AEP/West Southwestern Power Administration
Southwestern Power Administration Public Service Company of Oklahoma SPA-214
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 6/30/2020 with roll-over rights to SPP Tariff service
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
108 FederalSPA Pre-OATT Service
Southwestern Power Administration Associated Electric
Rate Sch NFTS-98D
Pre-Order 888 Service With Redirect Rights Firm in nature
None Through 2/29/2016. To be converted to Interconnection Facilities Service pursuant to Attachment AD thereafter.
109 Federal Southwestern Power Administration
AEP/WestPublic Service Company of Oklahoma
Pre-Order 888 Service With Redirect Rights Firm in nature None
110 Federal Southwestern Power Administration Anthony, KS
Pre-Order 888 Service With Redirect Rights Firm in nature None
111 Federal Southwestern Power Administration Beauregard
Pre-Order 888 Service With Redirect Rights Firm in nature None
112 Federal Southwestern Power Administration Bentonville, AR
Pre-Order 888 Service With Redirect Rights Firm in nature None
113 Federal Southwestern Power Administration Brazos
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
114 Federal Southwestern Power Administration Brazos
Pre-Order 888 Service With Redirect Rights Firm in nature None
115 Federal Southwestern Power Administration Carthage, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
116 FederalSPA Pre-OATT Service
Southwestern Power Administration Carthage, MO Car-409
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 6/30/2030 with roll-over rights to SPP Tariff service
117 Federal Carthage, MO Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
118 FederalSPA Pre-OATT Service
Southwestern Power Administration Sikeston, MO
Pre-Order 888 Service With Redirect Rights Firm in nature
None Through 6/30/2015. To be converted to Interconnection Facilities Service pursuant to Attachment AD thereafter.
119 Federal Southwestern Power Administration Fulton, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
120 Federal Southwestern Power Administration Claiborne
Pre-Order 888 Service With Redirect Rights Firm in nature None
121 Federal Southwestern Power Administration Clarksville, AR
Pre-Order 888 Service With Redirect Rights Firm in nature None
122 FederalSPA Pre-OATT Service
Southwestern Power Administration Clarksville, AR
Rate Sch NFTS-98D
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 5/31/2020 with roll-over rights to SPP Tariff service
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
123 Federal Southwestern Power Administration Coffeyville, KS
Pre-Order 888 Service With Redirect Rights Firm in nature None
124 Federal Southwestern Power Administration Comanche, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
125 Federal Southwestern Power Administration Concordia
Pre-Order 888 Service With Redirect Rights Firm in nature None
126 Federal Southwestern Power Administration Copan, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
127 Federal Southwestern Power Administration Dixie Electric
Pre-Order 888 Service With Redirect Rights Firm in nature None
128 Federal Southwestern Power Administration DOD - McAlester
Pre-Order 888 Service With Redirect Rights Firm in nature None
129 Federal Southwestern Power Administration Duncan, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
130 Federal Southwestern Power Administration Eldorado, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
131 Federal Empire District Electric Company
Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
132 Federal Southwestern Power Administration
Empire District Electric Company
Pre-Order 888 Service With Redirect Rights Firm in nature None
133 Federal ES Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
134 FederalSPA Pre-OATT Service
Southwestern Power Administration ES
Rate Sch NFTS-98D
Pre-Order 888 Service With Redirect Rights Firm in nature
None Through 6/30/2020. To be converted to Interconnection Facilities Service pursuant to Attachment AD thereafter.
135 Federal Southwestern Power Administration Fort Sill, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
136 Federal Southwestern Power Administration Goltry, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
137 Federal Southwestern Power Administration Granite, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
138 Federal Grand River Dam Authority
Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
139 Federal Southwestern Power Administration
Grand River Dam Authority
Pre-Order 888 Service With Redirect Rights Firm in nature None
140 Federal Grand River Dam Authority
Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
141 Federal Southwestern Power Administration
Grand River Dam Authority
Pre-Order 888 Service With Redirect Rights Firm in nature None
142 FederalSPA Pre-OATT Service
Southwestern Power Administration
Grand River Dam Authority
Rate Sch NFTS-98D
Pre-Order 888 Service With Redirect Rights Firm in nature
None Through 6/30/2020. To be converted to Interconnection Facilities Service pursuant to Attachment AD thereafter.
143 FederalSPA Pre-OATT Service
Southwestern Power Administration
Grand River Dam AuthorityAssociated Electric
Rate Sch NFTS-98D
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 6/30/2020. To be converted to Interconnection Facilities Service pursuant to Attachment AD thereafter
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
144 FederalSPA Pre-OATT Service
Southwestern Power Administration
Grand River Dam AuthorityAssociated Electric
Rate Sch NFTS-98D
Pre-Order 888 Service With Redirect Rights Firm in nature
None Through 6/30/2020. To be converted to Interconnection Facilities Service pursuant to Attachment AD thereafter.
145 Federal Southwestern Power Administration Hermann, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
146 Federal Southwestern Power Administration Higginsville, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
147 Federal Southwestern Power Administration Hominy, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
148 Federal Southwestern Power Administration Jackson, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
149 Federal Southwestern Power Administration Jefferson Davis
Pre-Order 888 Service With Redirect Rights Firm in nature None
150 Federal Southwestern Power Administration Jonesboro, AR
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
151 Federal Southwestern Power Administration Jonesboro, AR
Pre-Order 888 Service With Redirect Rights Firm in nature None
152 Federal Jonesboro, AR Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
153 Federal Southwestern Power Administration Kansas City, KS
Pre-Order 888 Service With Redirect Rights Firm in nature None
154 Federal Southwestern Power Administration Kaw Valley
Pre-Order 888 Service With Redirect Rights Firm in nature None
155 Federal Southwestern Power Administration Kennett, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
156 Federal Southwestern Power Administration Kennett, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
157 Federal Kennett, MO Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
158 Federal Southwestern Power Administration Kennett, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
159 Federal Southwestern Power Administration Kennett, MO Ken-286
Pre-Order 888 Service With Redirect Rights Firm in nature None
160 Federal Southwestern Power Administration KEPCO
Pre-Order 888 Service With Redirect Rights Firm in nature None
161 Federal Southwestern Power Administration KMEA
Pre-Order 888 Service With Redirect Rights Firm in nature None
162 Federal Southwestern Power Administration Lafayette, LA
Pre-Order 888 Service With Redirect Rights Firm in nature None
163 Federal Southwestern Power Administration Lamar, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
164 Federal Southwestern Power Administration
Louisiana Energy and Power Authority
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
165 Federal Southwestern Power Administration Lexington, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
166 Federal Southwestern Power Administration Malden, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
167 Federal Southwestern Power Administration Malden, MO Mal-238
Pre-Order 888 Service With Redirect Rights Firm in nature None
168 Federal Malden, MO Southwestern Power Administration
Rate Sch NFTS-98D
Pre-Order 888 Service With Redirect Rights Firm in nature None
169 Federal Southwestern Power Administration Malden, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
170 Federal Malden, MO Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
171 FederalSPA Pre-OATT Service
Southwestern Power Administration Malden, MO
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 5/31/2020 with roll-over rights to SPP Tariff service
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
172 Federal Southwestern Power Administration Manitou, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
173 Federal Southwestern Power Administration Minden, LA
Pre-Order 888 Service With Redirect Rights Firm in nature None
174 Federal Southwestern Power Administration Natchitoches, LA
Pre-Order 888 Service With Redirect Rights Firm in nature None
175 Federal Southwestern Power Administration Nemaha-Marshall
Pre-Order 888 Service With Redirect Rights Firm in nature None
176 Federal Southwestern Power Administration New Madrid, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
177 FederalSPA Pre-OATT Service
Southwestern Power Administration New Madrid, MO
Rate Sch NFTS-98D
Pre-Order 888 Service With Redirect Rights Firm in nature
None Through 6/30/2022 with roll-over rights to SPP Tariff service
178 Federal Southwestern Power Administration Nixa, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
179 FederalSPA Pre-OATT Service
Southwestern Power Administration Nixa, MO
Rate Sch NFTS-98D
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 6/30/2015 with roll-over rights to SPP Tariff service
180 Federal Southwestern Power Administration Northeast Louisiana
Pre-Order 888 Service With Redirect Rights Firm in nature None
181 Federal Southwestern Power Administration
Northeast Texas Electric Cooperative
Pre-Order 888 Service With Redirect Rights Firm in nature None
182 Federal Southwestern Power Administration
Northeast Texas Electric Cooperative
Pre-Order 888 Service With Redirect Rights Firm in nature None
183 Federal Southwestern Power Administration
Northeast Texas Electric Cooperative NTEC-265
Pre-Order 888 Service With Redirect Rights Firm in nature None
184 Federal Northeast Texas Electric Cooperative
Southwestern Power Administration NTEC-265
Pre-Order 888 Service With Redirect Rights Firm in nature None
185 Federal Southwestern Power Administration
Oklahoma Gas and Electric Company
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
186 Federal Oklahoma Gas and Electric Company
Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
187 Federal Southwestern Power Administration Olustee, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
188 Federal Southwestern Power Administration Paragould, AR
Pre-Order 888 Service With Redirect Rights Firm in nature None
189 FederalSPA Pre-OATT Service
Southwestern Power Administration Paragould, AR
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 6/30/2038 with roll-over rights to SPP Tariff service
190 Federal Southwestern Power Administration Paragould, ARs
Pre-Order 888 Service With Redirect Rights Firm in nature None
191 Federal Paragould, AR Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
192 Federal Southwestern Power Administration Paris, AR
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
193 FederalSPA Pre-OATT Service
Southwestern Power Administration People's
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 12/31/2022 with roll-over rights to SPP Tariff service
194 FederalSPA Pre-OATT Service
Southwestern Power Administration People's
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 12/31/2019 with roll-over rights to SPP Tariff service
195 Federal Southwestern Power Administration Piggott, AR Pig-288
Pre-Order 888 Service With Redirect Rights Firm in nature None
196 FederalSPA Pre-OATT Service
Southwestern Power Administration Piggott, AR
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 6/30/2020 with roll-over rights to SPP Tariff service
197 Federal Southwestern Power Administration Piggott, AR
Pre-Order 888 Service With Redirect Rights Firm in nature None
198 Federal Piggott, AR Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
199 Federal Southwestern Power Administration Piggott, AR
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
200 Federal
Southwestern Power AdministrationPiggott, AR
Piggott, ARSouthwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
201 Federal Southwestern Power Administration Pointe Coupee
Pre-Order 888 Service With Redirect Rights Firm in nature None
202 Federal Southwestern Power Administration Poplar Bluff, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
203 Federal Southwestern Power Administration Poplar Bluff, MO Pop-251
Pre-Order 888 Service With Redirect Rights Firm in nature None
204 Federal Poplar Bluff, MO Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
205 FederalSPA Pre-OATT Service
Southwestern Power Administration Poplar Bluff, MO
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 6/30/2039 with roll-over rights to SPP Tariff service
206 Federal Southwestern Power Administration Purcell, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
207 Federal Southwestern Power Administration Rayburn Country
Pre-Order 888 Service With Redirect Rights Firm in nature None
208 Federal Southwestern Power Administration Ryan, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
209 Federal Southwestern Power Administration Sam Rayburn Dam EC SRDEC-215
Pre-Order 888 Service With Redirect Rights Firm in nature None
210 Federal Southwestern Power Administration Sam Rayburn MPA SRDEC-215
Pre-Order 888 Service With Redirect Rights Firm in nature None
211 Federal Southwestern Power Administration Sikeston, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
212 Federal Southwestern Power Administration Sikeston, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
213 Federal
Southwestern Power AdministrationSikeston, MO
Sikeston, MOSouthwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
214 FederalSPA Pre-OATT Service
Southwestern Power Administration Sikeston, MO
Pre-Order 888 Service With Redirect Rights Firm in nature
None Through 6/30/2015. To be converted to Interconnection Facilities Service pursuant to Attachment AD thereafter.
215 Federal Southwestern Power Administration Skiatook, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
216 Federal Southwestern Power Administration South Louisiana
Pre-Order 888 Service With Redirect Rights Firm in nature None
217 Federal Southwestern Power Administration Southwest Louisiana
Pre-Order 888 Service With Redirect Rights Firm in nature None
218 Federal Southwestern Power Administration Spiro, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
219 Federal Southwestern Power Administration Springfield, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
220 Federal Southwestern Power Administration Springfield, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
221 Federal Springfield, MO Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
222 Federal Southwestern Power Administration
Tex-La & Rayburn Country Tes-La/Ray-435
Pre-Order 888 Service With Redirect Rights Firm in nature None
223 Federal Southwestern Power Administration Tex-La of Texas Tex-La-327
Pre-Order 888 Service With Redirect Rights Firm in nature None
224 Federal Southwestern Power Administration Thayer, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
225 Federal Southwestern Power Administration Valley
Pre-Order 888 Service With Redirect Rights Firm in nature None
226 Federal Southwestern Power Administration
Vance Air Force Base, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
227 Federal Southwestern Power Administration Walters, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
228 Federal Southwestern Power Administration WAPA
Pre-Order 888 Service With Redirect Rights Firm in nature None
229 Federal WAPA Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
230 Federal Southwestern Power Administration Washington-St Tammany
Pre-Order 888 Service With Redirect Rights Firm in nature None
231 Federal Southwestern Power Administration West Plains, MO
Pre-Order 888 Service With Redirect Rights Firm in nature None
232 Federal Southwestern Power Administration Wetumka, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
233 Federal Southwestern Power Administration
Western Farmers Electric Cooperative
Pre-Order 888 Service With Redirect Rights Firm in nature None
234 Federal Western Farmers Electric Company
Southwestern Power Administration
Pre-Order 888 Service With Redirect Rights Firm in nature None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
235 Federal Southwestern Power Administration
Western Farmers Electric Cooperative
Pre-Order 888 Service With Redirect Rights Firm in nature None
236 FederalSPA Pre-OATT Service
Southwestern Power Administration
Western Farmers Electric Cooperative
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 5/31/2020 with roll-over rights to SPP Tariff service
237 FederalSPA Pre-OATT Service
Southwestern Power Administration
Western Farmers Electric Cooperative
Pre-Order 888 Service With Redirect Rights Firm in nature
NoneThrough 5/31/2020 with roll-over rights to SPP Tariff service
238 Federal Southwestern Power Administration
Western Farmers Electric Cooperative
Pre-Order 888 Service With Redirect Rights Firm in nature None
239 Federal Southwestern Power Administration Yale, OK
Pre-Order 888 Service With Redirect Rights Firm in nature None
240
Amended Interchange Agreement for the Missouri-Kansas-Oklahoma 345 kV Interconnection
Kansas Gas and Electric
Associated Electric Cooperative Inc., Public Service Company of Oklahoma, Ameren-U.E
FERC rate schedule PSO-186, UE-79, KGE-130 Interconnection 4 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
241
Agreement for Wholesale Electric Service Westar Energy City of Altamount, Kansas
FERC rate schedule 225
dockets ER85-210, ER92-357,
ER92-692, EL94-34, OA96-100
Full requirements wholesale power supply agreement 3/27/2005
242
Agreement for Wholesale Electric Service
Kansas Gas and Electric City of Arcadia
FERC rate schedule 178
dockets ER88-120, ER92-508,
OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
243
Agreement for Wholesale Electric Service
Kansas Gas and Electric City of Arma, Kansas
FERC rate schedule 168
dockets ER88-120, ER92-508,
OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
244
Generating Municipal Electric Service Agreement
Kansas Gas and Electric City of Augusta, Kansas
FERC rate schedule 134
dockets E-8938, E-9485, ER77-578, ER80-259,
ER83-628, ER85-521, ER92-508,
ER92-733, ER97-1200, ER97-4028
Partial requirements wholesale power supply agreement None currently but contract provides for firm transmission service if requested and available
On-Going 30 months prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
245
Agreement for Wholesale Electric Service Westar Energy City of Axtell, Kansas
FERC rate schedule 227
dockets ER85-430, ER99-24,
ER92-357, ER92-692, EL94-34,
OA96-100
Full requirements wholesale power supply agreement 7/1/2010
246
Agreement for Wholesale Electric Service
Kansas Gas and Electric
City of Blue Mound, Kansas
FERC rate schedule 171
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
247
Agreement for Wholesale Electric Service
Kansas Gas and Electric City of Bronson, Kansas
FERC rate schedule 174
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
248
Generating Municipal Electric Service Agreement Westar Energy
City of Burlingame, Kansas
FERC rate schedule 250
dockets ER88-307, ER89-455,
ER92-357, ER97-1143, ER92-696, EL94-34, OA96-100, ER97-1143,
ER00-2502
Partial requirements wholesale power agreement
5/31/07 & then year to year 2 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
249
Generating Municipal Electric Service Agreement
Kansas Gas and Electric City of Burlington, Kansas
FERC rate schedule 193
dockets ER96-1468, ER00-617
Partial requirements wholesale power supply agreement None currently but contract provides for firm transmission service if requested and available
5/31/04 & then year to year 3 yr prior notice
250 Firm Transmission Service Agreement
Kansas Gas and Electric City of Burlington, Kansas
Service Agreement No. 7 under Western
Resources’ FERC Electric Tariff
Original Vol. No. 1 dockets ER96-
1468
Long-term firm transmission service to support purchase of participation power from Western Resources
5/31/04 Letter from city to continue service until 5/31/04 dated 3/20/98. City had to give 2 yrs. notice for the continuance.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
251
Wholesale Municipal Electric Service Agreement Westar Energy City of Centralia, Kansas
FERC rate schedule 248
dockets ER88-249, ER88-24,
ER92-357, ER92-692, EL94-34,
OA96-100
Full requirements wholesale power supply agreement 5/1/2008
252
Generating Municipal Electric Service Agreement
Kansas Gas and Electric City of Chanute, Kansas
FERC rate schedule 194
dockets ER96-587
Partial requirements wholesale power supply agreement None currently but contract provides for firm transmission service if requested and available
12/31/09 & then year to year 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
253 Firm Transmission Service Agreement Westar Energy City of Chanute, Kansas
Service Agreement No. 8 under Western
Resources’ FERC Electric Tariff,
Original Vol. No. 1 dockets ER96-587, ER96-2701
Long-term firm service agreement for 12.0 MW participation power purchased from Western Resources and 1.6 MW preference power purchased from Southwest Power Administration 12/31/2009
254
Wholesale Municipal Electric Service Agreement Westar Energy City of Chapman, Kansas
FERC rate schedule 231
dockets ER86-17, ER88-24, ER92-357, ER92-692, EL94-34, OA96-
100
Full requirements wholesale power supply agreement 11/1/2005
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
255
Generating Municipal Electric Service Agreement Westar Energy
City of Clay Center, Kansas
FERC rate schedule 241
dockets ER87-441, ER88-24,
ER89-455, ER92-357, ER92-696,
ER94-991, EL94-34, OA96-100,
ER00-2502
Partial requirements wholesale power agreement
4/21/07 & then year to year 2 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
256
Agreement for Wholesale Electric Service
Kansas Gas and Electric City of Elsmore, Kansas
FERC rate schedule 170
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
257
Wholesale Municipal Electric Service Agreement Westar Energy City of Elwood, Kansas
FERC rate schedule 253
dockets ER88-471, ER88-24,
ER92-357, ER92-692, EL94-34,
OA96-100
Full requirements wholesale power supply agreement 8/1/2008
258
Wholesale Municipal Electric Service Agreement Westar Energy City of Enterprise, Kansas
FERC rate schedule 270
dockets ER85-734, ER88-24,
ER92-357, ER92-692, EL94-34,
OA96-100
Full requirements wholesale power supply agreement 9/25/2005
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
259
Wholesale Municipal Electric Service Agreement Westar Energy City of Eudora, Kansas
FERC rate schedule 236
dockets ER86-553, ER88-24,
ER92-357, ER92-377, ER93-528,
ER92-692, EL94-34, OA96-100
Full requirements wholesale power supply agreement 6/1/2013
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
260 Transmission Service Agreement Westar Energy City of Fredonia, Kansas
FERC rate schedule Service Agreement No.
129 under Western
Resources’ FERC Electric Tariff,
2nd Rev. Vol. No. 5 dockets ER99-
3021
Long-term firm service agreement to support purchase of Nearman power from Kansas City Board of Public Utilities 5/31/2022
261
Generating Municipal Electric Service Agreement
Kansas Gas and Electric City of Girard, Kansas
FERC rate schedule 182
dockets ER92-211, ER92-508,
ER92-828, ER92-655, ER93-231,
ER93-430, ER93-653, ER94-47, ER96-2407,
OA96-100, ER97-4028
Partial requirements wholesale power supply agreement None currently but contract provides for firm transmission service if requested and available
2/1/07 & then On-Going 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
262
Agreement for Wholesale Electric Service
Kansas Gas and Electric City of Haven, Kansas
FERC rate schedule 176
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
263
Generating Municipal Electric Service Agreement Westar Energy City of Herington, Kansas
FERC rate schedule 209
dockets ER83-37, ER88-24, ER89-455, ER92-357,
ER92-696, ER94-955, EL94-34,
OA96-100, ER00-2502
Partial requirement wholesale power agreement
3/2/12 2 yr prior notice
264
Wholesale Municipal Electric Service Agreement Westar Energy City of Hillsboro, Kansas
FERC rate schedule 234
dockets ER86-404, ER88-24,
ER92-357, ER93-934, EL94-34,
OA96-100
Full requirements wholesale power supply agreement 5/31/2007
265
Generating Municipal Electric Service Agreement Westar Energy City of Holton, Kansas
FERC rate schedule 226
dockets ER85-377, ER88-24,
ER89-455, ER92-357, ER92-696, EL94-34, OA96-100, ER97-1127,
ER00-2502
Partial requirements wholesale power supply agreement
6/1/05 & then year to year 2 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
266
Generating Municipal Electric Service Agreement Westar Energy City of Horton, Kansas
FERC rate schedule 261
dockets ER93-449, EL94-34,
OA96-100, ER00-2502
Partial requirements wholesale power supply agreement
Year to Year 3 yr prior notice
267
Agreement for Wholesale Electric Service
Kansas Gas and Electric City of LaHarpe, Kansas
FERC rate schedule 169
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
268
Generating Municipal Electric Service Agreement Westar Energy City of Lindsborg, Kansas
FERC rate schedule 280
dockets ER89-659, ER92-357, EL94-34, OA96-100, ER00-844
Partial requirements wholesale power supply agreement
5/31/10 & then year to year 5 yr prior notice
269
Wholesale Municipal Electric Service Agreement Westar Energy City of Marion, Kansas
FERC rate schedule 228
dockets ER85-523, ER88-24,
ER92-357, ER92-692, EL94-34,
OA96-100
Full requirements wholesale power supply agreement 7/1/2005
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
270
Electric Interconnection Agreement Westar Energy
City of McPherson, Kansas
FERC rate schedule 127
dockets E-7893, ER78-196, ER78-626, ER80-527,
ER83-616, ER92-379
Long-term firm service agreement
5/31/27 & then year to year 3 yr prior notice 5/31/2039 & then year to year, (5) years prior written notice.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
271
Agreement for Wholesale Electric Service
Kansas Gas and Electric
City of Mindenmines, Missouri
FERC rate schedule 179
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
272
Generating Municipal Electric Service Agreement Westar Energy
City of Minneapolis, Kansas
FERC rate schedule 211
dockets ER83-462, ER83-418, ER88-24, ER89-455, ER92-357,
ER92-696, EL94-34, OA96-100,
ER97-2377, ER00-2502
Partial Requirements Wholesale Power Supply Agreement
Year to Year 2 yr prior notice
273
Agreement for Wholesale Electric Service
Kansas Gas and Electric City of Moran, Kansas
FERC rate schedule 172
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
274
Wholesale Municipal Electric Service Agreement Westar Energy City of Morrill, Kansas
FERC rate schedule 260
dockets ER90-382, ER92-357, EL94-34, OA96-100, ER99-3856
Full requirements wholesale power supply agreement 5/31/2005
275
Agreement for Wholesale Electric Service
Kansas Gas and Electric
City of Mount Hope, Kansas
FERC rate schedule 177
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
2/1/08 & then on-going 3 yr prior notice
276
Agreement for Wholesale Electric Service
Kansas Gas and Electric City of Mulberry, Kansas
FERC rate schedule 173
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
277
Service Agreement for Long Term Firm Point-To-Point Westar Energy City of Mulvane, Kansas
FERC rate schedule Service Agreement No.
125 under Western
Resources’ FERC Electric Tariff,
2nd Rev. Vol. No. 5 dockets ER99-
2457
Long-term firm service agreement to support purchase of Nearman power from Kansas City Board of Public Utilities 5/31/2022
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
278
Generating Municipal Electric Service Agreement
Kansas Gas and Electric City of Mulvane, Kansas
FERC rate schedule 195
dockets ER96-587, OA96-100
Partial requirements wholesale power supply agreement None currently but contract provides for firm transmission service if requested and available
Year to Year 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
279 Firm Transmission Service Agreement Westar Energy City of Mulvane, Kansas
FERC rate schedule Service Agreement No. 3 under Western
Resources’ FERC Electric Tariff,
Original Vol. No. 1 dockets ER94-1286, ER96-587,
ER96-2701, ER97-3528.
Moved to OATT Vol. 5
Long-term firm service agreement to support purchase of preference power from Southwest Power Administration
The term has been interpreted under Sections 205 and 206 of the Federal Power Act
280
Wholesale Municipal Electric Service Agreement Westar Energy City of Muscotah, Kansas
FERC rate schedule 222
dockets ER85-169, ER88-24,
ER92-357, ER92-692, EL94-34,
OA96-100
Full requirements bundled wholesale service 1/3/2005
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
281
Long Term Firm Point-To-Point Transmission Service Westar Energy City of Neodesha, Kansas
FERC rate schedule Service Agreement No.
130 under Western
Resources’ FERC Electric Tariff,
2nd Rev. Vol. No. 5 ER99-3021
Long-term firm service agreement to support purchase of Nearman power from Kansas City Board of Public Utilities 5/31/2022
282
Generating Municipal Electric Service Agreement
Kansas Gas and Electric City of Neodesha, Kansas
FERC rate schedule 196
dockets ER96-587, OA96-100
Partial requirements wholesale power supply agreement None currently but contract provides for firm transmission service if requested and available
Year to Year 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
283
Long Term Firm Point-To-Point Transmission Service Westar Energy City of Neodesha, Kansas
FERC rate schedule Service Agreement No. 4 under Western
Resources’ FERC Electric Tariff,
Original Vol. No. 1 ER94-1286,
ER93-523, ER95-825, ER96-587,
ER96-2701, ER97-3528.
Moved to OATT Vol. 5
Long-term firm service agreement to support purchase of preference power from Southwest Power Administration
The term has been interpreted under Sections 205 & 206 of the Federal Power Act.
284
Generating Municipal Electric Service Agreement Westar Energy
City of Osage City, Kansas
FERC rate schedule 249
dockets ER88-306, ER89-455,
ER92-357, ER92-696, ER93-537, EL94-34, OA96-100, ER00-2501,
ER00-2502
Partial requirement wholesale power supply agreement
6/1/08 & then year to year 2 yr prior notice
285
Wholesale Municipal Electric Service Agreement Westar Energy City of Robinson, Kansas
dockets ER86-231, ER88-24,
ER92-357, ER92-692, EL94-34,
OA96-100
Full requirements bundled wholesale service 4/1/2006
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
286
Generating Municipal Electric Service Agreement Westar Energy City of Sabetha, Kansas
dockets ER86-412, ER88-24,
ER89-455, ER92-357, ER92-696, EL94-34, ER96-1467, OA96-100,
ER00-2502
Partial requirements wholesale power supply agreement
6/1/07 & then year to year 2 yr prior notice
287
Agreement for Wholesale Electric Service
Kansas Gas and Electric
City of Savonburg, Kansas
dockets ER88-120, ER92-508,
ER92-732, OA96-100
Full requirements wholesale power supply agreement
On-Going 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
288
Wholesale Municipal Electric Service Agreement Westar Energy City of St. Marys, Kansas
dockets ER87-666, ER88-24,
ER92-357 ER92-692, EL94-34,
OA96-100
Full requirements bundled wholesale service 11/1/2007
289
Wholesale Municipal Electric Service Agreement Westar Energy City of Toronto, Kansas
dockets ER90-188, ER92-357, EL94-34, OA96-
100
Full requirements bundled wholesale service 3/14/2010
290
Wholesale Municipal Electric Service Agreement Westar Energy City of Troy, Kansas
dockets ER88-393, ER92-357,
ER94-308, EL94-34, OA96-100
Full requirements bundled wholesale service 5/31/2004
291
Wholesale Municipal Electric Service Agreement Westar Energy City of Vermillion, Kansas
dockets ER88-116, ER88-24,
ER92-357, ER92-692, EL94-34,
OA96-100
Full requirements bundled wholesale service 2/1/2008
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
292
Generating Municipal Electric Service Agreement Westar Energy City of Wamego, Kansas
dockets ER86-595, ER88-24,
ER89-455, ER92-357, ER93-504, EL94-34, OA96-100, ER00-2501,
ER00-2502
Partial requirements wholesale power supply agreement
6/30/12 & then year to year 2 yr prior notice
293
Generating Municipal Electric Service Agreement
Kansas Gas and Electric
City of Wellington, Kansas
dockets ER96-587
Partial requirements wholesale power supply agreement None currently but contract provides for firm transmission service if requested and available
Year to Year 3 yr prior notice
294 Firm Transmission Service Agreement Westar Energy
City of Wellington, Kansas
Service Agreement No. 9 under Western
Resources’ FERC Electric Tariff,
Original Vol. No. 1 dockets ER96-587, ER96-2701
Long-term firm service agreement to support purchased preference power from Southwest Power Administration 6/30/2002
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
295
Long Term Point-To-Point Transmission Service Westar Energy City of Winfield, Kansas
Service Agreement No.
126 under Western
Resources’ FERC Electric Tariff 1st Rev. Vol. No. 5
Long-term Firm service agreement to support Winfield customers located outside of Winfield 4/30/2009
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
296
Generating Municipal Electric Service Agreement
Kansas Gas and Electric City of Winfield, Kansas
198 dockets ER96-
587
Partial requirements wholesale power supply agreement None currently but contract provides for firm transmission service if requested and available
Year to Year 3 yr prior notice
297
Long Term Point-To-Point Transmission Service Westar Energy City of Winfield, Kansas
Service Agreement No. 5 under Western
Resources’ FERC Electric Tariff,
Original Vol. No. 1 dockets ER94-1286, ER96-587
Long-term firm service agreement to support purchase of 1.6 MW preference power from Southwest Power Administration and 12.5 MW Nearman power from Kansas City Board of Public Utilities 2/28/2003
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
298 Participation Power Agreement Westar Energy
Empire District Electric Company
FERC rate schedule 273
dockets ER95-615
Participation Power Agreement 5/31/2010
299
Agreement Respecting Certain Eastern Kansas Transmission Installations
Kansas Gas and Electric
Empire District Electric Company
Line lease agreement 3 yr prior notice
300
Agreement for Interchange of Power and Interconnected Operation
Kansas Gas and Electric
Empire District Electric Company
FERC rate schedule EDE-
69, KGE-83 Interchange On-Going 3 yr prior notice
301
Agreement for Interchange of Power and Interconnected Operation -Service Schedule SP
Kansas Gas and Electric
Empire District Electric Company
FERC rate schedule
Supplement No. 22 to 83 ER94-
1010
Long-term firm service agreement
Early termination permitted depending on continuous availability of certain base load generating units
302 Lease Agreement Kansas Gas and Electric
Kansas City Power and Light
FERC rate schedule KGE-
160 dockets ER85-386
Line lease; Wolf Creek to LaCygne 345 kV
Year to Year 2 yr prior notice
303 Electric Interchange Agreement Westar Energy
Kansas City Power and Light
FERC rate schedule KCPL-
55, Western Resources-83 Interchange
5/31 of any year 36 months prior notice
304 Interchange Agreement
Kansas Gas and Electric
Kansas City Power and Light
FERC rate schedule KCPL-
34, KGE-99 Interchange 5/31 of any year 42 months prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
305 MOKAN Coordination Agreement Westar Energy
Kansas City Power and Light Kansas Gas and Electric Company, Utilicorp-MPS
FERC rate schedule KGE-186, KCPL-110,
MPS-95, Western Resources-266
This Agreement shall continue in full force and effect during the term of the General Participation Agreement and shall, as supplement thereto, terminate concurrently, therewith.
306 Border Customer Agreement Westar Energy BPU-Kansas City, KS
Service to border customers
307
Electrical Interconnection Agreement Westar Energy BPU-Kansas City, KS
FERC rate schedule Western
Resources-272 dockets ER94-
125 Interconnection 4/26/06 and then year to year 10 yr prior notice
308
Electric Power, Transmission and Service Contract Westar Energy
Kansas Electric Power Cooperative
FERC rate schedule 264
dockets ER93-683, ER94-969,
ER94-1116, ER95-841,ER96-1371, ER97-168,
ER97-2154, ER98-2173, ER98-2389, ER98-2907, ER99-3026, ER99-3418,
ER00-406, ER00-545, ER00-2572
Network Transmission Agreement
This contract shall terminate upon 6 years written notice given by either Party to the other; provided that the Contract shall not be terminated prior to December 31 of the calendar year Wolf Creek Generating Station 1 (WCGS-1) ceases commercial operation, or December 31, 2001, whichever is later
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
309
Electric Power, Transmission and Service Contract
Kansas Gas and Electric
Kansas Electric Power Cooperative, Inc
FERC rate schedule 183
dockets ER93-683, ER94-969,
ER94-1116, ER95-841, ER96-1371, ER97-168,
ER97-2154, ER98-2173, ER98-2389, ER98-2907, ER99-3026, ER99-3418,
ER00-406, ER00-545, ER00-2572
Partial Requirements Wholesale Power Supply Agreement
This contract terminates on May 31, 2003 if KEPCo has opted to convert its transmission service to a regional Open Access Transmission Tariff; otherwise, it shall terminate upon 6 years written notice given by either Party to the other; provided that the Contract shall not be terminated prior to December 31 of the calendar year Wolf Creek Generating Station 1 (WCGS-1) ceases commercial operation, or December 31, 2001, whichever is later.
310
Electric Interconnect Contract – Schedule M Westar Energy Kansas Gas and Electric
Supplement No. 15 to No. 93
ER83-527 with 32 subsequent
dockets Interconnection 2 yr prior notice
311
Jeffrey Energy Center Transmission Agreement Westar Energy Kansas Gas and Electric
254 dockets ER89-485, ER90-235,
ER90-300, ER90-478, ER90-500, ER92-29, ER92-239, ER96-1728,
ER96-1728 Interconnection
This agreement supports the Joint Ownership of the Jeffrey Energy Center Terminates upon the retirement of the last generating unit in which KGE has an ownership share at the Jeffrey Energy Center or upon the transfer of any or all of KGE’s interest in the Jeffrey Energy Center pursuant to the ownership agreement,
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions whichever comes first
312
Electric Interconnection Contract Westar Energy Kansas Gas and Electric
FERC rate schedule KGE-
93, Western Resources-6
Interconnection Burton & Peabody
Year to Year 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
313 Interconnection Agreement Westar Energy Kansas Gas and Electric
FERC rate schedule KGE-
25, Western Resources-9 Interconnection
On-Going 6 months prior notice
314 Transmission Service Agreement Westar Energy Midwest Energy, Inc
FERC rate schedule 265
dockets ER93-849, OA96-100
Long-term firm service agreement 60.5 MW @ POR, 60.0 MW @ POD
5/31/2008 extends until canceled. Trans Svc Agrmt Ex. A - extended under the provisions of Section 6 Paragraph 6.2 of MWE RS No. 184 - thru 09/30/2013 or approval of CBFR.)
315
Electric Interconnection Contract – Service Schedule P Westar Energy Midwest Energy, Inc
FERC rate schedule
Supplement No. 21 to 123 dockets
ER91-357
long term firm service agreement
Year to Year 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
316
Agreement for Wholesale Electric Service
Kansas Gas and Electric
Missouri Public Service Company
FERC rate schedule 152
dockets ER81-519, ER82-519,
ER85-521, ER92-508, OA96-100
Full requirements wholesale power supply agreement for ultimate delivery to the cities of Eve, Missouri and Richards, Missouri
Year to Year 90 days not less than 60 days prior notice
317
Electric Interconnection and Interchange Agreement Westar Energy
Nebraska Public Power District
FERC rate schedule not
assigned or filed
Interconnection has not been established
5/1/14 4 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
318
Wholesale Contract Service - Rural Electric Coop. Westar Energy
Doniphan Electric Cooperative Association, Inc.; Kaw Valley Electric Cooperative, Inc.; and Nemaha-Marshall Electric Cooperative Association, Inc.
Westar Energy FERC Electric
Tariff No. 7
Partial requirements wholesale power supply agreement including long-term firm transmission service to support purchase of 1.0 MW preference power from Southwest Power Administration
5/31/07 & then on-going 3 yr prior notice
319
Agreement for Sale of Power and Interconnected Operation
Kansas Gas and Electric
Oklahoma Gas and Electric Company
FERC rate schedule OGE-
32, KGE-75 Interconnection On-Going 3 yr prior notice
320
Amended Electric Interconnection Contract Westar Energy
Omaha Public Power District
FERC rate schedule Western
Resources-277 OA97-314 Interconnection
Year to Year 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
321
Service Agreement for Long Term Firm Point-To-Point Transmission Service Westar Energy
Public Service Company of Oklahoma
Service Agreement
No.124 under Western
Resources’ FERC Electric Tariff , 1st. Rev. Volume No. 5 Dockets ER98-
3617
Long term firm transmission service agreement none stated
322
Service Agreement for Long Term Firm Point-To-Point Transmission Service Westar Energy
Public Service Company of Oklahoma
Service Agreement
No.121 under Western
Resources’ FERC Electric Tariff , 1st. Rev. Volume No. 5 Dockets ER98-
2533
Long term firm transmission service agreement none stated
323
Agreement for Interchange of Power and Interconnected Operation
Kansas Gas and Electric
Public Service Company of Oklahoma
FERC rate schedule PSO-161, KGE-97 Interchange
On-Going 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
324
Second Firm Transmission Service Agreement Westar Energy
The State of Oklahoma through Oklahoma Municipal Power Authority
Service agreement No.
131 under Western
Resources’ FERC Electric Tariff,
Original volume No. 5 dockets
ER96-592, ER96-2701, ER00-2465
long term firm transmission supporting an agreement by OMPA to purchase participation power from Western Resources
Agreement automatically terminates December 31, 2013, unless extended by mutual agreement
325 Transmission Service Agreement Westar Energy
The State of Oklahoma through the Oklahoma Municipal Power Authority
dockets ER93-613, ER93-523,
ER94-957
Long term firm transmission service supporting an agreement by OMPA to purchase participation power from Western Resources.
Agreement automatically terminates December 31, 2013, unless extended by mutual agreement.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
326
Jeffrey Energy Center Transmission Agreement Westar Energy
UtiliCorp United, Inc.’s Missouri Public Service Division
256 dockets ER89-485, ER90-235,
ER90-300, ER90-478, ER90-500, ER92-29, ER92-239, ER96-1728,
ER96-1728 Interconnection
This agreement supports the Joint Ownership of the Jeffrey Energy Center Terminates upon the retirement of the last generating unit in which UtiliCorp United has an ownership share at the Jeffrey Energy Center or upon the transfer of any or all of UtiliCorp United’s interest in the Jeffrey Energy Center pursuant to the ownership agreement, whichever comes first. Up to 8% of the output of the Jeffrey Energy Center plus reassigned amounts. Current year amount is 338 MW.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
327
Jeffrey Energy Center Transmission Agreement Westar Energy
UtiliCorp United, Inc.’s WestPlains Division Central Telephone
dockets ER89-485, ER90-235,
ER90-300, ER90-478, ER90-500, ER92-29, ER92-239, ER96-1728,
ER96-1728 Interconnection
This agreement supports the Joint Ownership of the Jeffrey Energy Center Terminates upon the retirement of the last generating unit in which UtiliCorp United has an ownership share at the Jeffrey Energy Center or upon the transfer of any or all of UtiliCorp United’s interest in the Jeffrey Energy Center pursuant to the ownership agreement, whichever comes first. Up to 8% of the output of the Jeffrey Energy Center plus reassigned amounts. Current year amount is 338 MW.
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
328 Power Interchange Agreement
Kansas Gas and Electric Utilicorp-MPS
FERC rate schedule MPS-19, KGE-106 Interchange
Year to Year 3 yr prior notice
329 Electric Interchange Agreement Westar Energy Utilicorp-MPS
FERC rate schedule MPS-
18, Western Resources-84 Interchange
Year to Year 36 mos prior notice
330
Electric Interconnection Contract Westar Energy
Utilicorp-WestPlains Energy WPE-7, KGE-72 Interconnection
5/31/13 & then year to year 5 yr prior notice
331
Electric Interconnection Agreement
Kansas Gas and Electric
Utilicorp-WPD The Western Light & Telephone Co. WPE-6, KGE-101 Interconnection
Year to Year 3 yr prior notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
332 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS Firm TS Sch 7 Network
5/31/2009 - Ongoing per KCPL OATT
333 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS Firm TS Sch 7 Network
12/31/2003 - Ongoing per KCPL OATT
334 Transmission Service Agreement
Kansas City Power & Light AECI
Firm TS Sch 89 ER94-1101-002
NetworkPoint to Point year to year, 18 mo notice
335 Transmission Service Agreement
Kansas City Power & Light AECI
Firm TS Sch 89 ER94-1101-002
NetworkPoint to Point year to year, 18 mo notice
336 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS Firm TS Sch 7 Network
12/31/2003 - Ongoing per KCPL OATT
337 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS 107 Network
12/31/2002 - Ongoing per KCPL OATT
338 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS 107 Network
12/31/2002 - Ongoing per KCPL OATT
339 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS 107 Network
12/31/2002 - Ongoing per KCPL OATT
340 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS 107 Network
12/31/2002 - Ongoing per KCPL OATT
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
341 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS Network
12/31/2002 - Ongoing per KCPL OATT
342
Municipal Participation Agreement
Kansas City Power & Light Baldwin
85 - ER94-1101-002 Point To Point year to year, 42 mo notice
343 Interchange Agreement (UE)
Kansas City Power & Light AMRN
104 - ER94-1101-002 Point To Point year to year, 36 mo notice
344
Municipal Participation Agreement
Kansas City Power & Light Garnett
78 - ER94-1101-002 Point To Point year to year, 42 mo notice
345
Municipal Participation Agreement
Kansas City Power & Light Osawatomie
77 - ER94-1101-002 Point To Point year to year, 42 mo notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
346
Municipal Participation Agreement
Kansas City Power & Light Ottawa
90 - ER94-1101-002 Point To Point year to year, 42 mo notice
347
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS 108 Network year to year, 42 mo notice
348
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS 105 Network year to year, 42 mo notice
349 Wholesale Firm Power Contract
Kansas City Power & Light
Kansas City Power & Light 74 - ER96-1736 Point To Point year to year, 18 mo notice
350 Municipal Firm Power Contract
Kansas City Power & Light
Kansas City Power & Light 82 - ER98-3089 Point To Point year to year, 18 mo notice
351 Cooperative Firm Power Contract
Kansas City Power & Light
Kansas City Power & Light 69 - ER98-4469 Point To Point year to year, 12 mo notice
352 Cooperative Firm Power Contract
Kansas City Power & Light
Kansas City Power & Light 84 - ER98-4468 Point To Point year to year, 18 mo notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
353
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS 108 - ER96-1225 Point To Point year to year, 42 mo notice
354 Municipal Firm Power Contract
Kansas City Power & Light
Kansas City Power & Light 76 - ER96-1448 Point To Point year to year, 18 mo notice
355 Municipal Firm Power Contract
Kansas City Power & Light
Kansas City Power & Light 98 - ER96-689 Point To Point year to year, 18 mo notice
356
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS 77 - ER96-2218 Point To Point year to year, 42 mo notice
357
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS 78 - ER96-2099 Point To Point year to year, 42 mo notice
358
Municipal Participation Agreement
Kansas City Power & Light Ottawa
90 - ER94-1101-002 Point To Point year to year, 42 mo notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
359
Municipal Participation Agreement
Kansas City Power & Light Osawatomie
77 - ER94-1101-002 Point To Point year to year, 42 mo notice
360
Municipal Participation Agreement
Kansas City Power & Light Higginsville
108 - ER94-1101-002 Point To Point year to year, 42 mo notice
361
Municipal Participation Agreement
Kansas City Power & Light Garnett
78 - ER94-1101-002 Point To Point year to year, 42 mo notice
362 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 116 - ER99-2203 Point To Point
3/31/2004 - Ongoing per KCPL OATT
363 KCPL OATT Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 119 - ER99-2202 Point To Point
12/31/2003 - Ongoing per KCPL OATT
364
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 117 - ER99-2204 Point To Point
5/31/2005 - Ongoing per KCPL OATT
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
365
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 128 -
ER00-1247-000 Point To Point 1/31/2003 - Ongoing per KCPL OATT
366
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 128 -
ER00-1247-000 Point To Point 1/31/2007 - Ongoing per KCPL OATT
367
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 128 -
ER00-1247-000 Point To Point 1/31/2010 - Ongoing per KCPL OATT
368
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 130 -
ER00-1247-000 Point To Point 1/31/2003 - Ongoing per KCPL OATT
369
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 130 -
ER00-1247-000 Point To Point 1/31/2007 - Ongoing per KCPL OATT
370
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 130 -
ER00-1247-000 Point To Point 1/31/2010 - Ongoing per KCPL OATT
371
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 131 -
ER00-1247-000 Point To Point 1/31/2003 - Ongoing per KCPL OATT
372
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 131 -
ER00-1247-000 Point To Point 1/31/2007 - Ongoing per KCPL OATT
373
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 131 -
ER00-1247-000 Point To Point 1/31/2010 - Ongoing per KCPL OATT
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
374
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 134 -
ER00-1247-000 Point To Point 1/31/2003 - Ongoing per KCPL OATT
375
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 134 -
ER00-1247-000 Point To Point 1/31/2007 - Ongoing per KCPL OATT
376
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 134 -
ER00-1247-000 Point To Point 1/31/2010 - Ongoing per KCPL OATT
377
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 135 -
ER00-1247-000 Point To Point 1/31/2003 - Ongoing per KCPL OATT
378
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 135 -
ER00-1247-000 Point To Point 1/31/2010 - Ongoing per KCPL OATT
379
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 129 -
ER00-1247-000 Point To Point 1/31/2003 - Ongoing per KCPL OATT
380
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 129 -
ER00-1247-000 Point To Point 1/31/2007 - Ongoing per KCPL OATT
381
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 129 -
ER00-1247-000 Point To Point 1/31/2010 - Ongoing per KCPL OATT
382
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 132 -
ER00-1247-000 Point To Point 1/31/2010 - Ongoing per KCPL OATT
383
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 133 -
ER00-1247-000 Point To Point 1/31/2003 - Ongoing per KCPL OATT
384
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 133 -
ER00-1247-000 Point To Point 1/31/2007 - Ongoing per KCPL OATT
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
385
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 133 -
ER00-1247-000 Point To Point 1/31/2010 - Ongoing per KCPL OATT
386
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 136 -
ER00-1247-000 Point To Point 1/31/2003 - Ongoing per KCPL OATT
387
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 136 -
ER00-1247-000 Point To Point 1/31/2007 - Ongoing per KCPL OATT
388
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 136 -
ER00-1247-000 Point To Point 1/31/2010 - Ongoing per KCPL OATT
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
389
Municipal Participation Agreement
Kansas City Power & Light
Kansas City Power & Light-PS
KCPL OATT Vol 3, Sup 93 - ER00-
1247-000 Point To Point 12/31/2010 - Ongoing per KCPL OATT
390 Electric Interchange Agreement
Kansas City Power & Light
Empire District Electric Company
88 - ER94-1101-002 Point To Point year to year, 36 mo notice
391
Municipal Participation Agreement
Kansas City Power & Light
Board of Public Utilities - Kansas City Kansas
54 - ER94-1101-002 Point To Point year to year, 42 mo notice
392 Electric Interchange Agreement
Kansas City Power & Light Westar Energy
55 - ER94-1101-002 Point To Point year to year, 36 mo notice
393 Missouri Interconnection KCPL 111 - ER94-411
394 MOKAN Interconnection KCPL 110 - ER94-411 Term of GPA
395 MPS Multiple Interconnection KCPL GMO 58 - ER91-682 year to year, 48 mo notice
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
396 KCPL Network Service
KCPL OATT Vol. 3, Supp. 127 -
ER00-1132-000
397 WC-LaCygne 345kV Line Lease Westar KCPL
Westar's KGE 160 - ER91-391 Concurrent with supply
398 Facilities Use Agreement
Responsibility of GMO/KCPL
107 - ER91-41-000
399
Cooper-Fairport-St. Joseph Interconnection (MINT) KCPL
107 - ER91-41-000 year to year, 48 mo notice
400 Sched P Westar Energy Midwest Energy
FERC Rate Schedule
Supplement No. 21 to 123, Docket
No. ER91-357
Transmission Service Agreement 5/31/2010
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
401 Sched PPA Westar Energy Midwest Energy
OASIS:272409-FERC Rate
Schedule 265, Docket Nos.
ER93-849, OA96-100
Transmission Service Agreement
5/31/2008 extends until canceled. (Trans Svc Agrmt Ex. A - extended under the provisions of Section 6 Paragraph 6.2 of MWE RS No. 184 - thru 09/30/2013 or approval of CBFR.)
402 Holcomb Sunflower Electric Power Midwest Energy
Interconnection & Transmission Service Agreement
Through 5/31/2006 with renewal provisions thereafter
403 MTS-Colby Midwest Energy City of Colby Supp 5 to FERC
No. 6
Transmission Service Agreement None
404 MTS-Oakley Midwest Energy City of Oakley Supp 5 to FERC
No. 4
Transmission Service Agreement None
405 MFS-Radium Midwest Energy City of Radium FERC Rate
Schedule No. 13
Bundled Wholesale Sales Service None
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
406 MFS-Seward Midwest Energy City of Seward FERC Rate
Schedule No. 12
Bundled Wholesale Sales Service None
407 NF Colby Midwest Energy City of Colby SA 2 to FERC
Tariff Vol. 4 Point To Point None
408 NF Oakley Midwest Energy City of Oakley SA 16 to FERC
Vol. 4 Point To Point None
409 NF LaCrosse Midwest Energy City of LaCrosse SA 17 to FERC
Vol. 4 Point To Point None
410 NF Jetmore Midwest Energy City of Jetmore SA 15 to FERC
Vol. 4 Point To Point None
411 Sunflower Interconnect
Sunflower Electric Company Midwest Energy Network
Through 6/30/2010 with renewal provisions thereafter
412 Sunflower Interconnect Midwest Energy
Sunflower Electric Company Network
Through 6/30/2010 with renewal provisions thereafter
Line No Contract Title Selling
Party Buying Party FERC Sch. Type of Service Termination
Provisions Capacity (MW) Type Other
413
Agreement for Interchange of
Power & Interconnected
Operations Between
UtiliCorp United Inc. d/b/a
Missouri Public Service and Associated
Electric Cooperative,
Inc.
Both Aquila
GMO(fromerly
UtiliCorp Unitied
Inc.) and Associated
Both Aquila GMO(fromerly UtiliCorp Unitied Inc.)
and Associated
60
Long Term, Short Term and
Emergency Transmission
Service, various capacity and energy (power) services and
Exchange Power Interconnections.
Four Years prior written notice Transmissio
n and Power
Note: The Exchange
Power Interconnections provide for power to be
supplied from party A to
Party B for the other for load that resides in
the other parties control
area and is treated like Full Requirements
load.
414 Contract for Electric Service
AquilaGMO City of Galt 55 Full Requirements
One year advance notice to terminate and
two years advance to
switch power suppliers
Full Requirements
415 Contract for Electric Service
AquilaGMO Gilman City 56 Full Requirements
One year advance notice to terminate and
two years advance to
switch power suppliers
Full Requirements
Line No
Contract Title
Selling Party
Buying Party
FERC Sch. Type of Service Termination
Provisions Capacity
(MW) Type
416 Contract for
Electric Service
AquilaGMO Liberal 54 Full Requirements
One year advance notice to terminate
and two years advance to switch power suppliers
Full Requirements
417 Contract for
Electric Service
AquilaGMO Osceola 109 Full Requirements
One year advance notice to terminate
and two years advance to switch power suppliers
Full Requirements
418 Contract for
Electric Service
AquilaGMO Rich Hill 58 Full Requirements
One year advance notice to terminate
and two years advance to switch power suppliers
Full Requirements
419
Service Agreement for
Network Integration
Transmission Service
AquilaGMO Odessa OATT NITS - Reference #657274 14 NITS
Line No Contract Title Selling
Party Buying Party
FERC Sch. Type of Service Termination
Provisions Capacity
(MW) Type Other
420
Service Agreement for
Network Integration
Transmission Service
AquilaGMO Harrisonville OATT NITS - Reference #497133 30 NITS
421 Control Area Service
Associated Electric
Cooperative, Inc.
UtiliCorp United Inc. Firm Network
Evaluated annually by
AECI, termination
allowed upon 12 months
written notice to UCU; UCU may terminate
with 30 day written notice
to AECI.
150 Network
422 Firm point to point Aquila Aquila OATT, reference #
840769
Reservation presently
goes out to 5/31/2006
100
423 Network Service Aquila Aquila OATT Network -
reference # 736081 315 Network
Transmission service to
deliver South Harper
generation to Aquila load
Line No
Contract Title Selling Party
Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW) Type Other
424
Electric Sales, Transmission and Service Contract between Centel Corporation and Kansas Electric Power Cooperative, Inc.
Centel Corporation
Kansas Electric Power Cooperative, Inc
71 Network 60 month advance written notice
Transmission
425
Full Requirements Contract between Centel Corporation and City of Cawker City
Centel Corpation
City of Cawker City
73 Full Requirements
24 month advance written notice
Full Requirements
Line No
Contract Title Selling Party
Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW)
Type Other
426
Full Requirements Contract between WestPlains Energy and City of Cimarron
WestPlains Energy
City of Cimarron
67 Full Requirements
36 month advance written notice
Full Requirements
Line No
Contract Title Selling Party
Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW)
Type Other
427
Full Requirements Contract between Centel Corporation and City of Glasco
Centel Corpation
City of Glasco
74 Full Requirements
36 month advance written notice
Full Requirements
428
Full Requirements Contract between Centel Corporation and City of Glen Elder
Centel Corpation
City of Glen Elder
75 Full Requirements
36 month advance written notice
Full Requirements
429
Full Requirements Contract between WestPlains Energy and City of Holyrood
WestPlains Energy
City of Holyrood
64 Full Requirements
36 month advance written notice
Full Requirements
Line No
Contract Title Selling Party
Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW) Type Other
430
Full Requirements Contract between WestPlains Energy and City of Isabel
WestPlains Energy
City of Isabel 65 Full Requirements
36 month advance written notice
Full Requirements
431
Full Requirements Contract between Centel Corporation and City of Lucas
Centel Corpation
City of Lucas 76 Full Requirements
36 month advance written notice
Full Requirements
432
Full Requirements Contract between WestPlains Energy and City of Luray
WestPlains Energy
City of Luray 69 Full Requirements
36 month advance written notice - presently effective as of Sept 30, 2005, reviewed annually by City
Full Requirements
433
Full Requirements Contract between Centel Corporation and City of Mankato
Centel Corpation
City of Mankato
77 Full Requirements
36 month advance written notice
Full Requirements
Line No Contract Title Selling
Party Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW) Type Other
434
Full Requirements Contract between WestPlains Energy and City of Montezuma
WestPlains Energy
City of Montezuma
68 Full Requirements
36 month advance written notice
Full Requirements
Line No
Contract Title Selling Party
Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW)
Type Other
435
Transmission Service Contract between Centel Corporation and City of Lindsborg
Centel Corpation
City of Lindsborg
83 Transmission 60 month advance written notice
Transmission Wheel Lindsborg's WAPA allocation from Sunflower interconnection to KPL system.
436
Municipal Interconnection Contract between Centel Corporation and City of Ashland
Centel Corpation
City of Ashland
78 Transmission 36 month advance written notice - notice submitted Nov 1, 2004
0.65 Transmission Wheel Ashland's WAPA allocation from Sunflower Interconnection to City
437
Municipal Interconnection Contract between Centel Corporation and City of Beloit
Centel Corpation
City of Beloit
79 Transmission 36 month advance written notice - notice submitted Nov 1, 2004
2 Transmission Wheel Beloit's WAPA allocation from Sunflower Interconnection to City
Line No Contract Title Selling
Party Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW) Type Other
438
Municipal Interconnection Contract between Centel Corporation and City of Lincoln Center
Centel Corpation
City of Lincoln Center
80 Transmission 36 month advance written notice - notice submitted Nov 1, 2004
0.5 Transmission Wheel Lincoln Center's WAPA allocation from Sunflower Interconnection to City
439
Municipal Interconnection Contract between Centel Corporation and City of Osborne
Centel Corpation
City of Osborne
81 Transmission 36 month advance written notice - notice submitted Nov 1, 2004
1 Transmission Wheel Osborne's WAPA allocation from Sunflower Interconnection to City
440
Municipal Interconnection Contract between Centel Corporation and City of Stockton
Centel Corpation
City of Stockton
82 Transmission 36 month advance written notice - notice submitted Nov 1, 2004
0.6 Transmission Wheel Stockton's WAPA allocation from Sunflower Interconnection to City
441
Sunflower/Aquila Capacity Agreement
Sunflower Electric Power Corporation
UtiliCorp United, Inc
Capacity/transmission
May 31, 2008 - mutually reviewed annually
100 Capacity/transmission
Line No Contract Title Selling
Party Buying Party FERC Sch. Type of Service Termination Provisions
Capacity (MW) Type
442
Letter Agreement dated February 25, 1994 ("Participation Agreement")
Sunflower Electric Power Corporation
UtiliCorp United, Inc
Unit Participation/transmission
May 31, 2009 - mutually reviewed annually
50 Unit Participation/transmission
443
Schedule D imbalance payback
Aquila, Inc Aquila, Inc OATT, Reference #'s 652106, 652105, 591891, 591881, 591877, 578267
Reservations presently go out to 2008
6 reservations, 5 MW each
Network Reservations are used to payback use of 34.5 kV back service between WPEK and SECI, WRI, and MIDW
444
Firm Point to Point
Aquila, Inc Aquila, Inc OATT reference # 760849
Reservation presently goes out to 10/1/2005
10 Point to Point, WPEK to MIDW
445
Cooper-Fairport: St. Joseph Interconnection (MINT)
107-ER91-41-000
Year to year, 48 mo notice
Line No Contract Title Selling
Party Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW) Type Other
446 Power Supply Agreement
Sunflower Electric Power
Corporation
Lane-Scott Electric
Cooperative / City of Dighton
Full Requirements
90 days prior to the beginning of each successive optional term of
3 years
Full Requirements
447
Electric Interconnection
and Power Supply
Agreement
Sunflower Electric Power
Corporation
Prairie Land Electric
Cooperative, INC / City of Norton, KS
Full Requirements;
unless the City provides written notice to Sunflower at least 180 days prior to the beginning
of any Contract year.
The Parties to this agreement
shall negotiate in good faith towards a possible
extension; however, neither
party is obligated to extend this Agreement
beyond the initial term. Contract duration is 5
years
Full Requirements
Line No Contract Title Selling
Party Buying Party FERC Sch. Type of Service Termination
Provisions Capacity
(MW) Type Other
448
Electric Interconnection
and Power Supply
Agreement
Sunflower Electric Power
Corporation
Wheatland Electric
Cooperative, INC / City of Lakin, KS
Full Requirements
180 days prior to the beginning of each successive optional term of 3
years
Full Requirements
449 Energy Sales Agreement
Sunflower Electric Power
Corporation
Pioneer Electric
Cooperative, INC / City of Johnson, KS
Full Requirements One Year Notice 8 MW Full Requirements
450
Electric Interconnection
and Power Supply
Agreement
Sunflower Electric Power
Corporation
Pioneer Electric Power Corporation, INC / City of Hugoton, KS
Full Requirements
180 days prior to the beginning of each successive optional term of 3
years
Full Requirements
451
Electric Interconnection
and Power Supply
Agreement
Sunflower Electric Power
Corporation
Prairie Land Electric
Cooperative, INC / City of Hill City, KS
Full Requirements
90 days prior to the beginning of each successive optional term of 3
years
Full Requirements
452
Electric Interconnection
and Power Supply
Agreement
Sunflower Electric Power
Corporation
Prairie Land Electric
Cooperative, INC / City of Herndon, KS
Full Requirements
Agreement terminates on
September 14th, 2009
Full Requirements
Line No Contract Title Selling Party Buying
Party FERC Sch. Type of Service Termination
Provisions Capacity
(MW) Type
453
Electric Interconnection
and Power Supply
Agreement
Sunflower Electric Power
Corporation
City of Goodland,
KS Full Requirements
90 days prior to the beginning of each successive optional term of
3 years
Full Requirements
454 Power Supply Agreement
Sunflower Electric Power
Corporation
Wheatland Electric
Cooperative, INC / City of Garden City,
KS
Full Requirements
2 year notice that may
establish a termination date
between December 1,
2008 and ending November 30,
2010
Full Requirements
455
Electric Interconnection
and Power Supply
Agreement
Sunflower Electric Power
Corporation
Kansas Municipal Energy
Agency for benefit of
Oberline, St. Fancis, and
Sharon Springs, KS.
Full Requirements
Terminates May 24th, 2010 with the good faith for additional five Contract
Years.
Full Requirements
Line No Contract Title Selling
Party Buying Party FERC Sch. Type of Service Termination
Provisions Capacity
(MW) Type Other
456
System Participation
Power Service Agreement
Sunflower Electric Power
Corporation
Midwest Energy, INC
Full Requirements
12 months notice and
must occur at the end of a
term
25 MW Full Requirements
457 Interconnection Agreement
Sunflower Electric Power
Corporation
Midwest Energy, INC
Network 3 years prior written notice
458 Wholesale
Power Agreement
Sunflower Electric Power
Corporation
Kansas Electric Power Cooperative,
INC
Full Requirements
1 year prior to termination Full Requirements
Line No
Contract Title Selling Party
Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW)
Type Other
459 Power Purchase Agreement
Sunflower Electric Power Corporation
Central Plans Power, LLC
Full Requirements
January 28th, 2023; unless the buyer provides the seller with 60 days prior written notice
Full Requirements
460 Interconnection Agreement
Sunflower Electric Power Corporation
Nebraska Public Power District
May 1, 2006; unless terminated by 4 years written notice
461 Interconnection Agreement
Sunflower Electric Power Corporation
WestPlains, Inc Mid-Kansas
Assessed on a year-to-year basis up to May 31, 2009
100
462 Interconnection Agreement
Sunflower Electric Power Corporation
Southwestern Public Service Company
January 28th, 2020 unless one of the parties provides a 1 year written notice
Line No
Contract Title Selling Party
Buying Party
FERC Sch.
Type of Service
Termination Provisions
Capacity (MW) Type Other
463 Interconnection Agreement
Sunflower Electric Power Corporation
Western Area Power Administration
September 30, 2024
October 221 November 207 December 236 January 228 February 236 March 264 April 255 May 232 June 180 July 285 August 247 September 240
464
Wholesale Power Contract with Member Cooperatives
East Texas Electric Cooperative
Member Co-ops
All requirements wholesale power supply agreement
12/31/2044
465
Wholesale Power Contract Member Cooperatives
Tex-La Electric Cooperative of Texas
Member Co-ops
All requirements wholesale power supply agreement
12/31/2044
Line No. Contract Title Selling
Party Buying Party
FERC Sch.
Type of Service
Termination Provisions Capacity (MW) OASIS
Reference
466
MINT Coordinating Agreement, Cooper -Fairport-St. Joseph Interconnection (MINT) Dated March 5, 1990 and associated agreements
MINT Participants-Responsibility of GMO/KCPL
MINT Participants N/A
Point to Point Service Rights
Initial term 50 years, extended thereafter on year to year basis, 4 years notice to withdraw
See Transmission Capacity Rights in contract
467
LES and Associated Electric Cooperative (AECI) Agreement dated October 31, 1996 as amended LES & AECI LES & AECI N/A
Point to point firm reservations of Firm Capacity on MINT Line
Agreement automatically extends each year. One month notice.
50mw 70 mw
#1596 & #1597
468
MINT Transmission Exchange Agreement dated February 15, 1990
LES & NPPD LES & NPPD N/A
Exchange of a portion of LES firm capacity rights on MINT Line to NPPD for Point to Point rights on NPPD transmission System
Agreement shall remain in force as long as LES is a participant in the MINT Project (See MINT). No notice provisions
See Transmission Capacity Rights Exchange in Article II &III
Line No. Contract Title Selling
Party Buying Party
FERC Sch.
Type of Service
Termination Provisions Capacity (MW) OASIS
Reference
469
Power Supply and Wheeling Agreement dated January 1, 1999 LES
State of Nebraska N/A
Point to Point Service- Fixed allocation requirements contract
Agreement will terminate either when State of Nebraska WAPA contract terminates or the date following one year notice whichever is first to occur 1.832 mw
470
Power Supply and Wheeling Agreement dated January 1, 1999 LES
University of Nebraska-Lincoln N/A
Point to Point Service-Fixed allocation requirements contract
Agreement will terminate either when UNL WAPA contract terminates or the date following one year notice whichever is first to occur. 19.534 mw
471
Electric Interconnection and Interchange Agreement dated June 20, 1988 as amended
LES and OPPD
LES and OPPD N/A
Interconnection and Interchange of Power and Energy Between Systems
Agreement extends to January 1 2015 2040 and thereafter year to year with 4 5 years written notice
Line No. Contract Title Selling
Party Buying Party
FERC Sch.
Type of Service
Termination Provisions Capacity (MW) OASIS
Reference
472
Gerald Gentlemen Station Power Sales Contract LES NPPD N/A
Tranformation Capacity in the LES 345kv West Substation up to 50mw
Agreement expires when Gerald Gentleman removed from commerical operation Up to 50 mw
473
Interconnection Agreement dated May 1, 1977 as amended
LES and NPPD
LES and NPPD N/A
Interconnection and Interchange of Power and Energy Between Systems pursuant to various Service Schedules to the Agreement
Agreement extends 30 years or until all Service Schedules have terminated whichever is last to occur. Thereafter continues with notice requirement of 4 years.
474 LES OASIS Reservation LES LES N/A
Point to Point Firm Drive In Service for WAPA Purchase Power Contracts to load 2021
59mw 75mw
#1286717 (WAPA Seasonal Firm) #1286716 (WAPA Peaking Firm
Line No. Contract Title Selling
Party Buying Party
FERC Sch.
Type of Service
Termination Provisions Capacity (MW) OASIS
Reference
475 LES OASIS Reservation LES LES N/A
Point to Point Firm Drive in Service for Walter Scott Station to load 2036 105 mw
#575887 #623600 #71115707
476 LES OASIS Reservation LES LES N/A
Point to Point Drive In Service for MBPP Laramie River Station to load 2021 190mw
#1286714 #649944
477 LES OASIS Reservation LES LES N/A
Point to Point Drive In Service for Gerald Gentleman Station to load 2021 109 mw #1286715
478 LES OASIS Reservation LES LES N/A
Point to Point Drive In Service for Sheldon Station to load 2021 68mw #1286712
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
479
Electric Interconnection and Interchange
Agreement [95-L22-60]
Nebraska Public Power District
MidAmerican Energy Company
(IPS) Transmission
Interconnection
1/1/2010 and annual thereafter
(4 yr Notice)
480 Transmission
Operating Agmt. [06-L22-15]
Nebraska Public Power District
MidAmerican Energy Company
(IPS)
Point to Point Service and
Contract Rights
6/30/2009 or MEC participation in
CNS or MINT Line (4 Yr Notice)
250
Oasis Reservation # 842306
481 Power Sales
Agreement [04-L22-2]
Nebraska Public Power District
MidAmerican Energy Company
(IPS)
Generator Outlet and Contract
Rights
12/31/2009 Subject to Extension
482
Electric Inteconnection
and Interchange Agreement [96-L22-53]
Nebraska Public Power District
Omaha Public Power District
Point to Point Service,
Transmission Interconnection and Service Per
Parties Rate Schedules
1/1/2005 or contingent on
OPPD participation in
MINT line
25 15 10
Oasis Reservation # 1294408 1294407 1282819
483
Wind Facility Share
Participation Agreement [04-
L22-30]
Nebraska Public Power District
Omaha Public Power District
Point to Point Service OPPD responsible for Transmission at
Wind Sub delivery point
10/27/2024 Subject to renewals
8 2
Oasis Reservation # 1217482
1217220
484
Interconnection Agreement [96-L22-50], Service
Schedule 4
Nebraska Public Power District
City of Lincoln, Ne (LES)
Point to Point Service,
Generator Outlet & Contract
Delivery (WAPA Peaking)
5/1/2007 or decommission of NPPD's Cooper Nuclear Station
97 75
Oasis Reservation # 178307
178299
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
485
Interconnection Agreement [96-L22-50] Service
Schedule 9
Nebraska Public Power District
City of Lincoln, Ne (LES)
Point to Point Service Contract Delivery, (WAPA
Firm)
Through term of WAPA contracts 59
Oasis Reservation # 178297
486
Interconnection Agreement [96-L22-50] Service
Schedule 10
Nebraska Public Power District
City of Lincoln, Ne (LES)
Contract Rights Exchange for
Service (MINT)
Through Term of MINT contract
487
MINT Rights Exchange
Agreement [99-L22-13]
Nebraska Public Power District
City of Lincoln, Ne (LES)
Contract Rights Exchange for
Service
Through Term of MINT contract
488
Interconnection Agreement [96-
L22-50] Service Schedule
12
Nebraska Public Power District
City of Lincoln, Ne (LES)
Pre-OATT Point to Point service.
Gentleman Station delivery
Agreement terminates with
end of Gentleman Station Power
Sales Agreement
489
Gerald Gentleman Station
Participation Power Sales
Agreement [96-L22-44]
Nebraska Public Power District
City of Lincoln, Ne (LES)
Point to Point Service Contract
Rights, BTS Capacity Rights
Exchange
Life of Plant 109 Oasis Reservation # 178301
490
Bulk Transmission System Loss Factor Letter
Agreement [99-L22-21]
Nebraska Public Power District
City of Lincoln, Ne (LES) / Basin Electric Power Cooperative
BTS Loss Compensation
Calculation Procedure
In conjunction with Base Contracts
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
491
Amended and Restated
Coordinating Agreement for the Cooper-Fairport-St.Joseph 345 kV
Line (MINT) [98-L21-18]
Nebraska Public Power District
Associated Electric
Cooperative, Inc./ Kansas City
Power & Light/ St. Joseph Light &
Power Company/ MidAmerican
Energy Company/ Omaha Public Power District/
City of Lincoln, NE
Point to Point Service
Interconnection Capacity and Transmission
Service
3/4/2040
See
capacity rights
identified in the
contract
Oasis Reservation
# 178323 178322 178321 178317
492
Transmission Line Terminal Facilities
Agreement [99-L22-12]
Nebraska Public Power District
Omaha Public Power District/
City of Lincoln, NE (LES)/
MidAmerican Energy Company
Use of Cooper MINT Terminal
Facilities for deliveries at contract rate
3/4/2040
493
Electric Interconnect &
Interchange Agreement. [96-L22-110]
Nebraska Public Power District
SEC Corporation (Sunflower
Electric) Interconnection
5/1/2006 evergreen
thereafter (4 Yr Notice)
494
Western Nebraska Joint
Transmission Agreement [96-
L22-83]
Nebraska Public Power District
Tri-State Generation and Transmission
Association, Inc.
Network-type Transmission
Service
1/1/1994 with annual extensions
(5 Yr Notice)
86 30
350380
Oasis Reservation
# 181655
1254746 1071027
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
495
Agreement for Common Use of Switching Station and Transmission
Facilities - Big Springs Tap [95-L21-612]
Nebraska Public Power District
Tri-State Generation and Transmission
Association, Inc.
Transmission
Capacity Allocation
November 30, 2007 ( In process of amending to
"Evergreen Term.")
496 Transmission
Service Contract [99-L22-23]
Nebraska Public Power District
Basin Electric Power
Cooperative
Point to Point Service Bulk
Transmission Service - Contract
Rate
12/31/2040
272 190
Oasis Reservation # 520962
178300
497
Agreement for Construction and
Joint Use of Substation and Transmission
Facilities [94-L21-502]
Nebraska Public Power District
Basin Electric /Rushmore Cooperative /Cherry-Todd Cooperative /
LaCreek Electric Association
Network Transmission and SubT service for joint use facilties (Cody - Niobrara)
6/18/2015 or as long as facilities in
use.
498
Agreement for Joint Use of
Substation and Transmission
Facilities [94-L21-383]
Nebraska Public Power District
Wheat Belt Public Power District
Joint Use of 115/34.5
Substation at Blue Creek
Year to Year, one year notice
499
Stegall DC Tie Loss
Compensation Agreement [99-
L22-24]
Nebraska Public Power District
Basin Electric Power
Cooperative
Loss procedure of DC Tie
interconnection
9/16/2011 subject to renewal
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
500
Loveland Area Projects for Firm Electric Service
[96-L22-103]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Rocky Mountain
Region)
NPPD Firm Electric Service
from the Loveland Area Projects
9/30/2024
501
Interconnection and Transmission
Agreement 87-LAO-200
[96-L22-100]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Rocky Mountain
Region)
Point to Point Service
Transmission Interconnection
and Service
12/31/2019
2 18 1
Oasis Reservation # 1299729
1299689 1299687
502
Electric Power Service
93-BAO-667 [96-L22-60]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Upper Great
Plains Region)
Point to Point Service
Transmission Interconnection
and Service
12/31/2020
64 492
Oasis Reservation # 1282494
1282491
503
Contract For Control Area Regulation
Service [00-L22-317]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Upper Great
Plains Region)
Control Area Regulation
Service provided by WAPA to
NPPD
Annual Term, but in no case extend beyond 2021(30 day termination,
anytime)
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
504
Contract For Administrative
Services [99-L22-64]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Upper Great
Plains Region) / City of Beatrice,
Nebraska
NPPD provides control area
scheduling service for Beatrice firm
service from WAPA
12/31/2020 (termination by one year notice,
anytime)
505
Contract For Bill Crediting Program
Arrangements [01-L22-19]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Upper Great
Plains Region) / Omaha Tribe of
Nebraska / Nebraska Electric
G & T Cooperative, Inc. / Burt County Public
Power District
Provides Firm Electric Power
Benefit to Omaha Tribe utilizing
existing delivery systems
Successive Annual Periods
through 12/31/2020
(termination 90 days notice,
anytime)
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
506
Contract For Bill Crediting Program
Arrangements [00-L22-305]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Upper Great
Plains Region) / Santee Sioux
Tribe of Nebraska / Nebraska
Electric G & T Cooperative, Inc. /
North Central Public Power
District
Provides Firm Electric Power
Benefit to Santee Sioux Tribe
utilizing existing delivery systems
Successive Annual Periods
through 12/31/2020
(termination 90 days notice,
anytime)
507
Contract For Bill Crediting Program
Arrangements [01-L22-20]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Upper Great
Plains Region) / Oglala Sioux Tribe
of Nebraska
Provides Firm Electric Power
Benefit to Oglala Sioux Tribe
utilizing existing delivery systems
Successive Annual Periods
through 12/31/2020
(termination 90 days notice,
anytime)
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
508
Contract For Bill Crediting Program
Arrangements [01-L22-21]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Upper Great
Plains Region) / Winnebago Tribe
of Nebraska / Nebraska Electric
G & T Cooperative, Inc. / Burt County Public
Power District
Provides Firm Electric Power
Benefit to Winnebago Tribe utilizing existing delivery systems
Successive Annual Periods
through 12/31/2020
(termination 90 days notice,
anytime)
509
Contract For Bill Crediting Program
Arrangements [01-L22-22]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Upper Great
Plains Region) / Winnebago Tribe
of Nebraska
Provides Firm Electric Power
Benefit to Winnebago Tribe utilizing existing delivery systems
Successive Annual Periods
through 12/31/2020
(termination 90 days notice,
anytime)
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
510
Contract For Bill Crediting Program
Arrangements [01-L22-23]
Nebraska Public Power District
U.S. Department of Energy -
Western Area Power
Administration (Upper Great
Plains Region) / Winnebago Tribe
of Nebraska / Nebraska Electric
G & T Cooperative, Inc. /
Northeast Nebraska Public Power District
Provides Firm Electric Power Benefit to Winnebago Tribe utilizing existing delivery systems
Successive Annual Periods through
12/31/2020 (termination 90
days notice, anytime)
511 Transmission
Service Agreement [06-L22-1]
Nebraska Public Power District
Municipal EnergyAgency of Nebraska (MEAN)
Point to Point Service Transmission Service 12/31/2015
25 25
Oasis Reservation # 1282761 1282760
512
Network Transmission
Service Agrmt [06-L22-2]
Nebraska Public Power District
Municipal EnergyAgency of Nebraska (MEAN)
Network Firm Transmission Service 12/31/2015
513 Lincoln Delivery Agreement [03-
L22-9]
Nebraska Public Power District
Municipal EnergyAgency of Nebraska (MEAN)
Bulk Transmission Service for share of Laramie River (sale
from LES)
2/28/2026
514
Wind Facility Share Participation
Agreement [04-L22-31]
Nebraska Public Power District
Municipal EnergyAgency of Nebraska (MEAN)
Point to Point Service MEAN responsible for Transmission at Wind
Sub delivery point
10/27/2024 renewals possible
7 Oasis
Reservation # 992887
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions Capacity (MW) Other
515
System Participation
Agreement [04-L22-9]
Nebraska Public Power District
Municipal EnergyAgency of Nebraska
(MEAN)
NPPD sale to
MEAN of Power and Energy
4/30/2014
516
Local Non-Network Service
Agreement [03-L22-8]
Nebraska Public Power District
Municipal EnergyAgency of Nebraska
(MEAN)
Load Management via run of
generation to determine T-2 rate
demand
12/31/2010
517
Electric Interconnection
and Interchange Agreement [94-L22-10]
Nebraska Public Power District
City of Grand Island,
Nebraska
Point to Point Service
Transmission Interconnection
Service
1/1/2005, yearly thereafter (4 Yr Notice) 9
Oasis Reservation # 662099
518
230/115 Transformer Replacement
Agreement [99-L22-83]
Nebraska Public Power District
City of Grand Island,
Nebraska
Transmission Credit for Capital
Improvement, T-2 specific
12/31/2020
519 Joint Reporting Agreement [02-
L20-119]
Nebraska Public Power District
City of Grand Island,
Nebraska
Joint Load & Capability
Reporting to MRO
5/31/2004, yearly thereafter (6 months
notice)
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
520
Wind Facility Share
Participation Agreement [04-
L22-45]
Nebraska Public Power District
City of Grand Island, Nebraska
Point to Point Service G.I.
responsible for Transmission at
Wind Sub delivery point
11/22/2024 renewals possible 1
Oasis Reservation # 990218
521
Interconnection and Interchange
Agreement [94-L22-11]
Nebraska Public Power District
City of Hastings, Nebraska
Point to Point Service
Transmission Interconnection
Service
3/31/2009, yearly thereafter (6 Mo.
Notice) 13
Oasis Reservation # 224052
522
Mutual Emergency
Energy Agreement [04-
L20-195]
Nebraska Public Power District
City of Hastings, Nebraska
Reciprocal interchange of
emergency energy as needed
6/14/2009 (6 mo anytime notice)
523
Whelan Energy Center 2
Transmission Facilities
Agreement [07-L22-130]
Nebraska Public Power District
Public Power Generating
Agency / City of Hastings, NE
Transmission Credit for facility costs
Until all obligations fulfilled, including
crediting obligations
524
Mission - St. Francis -
Valentine 115 KV
Transmission Line Agreement
[04-L21-14]
Nebraska Public Power District
Cherry-Todd Electric
Cooperative / Nebraska Electric
Generation and Transmission
Cooperative, Inc.
Transmission Service
8/23/2012, and thereafter as long as
line in service
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
525 Interconnection Agreement [03-
L20-106]
Nebraska Public Power District
Cherry-Todd Electric
Cooperative / Nebraska Electric
Generation and Transmission
Cooperative, Inc.
Transmission
Interconnection and Service
Continues until terminated, (12 Mo.
Notice).
526
Participation and Cost Sharing
Agreement (Springview
Wind Facility) [04-L21-15]
Nebraska Public Power District
Auburn, NE/ Grand Island,
NE/ KBR Rural Public Power
District/ Lincoln, NE/ Municipal
Energy Agency of NE
Transmission
Service under T-2 Rate
5/7/2018 (participant termination 4 Yr.
Notice)
527
Facilties Modifications
and Construction
Agreement for Cooper South
Flowgate Upgrades [06-
L22-22]
Nebraska Public Power District
Aquila, Inc./ MidAmerican
Energy Company/
Omaha Public Power District
Transmission
Capacity Rights established.
Through completion of project and all final
payments made
528
Gerald Gentleman Station Unit Participation
Agreement [96-L21-462]
Nebraska Public Power District
St.Joseph Light & Power Company
Point to Point Service
Transmission Capacity and
Service
5/31/2011 Oasis
Reservation # 1622
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
529
Kingsley Project Power Sales Agreement [95-L21-121
and 122]
Nebraska Public Power District
Central Nebraska Public
Power and Irrigation District
NPPD purchase of Hydro output / Transmission
Capacity Rights
Bonds Paid or Retirement of Plant,
the later
530
Loss Replacement
Agreement [96-L22-64], (Part of
Power Interference Agreement)
Nebraska Public Power District
Loup River Public Power
District / Bureau of Reclamation / Western Area
Power Administration
Point to Point Service Loss
compensation to NPPD for delivery to Loup due to water diversion at North Loup Reclamation
On or Before Year 2020 15
Oasis Reservation # 1282493
531
Cooper Nuclear Station Unit Participation Agreement [03-L21-75]
Nebraska Public Power District
Aquila Inc. d/b/a Aquila Networks
Point to Point Service Power Sale to AQN from CNS /
Transmission Service
1/18/2014 75 Oasis
Reservation # 809481
532
Cooper Nuclear Station Unit Participation Agreement [03-L21-75]
Nebraska Public Power District
Heartland Consumers
Power District
Point to Point Service Power Sale to HCPD off of CNS
/ Transmission Service on NPPD System by NPPD
Energy Supply
12/31/13 with option to extend to 12/31/2016 45
Oasis Reservation # 874963
533
Generator Interconnection Agreement [08-
L22-98]
Nebraska Public Power District
Elkhorn Ridge Wind, LLC
Generator Interconnection
Service on NPPD Transmission
System
12 Month termination notice or contract
terms
534 Wholesale Power Contract
Nebraska Public Power District Sutton 94-L22-
71
Full Requirements Wholesale Power
contract
Through 4-10-15; year to year thereafter; 5 yrs notice.
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
535 Wholesale Power Contract
Nebraska Public Power District Snyder 94-L22-
67
Full Requirements Wholesale Power
contract
Through at least 5-31-12, but no longer than 5-31-16; one year notice.
536 Wholesale Power Contract
Nebraska Public Power District Hemingford 94-
L22-48
Full Requirements Wholesale Power
contract
Through 10-31-18; year to year thereafter; 5 yrs notice.
537 Wholesale Power Contract
Nebraska Public Power District
Neligh 9400-L22-10
Full Requirements Wholesale Power
contract
Through 3-31-10, no rolling term; one year notice by Customer prior to terminate prior to 3-31-10. Will offer then-current WPC after 3-31-10.
538 Wholesale Power Contract
Nebraska Public Power District Arapahoe 94-
L22-26
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
539 Wholesale Power Contract
Nebraska Public Power District Auburn 01-L22-
11
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
540 Wholesale Power Contract
Nebraska Public Power District Battle Creek 94-
L22-27
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
541 Wholesale Power Contract
Nebraska Public Power District Beatrice 94-L22-
29
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
542 Wholesale Power Contract
Nebraska Public Power District Bradshaw 94-
L22-30
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
543 Wholesale Power Contract
Nebraska Public Power District Brainard 94-L22-
31
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
544 Wholesale Power Contract
Nebraska Public Power District Central City 94-
L22-32
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
545 Wholesale Power Contract
Nebraska Public Power District Chester 94-L22-
34
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
546 Wholesale Power Contract
Nebraska Public Power District Cozad 94-L22-
35
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
547 Wholesale Power Contract
Nebraska Public Power District Davenport 94-
L22-36
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
548 Wholesale Power Contract
Nebraska Public Power District David City 94-
L22-37
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
549 Wholesale Power Contract
Nebraska Public Power District Deshler 01-L22-
9
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
550 Wholesale Power Contract
Nebraska Public Power District DeWitt 94-L22-
38
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
551 Wholesale Power Contract
Nebraska Public Power District Dorchester 94-
L22-39
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
552 Wholesale Power Contract
Nebraska Public Power District
Edgar 94-L22-40
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
553 Wholesale Power Contract
Nebraska Public Power District Fairmont 94-
L22-41
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
554 Wholesale Power Contract
Nebraska Public Power District Friend 94-L22-
42
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
555 Wholesale Power Contract
Nebraska Public Power District Giltner 94-L22-
44
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
556 Wholesale Power Contract
Nebraska Public Power District Gothenburg 94-
L22-45
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
557 Wholesale Power Contract
Nebraska Public Power District Hampton 94-
L22-46
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
558 Wholesale Power Contract
Nebraska Public Power District Hebron 94-L22-
47
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
559 Wholesale Power Contract
Nebraska Public Power District Hildreth 94-L22-
49
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
560 Wholesale Power Contract
Nebraska Public Power District Holdrege 94-
L22-50
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
561 Wholesale Power Contract
Nebraska Public Power District Lexington 94-
L22-51
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
562 Wholesale Power Contract
Nebraska Public Power District Lodgepole 94-
L22-52
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
563 Wholesale Power Contract
Nebraska Public Power District
Lyons 94-L22-54
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
564 Wholesale Power Contract
Nebraska Public Power District Madison 94-L22-
55
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
565 Wholesale Power Contract
Nebraska Public Power District Minden 954-L22-
56
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
566 Wholesale Power Contract
Nebraska Public Power District Nelson 94-L22-
58
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
567 Wholesale Power Contract
Nebraska Public Power District North Platte 94-
L22-60
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
568 Wholesale Power Contract
Nebraska Public Power District
Ord 94-L22-61
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
569 Wholesale Power Contract
Nebraska Public Power District
Polk 94-L22-62
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
570 Wholesale Power Contract
Nebraska Public Power District Prague 94-L22-
63
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
571 Wholesale Power Contract
Nebraska Public Power District Randolph 94-
L22-64
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
572 Wholesale Power Contract
Nebraska Public Power District Scribner 94-L22-
65
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
573 Wholesale Power Contract
Nebraska Public Power District Seward 94-L22-
66
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
574 Wholesale Power Contract
Nebraska Public Power District South Sioux City
94-L22-68
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
575 Wholesale Power Contract
Nebraska Public Power District Summerfield, KS
94-L22-69
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
576 Wholesale Power Contract
Nebraska Public Power District Superior 94-L22-
70
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
577 Wholesale Power Contract
Nebraska Public Power District Valentine 94-
L22-72
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
578 Wholesale Power Contract
Nebraska Public Power District Wahoo 01-L22-
14
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
579 Wholesale Power Contract
Nebraska Public Power District Wakefield 94-
L22-73
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
580 Wholesale Power Contract
Nebraska Public Power District Walthill 94-L22-
74
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
581 Wholesale Power Contract
Nebraska Public Power District Wauneta 94-
L22-75
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
582 Wholesale Power Contract
Nebraska Public Power District Wayne 94-L22-
76
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
583 Wholesale Power Contract
Nebraska Public Power District Webber, KS 94-
L22-77
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
584 Wholesale Power Contract
Nebraska Public Power District Wilcox 94-L22-
78
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
585 Wholesale Power Contract
Nebraska Public Power District Wymore 94-L22-
79
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
586 Wholesale Power Contract
Nebraska Public Power District
Nebraska Electric G&T 96-
L22-52
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
587 Wholesale Power Contract
Nebraska Public Power District Norris PPD 94-
L22-59
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
588 Wholesale Power Contract
Nebraska Public Power
District Southern PD 01-L22-25
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
589 Wholesale Power Contract
Nebraska Public Power
District Loup River PPD 05-L22-13
Full Requirements Wholesale Power
contract
Through 12-31-21; year to year thereafter; 5 yrs notice.
590 Oasis Transaction
Nebraska Public Power
District
Municipal EnergyAgency of
Nebraska (MEAN)
Point to Point 5/1/2014 3
Oasis Reservation
# 71396561
591 Oasis Transaction
Nebraska Public Power
District
Omaha Public Power District Point to Point 1/1/2023 12
Oasis Reservation # 1294460
592 Oasis Transaction
Nebraska Public Power
District
Omaha Public Power District Point to Point 1/1/2023 9
Oasis Reservation # 1294162
593 Oasis Transaction
Nebraska Public Power
District
Municipal EnergyAgency of
Nebraska (MEAN)
Point to Point 1/1/2021 23 Oasis
Reservation # 1282495
594 Oasis Transaction
Nebraska Public Power
District
Municipal EnergyAgency of
Nebraska (MEAN)
Point to Point 1/1/2017 10 Oasis
Reservation # 1063385
595 Oasis Transaction
Nebraska Public Power
District
Municipal EnergyAgency of
Nebraska (MEAN)
Point to Point 12/31/2014 7 Oasis
Reservation # 910527
596 Oasis Transaction
Nebraska Public Power
District
Municipal EnergyAgency of
Nebraska (MEAN)
Point to Point 1/1/2015 2 Oasis
Reservation # 883396
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
597 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power
District Point to Point 1/1/2021 4
Oasis Reservation # 192864
598 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power
District Point to Point 1/1/2021 3
Oasis Reservation # 191293
599 Oasis Transaction Nebraska
Public Power District
Lincoln Electric System Point to Point 1/1/2021 68
Oasis Reservation # 178304
600 Oasis Transaction Nebraska
Public Power District
Municipal EnergyAgency of Nebraska
(MEAN)
Point to Point 5/1/2014 7
Oasis Reservation
# 71287339
601 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power
District Point to Point 6/1/2029 150
Oasis Reservation # 1282622
602 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power
District Point to Point 6/1/2029 25
Oasis Reservation # 1282619
603 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power
District Point to Point 5/1/2029 30
Oasis Reservation # 784417
604 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power
Marketing Point to Point 5/1/2029 3
Oasis Reservation
# 72190701
605 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power
District Point to Point 1/1/2025 4
Oasis Reservation # 345442
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
606
NPPD Professional
Retail Operations Service
Agreements and Service Area Agreements
Nebraska Public Power
District
Nebraska Public Power
District
Full Requirements Wholesale contract,
Firm Network Service, Distribution
Services
Various Termination Dates Ranging From 12-31-14 to 7-1-32
With Renewal Rights
NPPD has PRO-
Service Agreements
with 81 Nebraska Municipals
Line No. Contract Title OASIS #
Selling Party Buying Party
FERC Schedule
Type of Service
Termination Provisions
607 Service Agreement and OASIS Reservation 1587762 OPPD Central MN Muni Pwr Assn Point-to-Point 5/1/2019
608 Service Agreement and OASIS Reservation 1587761 OPPD Central MN Muni Pwr Assn Point-to-Point 5/1/2019
609 Service Agreement and OASIS Reservation 1589101 OPPD Independence, MO Point-to-Point 5/1/2034
610 Service Agreement and OASIS Reservation 1585187 OPPD Lincoln Electric System Point-to-Point 1/1/2013
611 Service Agreement and OASIS Reservation 1585188 OPPD Lincoln Electric System Point-to-Point 1/1/2013
612 Service Agreement and OASIS Reservation 1585194 OPPD Lincoln Electric System Point-to-Point 5/1/2036
613 Service Agreement and OASIS Reservation 1585195 OPPD Lincoln Electric System Point-to-Point 5/1/2036
614 Service Agreement and OASIS Reservation 1585192 OPPD Lincoln Electric System Point-to-Point 3/1/2036
615 Nebraska City Unit 2 Transmission Facilities Cost Agreement
OPPD
NPPD, Independence, MO, Central Minnesota Municipal
Power Agency, Falls City, Grand Island, Missouri Joint
Muni Electric Utility Commission, Nebraska City
Planning and facilities cost arrangement
Until payment
and crediting
obligations are satisfied
616 Service Agreement and OASIS Reservation 1588942 OPPD Missouri Joint Municipal
Electric Utility Commission Point-to-Point 6/1/2029
617 Electric Interconnection and Interchange Agreement
Plattsmouth, Verden,
Nehawaka OPPD NPPD
Interconnection & Point-to-
Point
Pre-OATT. Effective
until cancelled w/ 4-yr notice
Line No. Contract Title OASIS #
Selling Party Buying Party
FERC Schedule
Type of Service
Termination Provisions
618 Amended and Restated Coordinating Agreement (MINT) & OASIS
OPPD
Associated Electric, Kansas City Power & Light, Aquila,
NPPD, OPPD, LES, MidAmerican Energy
Joint
ownership & Point-to-Point
Pre-OATT. Effective through 2040.
Thereafter cancellable by any party
w/ 4-yr notice
619 OASIS Reservation 1585185 OPPD NPPD Point-to-Point 1/1/2023
620 OASIS Reservation 1585186 OPPD NPPD Point-to-Point 1/1/2023
621 OASIS Reservation 1585627 OPPD NPPD Point-to-Point 6/1/2029
622 OASIS Reservation 1585630 OPPD NPPD Point-to-Point 6/1/2029
623 Service Agreement and OASIS Reservation 1585621 OPPD NPPD Point-to-Point 5/1/2029
624 Service Agreement and OASIS Reservation 1589750 OPPD NPPD Point-to-Point 5/1/2029
625 OASIS Reservation 1585595 OPPD Falls City Point-to-Point 5/1/2036
626 OASIS Reservation 1585604 OPPD Nebraska City Point-to-Point 5/1/2036
627 Reserved
628 OASIS Reservation 1585212 OPPD OPPD Point-to-Point 4/1/2010
629 OASIS Reservation 1585213 OPPD OPPD Point-to-Point 4/1/2010
630 OASIS Reservation 1585221 OPPD OPPD Point-to-Point 4/1/2010
631 OASIS Reservation 1585639 OPPD OPPD Point-to-Point 1/1/2014
632 OASIS Reservation 1585208 OPPD OPPD Point-to-Point 1/1/2014
633 OASIS Reservation 1585237 OPPD OPPD Point-to-Point 1/1/2014
634 OASIS Reservation 1585183 OPPD OPPD Point-to-Point 1/1/2014
Line No. Contract Title OASIS #
Selling Party Buying Party
FERC Schedule
Type of Service Termination Provisions
635 OASIS Reservation 1585209 OPPD OPPD Point-to-Point 1/1/2014
636 OASIS Reservation 1588919 OPPD OPPD Point-to-Point 1/1/2014
637 OASIS Reservation 1585196 OPPD OPPD Point-to-Point 1/1/2014
638 OASIS Reservation 1585214 OPPD OPPD Point-to-Point 4/1/2015
639 OASIS Reservation 1585219 OPPD OPPD Point-to-Point 4/1/2015
640 OASIS Reservation 73224364 OPPD OPPD Point-to-Point 4/1/2040
641 OASIS Reservation 1584795 OPPD OPPD Point-to-Point 9/9/2020
642 OASIS Reservation 1584797 OPPD OPPD Point-to-Point 9/9/2020
643 OASIS Reservation 1585174 OPPD OPPD Point-to-Point 1/1/2021
644 OASIS Reservation 1585182 OPPD OPPD Point-to-Point 9/1/2025
645 OASIS Reservation 1585607 OPPD OPPD Point-to-Point 9/1/2029
646 OASIS Reservation 1585605 OPPD OPPD Point-to-Point 9/1/2029
647 OASIS Reservation 1585606 OPPD OPPD Point-to-Point 9/1/2029
648 Reserved
Line No. Contract Title Selling
Party Buying Party
FERC Sch.
Type of Service
Termination Provisions Capacity (MW) OASIS
Reference
649 LES OASIS Reservation LES LES N/A Point to Point
Firm Service 1/1/2014 100 MW 71334119
650 LES OASIS Reservation LES LES N/A Point to Point
Firm Service 1/1/2030 50MW 72914267
651 LES OASIS Reservation LES LES N/A Point to Point
Firm Service 1/1/2010 50 MW 72589094
652
LES OASIS Reservation Bloomfield
Wind Turbines Purchase
(LES_ELKHORN_WT)
LES LES N/A Point to Point Firm Service 1/1/2029 6 MW 72403386
Line No. Contract Title Selling
Party Buying Party
FERC Sch.
Type of Service
Termination Provisions Capacity (MW) OASIS
Reference
653 LES OASIS Reservation LES LES N/A Point to Point
Firm Service 1/1/2011 50MW 72930573
654 LES OASIS Reservation LES LES N/A Point to Point
Firm Service 1/1/2035 24 MW 72977186
655 LES OASIS Reservation LES LES N/A Point to Point
Firm Service 1/1/2035 20MW 72977175
656
Bulk Transmission System Loss Factor
Agreement (NPPD and LES)
LES LES N/A
Return of BTS Losses from
LES to NPPD according to BTS Loss
Compensation Calculation Procedure
Term and Amount varies
with LES & NPPD
Transmission and Power Supply
Contracts termination dates
15 MW 1589036
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
657
Transmission Service Agreement Between
Nebraska Public Power District and City of Deshler, Nebraska
Nebraska Public Power
District City of Deshler Network Service
Co-Term with City's WAPA
Allocation Contract
658
Transmission Service Agreement Between
Nebraska Public Power District and City of
Emerson , Nebraska
Nebraska Public Power
District City of Emerson Network Service
Co-Term with City's WAPA
Allocation Contract
659
Transmission Service Agreement Between
Nebraska Public Power District and City of Laurel, Nebraska
Nebraska Public Power
District City of Laurel Network Service
Co-Term with City's WAPA
Allocation Contract
660
Transmission Service Agreement Between
Nebraska Public Power District and City of Madison, Nebraska
Nebraska Public Power
District City of Madison Network Service
Co-Term with City's WAPA
Allocation Contract
661
Transmission Service Agreement Between
Nebraska Public Power District and City of Mullen, Nebraska
Nebraska Public Power
District City of Mullen Network Service
Co-Term with City's WAPA
Allocation Contract
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
662
Transmission Service Agreement Between
Nebraska Public Power District and City of Neligh, Nebraska
Nebraska Public Power
District City of Neligh Network Service
Co-Term with City's WAPA
Allocation Contract
663
Transmission Service Agreement Between
Nebraska Public Power District and City of
Randolph, Nebraska
Nebraska Public Power
District City of Randolph Network Service
Co-Term with City's WAPA
Allocation Contract
664
Transmission Service Agreement Between
Nebraska Public Power District and City of
Schuyler, Nebraska
Nebraska Public Power
District City of Schuyler Network Service
Co-Term with City's WAPA
Allocation Contract
665
Transmission Service Agreement Between
Nebraska Public Power District and City of South Sioux City,
Nebraska
Nebraska Public Power
District
City of South Sioux City Network Service
Co-Term with City's WAPA
Allocation Contract
666
Transmission Service Agreement Between
Nebraska Public Power District and City of Wahoo, Nebraska
Nebraska Public Power
District City of Wahoo Network Service
Co-Term with City's WAPA
Allocation Contract
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
667
Transmission Service Agreement Between
Nebraska Public Power District and City of
Wakefield, Nebraska
Nebraska Public Power
District City of Wakefield Network Service
Co-Term with City's WAPA
Allocation Contract
668
Transmission Service Agreement Between
Nebraska Public Power District and City of Wilber, Nebraska
Nebraska Public Power
District City of Wilber Network Service
Co-Term with City's WAPA
Allocation Contract
669
Generator Interconnection
Agreement Between Community Wind
Energy Transmission, LLC and Nebraska
Public Power District
Nebraska Public Power
District
Community Wind Energy
Transmission, LLC
Generator Interconnection Until Terminated
670 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 80 Oasis
Reservation # 1298924
671 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 15
Oasis Reservation # 1299178
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service
Termination Provisions
Capacity (MW) Other
672 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency
of Nebraska (MEAN)
Point to Point 35 Oasis
Reservation # 1299182
673 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency
of Nebraska (MEAN)
Point to Point 10 Oasis
Reservation # 1299186
674
Oasis Transaction HCPD Participation in
WEC2 (NPPD.HCPD.WEC2 to WAUE.HCPD.NTWK)
Nebraska Public Power
District
Municipal Energy Agency
of Nebraska (MEAN) HCPD
Point to Point80 MW
NPPD Monthly Firm PTP
Through 12/31/2031 with
rollover provisions thereafter
80 Oasis
Reservation # 12991891587829
675 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 81
Oasis Reservation #
71792232
676 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 42
Oasis Reservation #
71792980
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
677 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 71
Oasis Reservation
# 72062051
678 Oasis Transaction Nebraska
Public Power District
Lincoln Electric System Point to Point 6
Oasis Reservation
# 72403321
679 Oasis Transaction Nebraska
Public Power District
Omaha Public Power District Point to Point 25
Oasis Reservation
# 72426676
680 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 4
Oasis Reservation
# 72426730
681 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 8 Oasis
Reservation # 72426734
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
682 Oasis Transaction Nebraska
Public Power District
GrandIsland Point to Point 1 Oasis
Reservation # 72441570
683 Oasis Transaction Omaha Public Power District
Nebraska Public Power District Point to Point 175
Oasis Reservation
# 72589960
684 Oasis Transaction Nebraska
Public Power District
Lincoln Electric System Point to Point 50
Oasis Reservation
# 72590096
685 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 50
Oasis Reservation
# 72672357
686 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 25
Oasis Reservation # 72672520
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
687 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 25
Oasis Reservation # 72672703
688 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 80
Oasis Reservation # 72797870
689 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 80
Oasis Reservation # 72797894
690 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 65
Oasis Reservation
# 72830114
691 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 65
Oasis Reservation # 72830126
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
692 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 50
Oasis Reservation # 72959986
693 Oasis Transaction Nebraska
Public Power District
Nebraska Public Power District Point to Point 106
Oasis Reservation
# 72970088
694 Oasis Transaction Nebraska
Public Power District
Lincoln Electric System Point to Point 47
Oasis Reservation 72979719
695 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 20
Oasis Reservation
SPP# 1589027
696 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 20
Oasis Reservation
SPP# 1589028
Line No. Contract Title Selling Party Buying Party FERC
Sch. Type of Service Termination Provisions
Capacity (MW) Other
697 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 55
Oasis Reservation
SPP# 1589029
698 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 95
Oasis Reservation
SPP# 1589031
699 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 16
Oasis Reservation
SPP# 1589034
700 Oasis Transaction Nebraska
Public Power District
Lincoln Electric System Point to Point 15
Oasis Reservation
SPP# 1589037
701 Oasis Transaction Nebraska
Public Power District
Municipal Energy Agency of Nebraska (MEAN)
Point to Point 10
Oasis Reservation
SPP# 1589038
Line No. Contract Title OASIS # Selling Party Buying Party
FERC Schedule
Type of Service Termination Provisions
702 OASIS Reservation 1588927 OPPD OPPD Monthly Point-to-
Point 1/1/2014
703 OASIS Reservation 1588919 OPPD OPPD Monthly Point-to-
Point 1/1/2014
704 OASIS Reservation 1585179 OPPD OPPD Yearly Network 1/1/2037
705 OASIS Reservation 1585180 OPPD OPPD Yearly Network 1/1/2037
706 OASIS Reservation 1585225 OPPD OPPD Monthly Point-to-
Point 1/1/2040
707 OASIS Reservation 1585243 OPPD OPPD Monthly Point-to-
Point 1/1/2040
708 OASIS Reservation 1585244 OPPD OPPD Yearly Network 1/1/2037
709 OASIS Reservation 1585245 OPPD OPPD Yearly Network 1/1/2037
710 OASIS Reservation 1585564 OPPD OPPD Yearly Network 1/1/2013
711 OASIS Reservation 1585565 OPPD OPPD Monthly Point-to-
Point 1/1/2014
Line No. Contract Title OASIS # Selling Party Buying Party
FERC Schedule
Type of Service Termination Provisions
712 OASIS Reservation 1585567 OPPD OPPD/Nebraska City Utilities
Yearly Point-to-
Point 5/1/2014
713 OASIS Reservation 1585574 OPPD OPPD Monthly Point-to-
Point 1/1/2040
714 OASIS Reservation 1585576 OPPD OPPD Monthly Point-to-
Point 1/1/2029
715 OASIS Reservation 1585579 OPPD OPPD Monthly Point-to-
Point 1/1/2030
716 OASIS Reservation 1585588 OPPD OPPD Yearly Network 1/1/2037
717 OASIS Reservation 1585622 OPPD NPPD Monthly Point-to-
Point 6/1/2009
718 OASIS Reservation 1588958 OPPD OPPD Monthly Point-to-
Point 1/1/2040
719 OASIS Reservation 1588959 OPPD OPPD Monthly Point-to-
Point 1/1/2040
720 OASIS Reservation 1589052 OPPD OPPD Monthly Point-to-
Point 1/1/2014
Line No. Contract Title OASIS # Selling Party Buying Party
FERC Schedule
Type of Service Termination Provisions
721 OASIS Reservation 1589054 OPPD OPPD Daily
Point-to-Point
10/1/2009
722 OASIS Reservation 1589060 OPPD OPPD Monthly Point-to-
Point 1/1/2040
723 OASIS Reservation 1589065 OPPD OPPD Monthly Point-to-
Point 1/1/2014
724 OASIS Reservation 1589070 OPPD OPPD Monthly Point-to-
Point 7/1/2010
725 Service Agreement and OASIS Reservation 1589102 OPPD Independence, MO
Monthly Point-to-
Point 1/1/2040
726 Service Agreement and OASIS Reservation 1589103 OPPD Independence, MO
Monthly Point-to-
Point 1/1/2014
727 Service Agreement and OASIS Reservation 1589110 OPPD Municipal Energy Agency
of Nebraska Monthly Point-to-
Point 1/1/2031
728 OASIS Reservation 1594743 OPPD OPPD Monthly Point-to-
Point 4/1/2040
729 OASIS Reservation 1594744 OPPD OPPD Monthly Point-to-
Point 4/1/2040
730 OASIS Reservation 1594748 OPPD OPPD Monthly Point-to-
Point 9/1/2040
731 OASIS Reservation 1603144 OPPD OPPD Monthly Point-to-
Point 1/1/2014
732 OASIS Reservation 73224372 OPPD OPPD/Falls City Yearly
Point-to-Point
5/1/2036
Line No. Contract Title OASIS # Selling Party Buying Party
FERC Schedule
Type of Service
Termination Provisions
733
Joint Operating Agreement
1256070
SPS/PSCo
PSCo/SPS
FERC
Orders in Docket Nos.
EC96-2, ER96-2572-000, EC99-
101-000, ER04-1174-000 et al.,
and ER-08-313-000, et
al.
Transmission Service
implementing the Xcel Energy
Operating Companies’
Joint Operating Agreement
None
734
Network Integration Transmission Service
Agreement
1089911
SPS
Municipal Energy Agency of Nebraska
FERC orders in
Docket Nos. ER04-1174-
000 et al. and ER08-313-000, et
al.
Network Integration
Transmission Service
Through June 1, 2020 with rollover
provisions thereafter
Line No. Contract Title Selling Party Buying Party FERC Rate
Schedule No. Type of Service Termination Provisions
735 City of Coffeyville Grand River Dam
Authority Grand River Dam
Authority Point To Point
Through 1/1/2035 with rollover provisions
thereafter
736 WFEC/BANK Western Farmers Electric Company
Western Farmers Electric Company Point To Point
Through 1/1/2035 with rollover provisions
thereafter
737 WFEC/BANK Western Farmers Electric Company
Western Farmers Electric Company Point To Point
Through 1/1/2035 with rollover provisions
thereafter
738
Interchange Agreement
(AmerenUE) Kansas City Power &
Light AMRN 104, Supp. No. 5
to Sched. G Point To Point Year to year, 30 mo. Notice
Proposed Market Protocol Language Revision (Redlined) n/a
Proposed Business Practices Language Revision (Redlined)
n/a
Proposed Criteria Language Revision (Redlined) n/a
Revisions to Other Corporate Documents (Redlined)
n/a
RTWG TRR 096 Recommendations to MOPC 7 16-17 2013.docx Page 1 of 2
Southwest Power Pool, Inc.
MARKET AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors
TRR 096
July 29-30, 2013
Organizational Roster The following persons are members of the Regional Tariff Working Group:
Dennis Reed, WR (Chair) Charles Locke, KCPL (Vice-Chair) Richard Andrysik, LES Bill Dowling, Midwest Energy Luke Haner, OPPD Tom Hestermann, Sunflower Rob Janssen, Dogwood David Kays, OGE Lloyd Kolb, Golden Spread David Linton, ITC Great Plains Tom Littleton, OMPA Bernie Liu, Xcel
Paul Malone, NPPD Adam McKinnie, MoPSC Robert Pennybaker, AEP Neil Rowland, KMEA Robert Shields, AECC Keith Tynes, ETEC John Varnell, Tenaska Bary Warren, EDE Mitch Williams, WFEC Brenda Fricano, SPP (Staff Secretary)
Background Please see the TRR Recommendation Report for TRR 096 that were included in the MOPC July 16-17, 2013 background materials.
Analysis Please see the TRR Recommendation Report for TRR 096 that were included in the MOPC July 16-17, 2013 background materials.
Recommendation The MOPC recommends that the BOD approve its request regarding TRR 096.
Action Requested: Approval of RTWG’s request on TRR 096.
APPROVED: MOPC July 16-17, 2013
Approved Unanimously
RTWG TRR 096 Recommendations to MOPC 7 16-17 2013.docx Page 2 of 2
TRR Number
Description RTWG Meeting Vote
091
Proposed changes to the Aggregate Transmission Service Study process to allow SPP to close out the backlog of transmission service studies in conjunction with the implementation of the ATSS improvements that have been approved for MOPC’s review at its April 2013 meeting.
June 27, 2013
Approved unanimously
096
1. Bilateral Settlement Schedules: Revisions are suggested for provisions of Attachment AE regarding Bilateral Settlement Schedules. The addition of language to Section 8.2 is recommended to clarify that the Bilateral Settlement Schedules are tied to the physical capabilities of the system (i.e., are directly connected to the physical transfer of electricity and involve transactions in which title changes hands). 2. Notice Requirements for Information Requests: Revisions are suggested to Section 1.1 of Attachment AE to add a definition for the CFTC and to Section 11 (including subsections) of Attachment AE to remove requirements that SPP notify members if it provides their information to the CFTC and to clarify that SPP may provide member’s confidential information to the CFTC without prior consent. Research is ongoing regarding the FERC's requirements in the same context, and some additional revisions may be required to confirm terminology and whether some existing provisions are intended to include references to the FERC. 3. Minimum Financial Eligibility: Potential revisions to the SPP Tariff are described to address the minimum capitalization requirements for market participants as imposed by the Dodd-Frank legislation and the CFTC's April 2013 Order. While discussions with the CFTC are ongoing and may result in additional changes, revisions are suggested to Attachment X, Section 3.1.1.8 “Minimum Criteria for Participation” to move most of the current contents of the section to a new section 3.1.1.8.1 “Minimum Capitalization Requirements” and to add a new section 3.1.1.8.2 “Eligibility Requirements” that states the eligibility requirements set forth by the CFTC. Some corresponding revisions in other portions of Attachment X are described for consistency and to ensure that SPP is adequately protected and would be found in compliance with the exemption requirements.
July 3, 2013
Approved with one abstention (OPPD)
Tariff Revision Request (TRR)
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TRR Number 096 TRR
Title Revisions to Qualify for Exemption from Jurisdiction of the Commodity Futures Trading Commission
Cross Reference # PRR BRR Other (Specify) _ _____________
Sponsor Name Joe Ghormley, Senior Attorney E-mail Address [email protected] Company Southwest Power Pool, Inc. Phone Number (501) 614-3368 Date June 13, 2013 (revised July 2, 2013)
Tariff Section(s) Requiring Revision
Section No. Attachments AE and X Title Tariff Version (effective date)
Requested Resolution
Normal Urgent (provided justification below for urgent request) Urgent consideration is needed due to the CFTC's required changes to minimum financial eligibility criteria for market participants. The updated minimum eligibility criteria should be considered in the July 2013 Board of Directors meeting so they will be in place by this fall's TCR Auction.
Revision Description
1. Bilateral Settlement Schedules: Revisions are suggested for provisions of Attachment AE regarding Bilateral Settlement Schedules. The addition of language to Section 8.2 is recommended to clarify that the Bilateral Settlement Schedules are tied to the physical capabilities of the system (i.e., are directly connected to the physical transfer of electricity and involve transactions in which title changes hands). 2. Notice Requirements for Information Requests: Revisions are suggested to Section 1.1 of Attachment AE to add a definition for the CFTC and to Section 11 (including subsections) of Attachment AE to remove requirements that SPP notify members before it provides their information to the CFTC and to clarify that SPP may provide member’s confidential information to the CFTC without prior consent. 3. Minimum Financial Eligibility: Revisions to the SPP Tariff are described to address the minimum eligibility requirements for market participants as imposed by the Dodd-Frank legislation and the CFTC's April 2013 Order. While discussions with the CFTC are ongoing and may result in additional changes, revisions are
Tariff Revision Request (TRR)
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suggested to Attachment X, Section 3.1.1.8 “Minimum Criteria for Participation” to move most of the current contents of the section to a new section 3.1.1.8.2 (“Minimum Capitalization Requirements”) and to add a new section 3.1.1.8.1 (“Minimum Eligibility Requirements”) that states the eligibility requirements set forth by the CFTC. Some corresponding revisions in other portions of Attachment X are described for consistency and to ensure that SPP is adequately protected and would be found in compliance with the exemption requirements.
Reason for Revision Certain conditions must be satisfied for an RTO to qualify for exemption of specified RTO transactions from regulation under the Commodity Exchange Act (“CEA”) (as amended by the 2010 Dodd-Frank legislation) and associated regulations of the CFTC.
Stakeholder Approval Required (specify date and record outcome of vote; n/a for those stakeholders not required)
MWG BPWG (n/a) TWG (n/a) ORWG (n/a) Other (specify) (n/a) RTWG – 07/02/2013 – Approved with One Abstention - OPPD MOPC Board of Directors
Legal Review Completed
Yes (Include any comments resulting from the review)
No [Legal Review is ongoing as discussions with CFTC that could impact details of revisions continue.]
Market Protocol Implications or Changes
Yes (Include a summary of impact and/or specific changes & PRR #)
No
Business Practice Implications or Changes
Yes (Include a summary of impact and/or specific changes & BPR #)
No
Tariff Revision Request (TRR)
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Criteria Implications or Changes
Yes (Include a summary of impact and/or specific changes)
No Other Corporate Documents Implications (i.e., SPP By-Laws, Membership Agreement, etc.)
Yes (Include which corporate documents)
No
Credit Implications
Yes (Include a summary of impact and/or specific changes) Qualifying for the exemption from CFTC jurisdiction requires modifications to SPP's minimum capitalization/financial eligibility requirements as set forth in Attachment X (SPP Credit Policy)
No
Impact Analysis Required
Yes
No
Tariff Revision Request (TRR)
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Proposed Tariff Language Revisions (Redlined)
Proposed Revisions to Attachment AE Regarding Bilateral Settlement Schedules
1.1 Definitions B
Bilateral Settlement Schedule An arrangement between two Market Participants for transfer of Energy or Operating Reserve obligations.
* * *
8.2 Bilateral Settlement Schedules
Market Participants may create Bilateral Settlement Schedules for Energy and Operating
Reserve obligations by registering and confirming the parameters of the agreement between buyer
and seller as described in the Market Protocols. Both the buyer and seller must confirm the
Bilateral Settlement Schedule. Either the buyer or seller may terminate the Bilateral Settlement
Schedule at any time. In addition, the Transmission Provider may terminate the Bilateral
Settlement Schedule if either party is in Default and the Transmission Provider will resettle with
Market Participants as if the Bilateral Settlement Schedule did not exist.
Market Participants may submit Bilateral Settlement Schedule quantities for Energy and
Operating Reserve obligation for use in the Day-Ahead Market and may submit Bilateral
Settlement Schedule quantities for Energy for use in the Real-Time Balancing Market up to four
(4) days following the applicable Operating Day for the initial settlement. New submittals and
revisions to previously submitted values may be submitted up to forty-four (44) days following the
applicable Operating Day to be included in the final settlement. Submittals not confirmed by both
parties will not be included in any settlement execution.
Transactions related to Bilateral Settlement Schedules for Energy must specify the
Settlement Location, the MW amount, the buyer, the seller and which market it applies to (Day-
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Ahead Market or RTBM), and must be for the physical transfer of Energy, with title of the energy
transferring from the seller to the buyer at the Settlement Location specified for the transaction.
Market Participants that submit Bilateral Settlement Schedules for Energy shall use reasonable
efforts to limit the megawatt hours of such transactions to amounts reflecting the expected load
and other physical delivery obligations of the buyer under the bilateral contract. The seller
receives an increase in load obligation equal to the specified MW amount and the buyer receives a
reduction in load obligation equal to the specified MW amount (the equivalent of a Resource
settlement) at the specified Settlement Location.
Transactions related to Bilateral Settlement Schedules for Operating Reserve obligation
must specify the buyer, the seller, the Operating Reserve product, the MW obligation transfer and
the Reserve Zone within which the obligation transfer applies and must be for the physical transfer
of energy associated with the Operating Reserve product, with title of the Operating Reserve
product transferring from the seller to the buyer at the Reserve Zone specified for the transaction.
The seller receives an increase in Operating Reserve obligation equal to the specified MW and the
buyer receives a corresponding decrease in Operating Reserve obligation within the specified
Reserve Zone.
-------------------------------------------------------------------------------------------------
Proposed Revisions to Attachment AE Regarding Modification of Notice Requirements
Following Receipt of an Information Request from a Regulatory Agency
1.1 Definitions C
CFTC
The Commodity Futures Trading Commission
11.0 Confidentiality Provisions
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This Section 11 shall apply to Confidential Information disclosed by a Market Participant
to the Transmission Provider or by the Transmission Provider to a Market Participant or its
designee, the Market Monitor, the Commission, the CFTC, or an Authorized Requestor and shall
only be applicable to Confidential Information referenced within this Attachment AE, Attachment
AF and Attachment AG.
11.1.5 Required Disclosure
(1) Notwithstanding anything in this Section 11 to the contrary except Section 11.2, Section
11.3 and Section 11.4, if a Receiving Party is required by applicable law, or in the course
of administrative or judicial proceedings, other than Commission, CFTC, or state
regulatory proceedings or investigations, to disclose to third parties, other than to the
Commission, the CFTC, or their its staffs, Confidential Information that is otherwise
required to be maintained in confidence pursuant to this Tariff, the Receiving Party subject
to such disclosure requirement may disclose such information; provided, however, that the
Receiving Party shall not release the data until the affected Disclosing Party(ies) provide
written consent or until the affected Disclosing Party's(ies') legal avenues to prevent the
disclosure are exhausted. As soon as the Receiving Party learns of the disclosure
requirement and prior to making disclosure, it shall notify the affected Disclosing
Party(ies) of the requirement and the terms thereof and the date on which it may be
required to disclose the information. The affected Disclosing Party(ies) may direct, at their
sole discretion and cost, any challenge to or defense against the disclosure requirement.
The Receiving Party shall cooperate with such affected Disclosing Party(ies) to the
maximum extent practicable to minimize the disclosure of the Confidential Information
consistent with applicable law. To the extent reasonably possible, the confidentiality of
Confidential Information subject to this Section 11.1.5 will be maintained with (a) a
protective order, (b) other procedures available for protecting confidential data or (c) by
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aggregating data to prevent disclosure of Confidential Information. Each Receiving Party
shall cooperate with the affected Disclosing Party(ies) to obtain proprietary or confidential
treatment of such Confidential Information by the person to whom such information is
disclosed prior to any such disclosure.
(2) Section 11.1.5(1) does not apply to disclosure of information to the Commission or its
staff, the CFTC or its staff, or to a state regulator or its staff.
11.1.6 Limitations
Nothing contained in Section 11.1 through and including Section 11.1.5 shall require any
Receiving Party to violate any law or file a lawsuit in order to prevent disclosure of Confidential
Information.
11.2 Confidentiality Provisions Applicable to the Market Monitor Reporting to the Board of Directors
For the purposes of this Section 11.2, references to the Market Monitor shall mean the
Market Monitor as defined under Section 3.1 of Attachment AG.
(1) Notwithstanding anything in this Section 11 to the contrary, in order to enable the Market
Monitor to discharge its duties, the Transmission Provider is authorized to provide Market
Participant Confidential Information and any other information, data or materials that
constitutes Confidential Information under this Tariff to the Market Monitor. For purposes
of Confidential Information provided by the Transmission Provider to the Market Monitor,
the Transmission Provider will be considered to be a Disclosing Party, and for purposes of
this Section 11.2, the Market Monitor will treat both the Transmission Provider and, if
known to the Market Monitor, the Market Participant originally providing specific
Confidential Information as Disclosing Parties in the event the Market Monitor receives a
request for Confidential Information under this Section 11.2.
(2) The Market Monitor shall use all reasonable procedures necessary to protect and preserve
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the confidentiality of all Confidential Information as defined in Section 11.1 received by it
in connection with the discharge of its duties.
(3) Except as may be required by subpoena or other compulsory process or as set forth in
Sections 11.3(1) and 11.3(2), the Market Monitor shall not disclose Confidential
Information to any person or entity except to the Commission or its staff or the CFTC or
its staff, without prior written consent. Upon receipt of a subpoena or other compulsory
process from a source other than the CFTC or its staff for the disclosure of Confidential
Information, the Market Monitor shall promptly notify the affected Disclosing Party(ies)
that originally provided the data and shall provide all reasonable assistance requested by
the affected Disclosing Party(ies) to prevent disclosure, and if possible under the terms of
the subpoena or other compulsory process shall not release the data until the affected
Disclosing Party(ies) provide written consent or until the affected Disclosing Party(ies’)
legal avenues to prevent disclosure are exhausted. To the extent reasonably possible, the
confidentiality of Confidential Information subject to this Subsection 11.2(2) will be
maintained with (i) a protective order, (ii) other procedures available for protecting
confidential data, or (iii) by aggregating data to prevent disclosure of Confidential
Information.
11.3 Disclosure to Commission or CFTC
(1) Notwithstanding any provisions of this Section 11 to the contrary, if the Commission or
CFTC or their respective staffs, during the course of an investigation or otherwise,
requests Confidential Information from the Transmission Provider and/or the Market
Monitor that is otherwise required to be maintained in confidence pursuant to this Tariff,
the Transmission Provider and/or the Market Monitor, as applicable shall provide the
requested information to the Commission, CFTC, or their respective its staffs within the
time provided for in the request for information. Should the Transmission Provider and/or
the Market Monitor require additional time to provide the information requested due to
logistical matters such as the volume of information requested or technical complexity
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involved, the Transmission Provider and/or the Market Monitor will promptly
communicate that need to the entityindividual requesting the information and theyshall
establish the time for production of the requested information.
(2) In providing the information to the Commission or its staff, the Transmission Provider and
the Market Monitor shall, consistent with 18 C.F.R. §§ 1b.20 and/or 388.112, request that
the Confidential Information be treated as confidential and non-public by the Commission
and its staff and that the Confidential Information be withheld from public disclosure. The
Transmission Provider and/or the Market Monitor shall promptly notify the affected
Disclosing Party(ies) that originally submitted the requested Confidential Information
when it receives from the Commission or its staff a request for disclosure of Confidential
Information.
(3) In providing the information to the CFTC or its staff, the Transmission Provider and the
Market Monitor shall, consistent with 17 C.F.R §§ 11.3 and 145.9, request that the
Confidential Information be treated as confidential and non-public by the CFTC and its
staff and that the Confidential Information be withheld from public disclosure. If the
Transmission Provider and/or the Market Monitor receives notice from the CFTC or its
staff that Confidential Information provided by the Transmission Provider and/or the
Market Monitor is to be released, it shall promptly notify the affected Disclosing Party(ies)
in order to afford the affected Disclosing Party(ies) an opportunity to respond before such
information would be made public.
11.6 Notice
Notwithstanding any provision in this Section 11 (except as detailed in Section 11.4), the
Transmission Provider shall provide at least five (5) business days notice to the Disclosing Party
of its intent to provide Confidential Information to any other entity other than the CFTC or its
staff. The Transmission Provider shall not be required to provide such notice if such disclosure is
prohibited by law or Order or required by law or Order prior to five (5) business days.
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-------------------------------------------------------------------------------------------------
Proposed Revisions to Attachment X Regarding Modification of Financial Eligibility Criteria
ATTACHMENT X
SOUTHWEST POWER POOL, INC. CREDIT POLICY
ARTICLE ONE
General Provisions
1.1 Policy Statement. In furtherance of competition and the orderly administration of the Tariff, Southwest Power Pool (“SPP”) shall administer, implement and enforce this Credit Policy. This Credit Policy is intended to encourage the maximum participation of large and small participants in all market sectors while minimizing the likelihood of losses due to default and to establish eligibility requirements for market participation.
1.2 Applicability of Credit Policy and Overview.
1.2.1 This Credit Policy is applicable to each Credit Customer. It applies to each Credit
Customer regardless of whether SPP previously extended credit to, or established a Total Credit Limit for, the Credit Customer. .
1.2.2 As a condition to taking any service subject to this Credit Policy, SPP must
determine that the Credit Customer satisfies SPP’s credit requirements and minimum criteria for market participation under this Credit Policy and the terms and conditions for an extension of credit. SPP’s determination is a Credit Assessment. The Credit Assessment is based upon quantitative and qualitative credit scoring under the formulae and procedures set forth in this Credit Policy. This Credit Policy provides for initial and ongoing Credit Assessments. In order to facilitate continuous evaluation of credit, it requires the submission of Credit Information to SPP periodically and, additionally, upon the occurrence of certain events. Based upon the ongoing Credit Assessment, SPP is authorized, at any time, to revise a Credit Customer’s Total Credit Limit and the terms and conditions for the extension of credit.
1.2.3 SPP shall conduct initial and ongoing Credit Assessments for each Credit
Customer, based, as applicable, upon the Credit Application, Credit Information,
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and Credit Ratings. Credit Information includes: (a) the information contained in and submitted with the Credit Customer’s duly executed Credit Application; and (b) updated and additional information the Credit Customer is required to submit from time to time under this Credit Policy. Credit Information and Credit Ratings, if any, shall be sufficient to enable SPP to determine under this Credit Policy whether to approve an extension of credit, and the amount, terms, and conditions thereof, including the extent and nature of any Guaranty or Financial Security.
1.2.4 Based upon its Credit Assessment, SPP will: (a) determine the Credit Customer’s
Total Potential Exposure; (b) determine the amount of credit the Credit Customer requires; (c) determine whether to grant, and the amount of, any Unsecured Credit Allowance; (d) evaluate any Guaranty the Credit Customer offers to provide, including a Credit Assessment for the proposed Guarantor; and (e) determine the amount of any required Financial Security; and (f) determine if the Credit Customer meets the minimum criteria for market participation under Sections 3.1.1.8 and 3.1.1.9. Based on these determinations, which shall include consideration of the Credit Customer’s ability to fulfill SPP’s requirements to obtain credit, SPP will set the Total Credit Limit for the Credit Customer.
1.3 Components of Credit Policy. This Credit Policy includes the following elements:
1.3.1 Requirements for the establishment and maintenance of credit applicable to Credit Customers.
1.3.2 The basis for establishing a Total Credit Limit for a Credit Customer in order to
extend credit, but diminish the possibility of failure of payment under the Tariff and Agreements.
1.3.3 Forms of Guaranty and Financial Security acceptable to SPP, to be provided if SPP
does not approve an Unsecured Credit Allowance sufficient to cover the Credit Customer’s Total Potential Exposure.
1.3.4 Requirements to facilitate ongoing Credit Assessments. 1.3.5 Specification of Defaults under this Credit Policy and remedies. 1.3.6 Minimum criteria for market participation. 3.1.1.6 Attestation of Minimum Criteria for Market Participation and Risk
Management Capabilities. Each applying Market Participant shall submit to SPP a notarized statement signed by an authorized officer in the form
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attached as “Appendix E” to this Attachment X: a. Attesting that the officer has signature authority to make the
statement; b. Describing its risk management capabilities and procedures,
including whether the applying Market Participant is engaged in hedging;
c. Identifying the employee(s) of the Market Participant who perform the activities described in (b) above, or if those activities are contracted to an external organization, identifying such organization;
d. Defining the special training, skills, experience, and industry tenure of those person(s) performing the activities described in (b) above; and
e. Providing any other information that may assist SPP in determining the risk management capabilities of the applying Market Participant;. and
f. Certifying that the Market Participant meets the minimum criteria for market participation set forth in Section 3.1.1.8.
Such attestation shall be renewed and updated for each successive year of market participation, and shall be submitted to SPP no later than April 30 of each year.
The applying Market Participant shall be declined participation in all SPP markets Iif: (i) the risk management capabilities of the applying Market Participant are deemed insufficient by SPP for the type of service that will be undertaken, or(ii) SPP determines that the applying Market Participant does not meet the minimum criteria for market participation, (iii) the attestation is deemed insufficient by SPP to determine the risk management capabilities of the applying Market Participant, or (iv) the attestation is deemed insufficient by SPP to determine whether the applying Market Participant meets the minimum criteria for market participation. AAn applying Market Participant will have two (2) Business Days from receipt of notice from SPP that its attestation was deemed insufficient to cure any deficiency identified by SPP prior to being declined participation in SPP markets.
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3.1.1.8 Minimum Criteria for Market Participation.
3.1.1.8.1 Minimum Eligibility Requirements
In order to be eligible to transact in the Integrated Marketplace, each Market Participant must demonstrate to SPP that it qualifies as one of the following:
a. An “appropriate person,” as defined under Section 4(c)(3)(A)
through (J) of the Commodity Exchange Act (7 U.S.C. § 6(c)(3)(A) through (J)). A Market Participant may qualify as an “appropriate person” by providing: (i) an unlimited Corporate Guaranty in a form acceptable to SPP as described in Article 6 of this Attachment X and Appendix D of this Attachment X from an entity that demonstrates to SPP that it has in excess of $1 million of total net worth or in excess of $5 million of total assets per Market Participant for which that guarantor has issued an unlimited Corporate Guaranty, or (ii) a letter of credit in excess of $5 million in a form acceptable to SPP that the Market Participant acknowledges is separate from, and cannot be applied to meet, its credit requirements under this Attachment X., which includes, for example:
b. An “eligible contract participant,” as defined in Section 1a(18) of the Commodity Exchange Act (7 U.S.C. § 1a(18)) and in the Commodity Futures Trading Commission’s regulation 1.3(m) (17 C.F.R. § 1.3(m))
c. A person or entity that is in the “business of:; (1) generating,
transmitting or distributing electric energy or (2) providing electric services that are necessary to support the reliable operation of the transmission system” (78 Fed. Reg. 19880, page 19914).
If a Market Participant is unable to meet the minimum eligibility requirements for market participation set forth in this Section 3.1.1.8.1, the Market Participant shall immediately notify SPP and immediately cease conducting transactions in the Integrated Marketplace. When SPP receives such notification from a Market Participant or determines that a Market Participant does not meet the minimum eligibility requirements set forth in
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this Section 3.1.1.8.1, SPP shall immediately terminate that Market Participant’s transaction rights in the Integrated Marketplace.
In the event that a Market Participant is no longer able to demonstrate that it meets the minimum eligibility requirements set forth in this Section 3.1.1.8.1, and possesses, obtains, or has rights to possess or obtain any open or forward position in the Integrated Marketplace, SPP may take any action it deems necessary with respect to such open or forward positions. Such action may include but is not limited to, liquidation, transfer, assignment, or sale. The Market Participant will be entitled to any positive market value of such positions, net of any obligations due to SPP, notwithstanding its ineligibility to participate in the Integrated Marketplace. Nothing in this paragraph shall restrict SPP's ability to enforce SPP's rights to pursue and collect any amounts Market Participants may owe to SPP.
3.1.1.8.2 Minimum Capitalization Requirements Each Market Participant that meets the minimum eligibility requirements in Section 3.1.1.8.1 shall also, at a minimum, possess:
a. A Tangible Net Worth of One Million Dollars ($1,000,000) as shown in the most recent fiscal year end audited financial statements as described in Section 3.1.1.1; or
b. Ten Million Dollars ($10,000,000) in assets as shown in the most recent fiscal year end audited financial statement as described in Section 3.1.1.1; or
c. A Credit Rating of, or equivalent to, BBB-; or d. A Guaranty as described in Article Six of this Attachment X,
and approved by SPP, through which the audited financials or Credit Rating of the Guarantor is used to meet at least one of the alternatives specified in (a) through (c) above; or
e. In the event a Market Participant cannot meet at least one of the alternatives specified in (a) through (d) above, the Market Participant shall, at a minimum, deposit with SPP Two Hundred Thousand Dollars ($200,000) in Financial Security to be segregated and unavailable to secure any market or transmission activity. Pursuant to election of this alternative, if the anticipated activity at time of application or actual market activity as determined in Article Five, of the Market Participant exceeds One Hundred Thousand Dollars
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($100,000) in Market Exposure, the Market Participant shall provide SPP twice the amount of Financial Security that would otherwise be required of the Market Participant pursuant to Section 4.4.
If the applying Market Participant is unable to meet the minimum capitalization requirements in this Section 3.1.1.8.2criteria for market participation, the applying Market Participant shall be declined participation in all SPP markets. Failure at any time of a Market Participant to continue to satisfy these minimum capitalization requirements in this sSection 3.1.1.8.2criteria for market participation shall be deemed a Material Adverse Change pursuant to Section 3.2.7.
3.1.1.9 Minimum Criteria and Risk Management Verification Process
Through a periodic compliance verification process, SPP shall review and verify Market Participants’ eligibility for market participation based upon SPP’s minimum criteria for market participation, risk management policies, practices, and procedures pertaining to the Market Participants’ activities in the SPP markets. Such review shall include verification that:
1. The risk management framework is documented in a risk policy
addressing market, credit, and liquidity risks; 2. The Market Participant maintains an organizational structure with
clearly defined roles and responsibilities that clearly segregates trading and risk management functions;
3. There is clarity of authority specifying the types of transactions into which traders are allowed to enter;
4. The Market Participant has requirements that traders have adequate training or expertise relative to their authority in the systems and SPP markets in which they transact;
5. As appropriate, risk limits are in place to control risk exposures; 6. Reporting is in place to ensure that risks and exceptions are
adequately communicated throughout the organization; 7. Processes are in place for qualified independent review of trading
activities; and 8. As appropriate, there is periodic valuation or mark-to-market of risk
positions. 9. The Market Participant meets the minimum participation criteria,
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including capitalization requirements, set forth in Section 3.1.1.8.
SPP may select Market Participants for review on a random basis and/or based on identified risk factors such as, but not limited to, the SPP markets in which the Market Participant is transacting, the magnitude of the Market Participant’s transactions, or the volume of the Market Participant’s open positions. Those Market Participants notified by SPP that they have been selected for review shall, upon fourteen (14) calendar days notice, provide a copy of their current governing risk control policies, procedures, and controls applicable to their SPP market activities and shall also provide such further information or documentation pertaining to the Market Participants’ activities in the SPP markets as SPP may reasonably request. Market Participants selected for risk management verification through a random process and satisfactorily verified by SPP shall be excluded from such verification process based on a random selection for the subsequent two years. SPP shall annually randomly select for review no more than twenty percent (20%) of the Market Participants. Each selected Market Participant’s continued eligibility to participate in the SPP markets is conditioned upon SPP notifying the Market Participant of successful completion of SPP’s verification, provided, however, that if SPP notifies the Market Participant in writing that it could not successfully complete the verification process, SPP shall allow such Market Participant fourteen (14) calendar days to provide sufficient evidence for verification prior to declaring the Market Participant as ineligible to continue to participate in SPP’s markets, which declaration shall be in writing with an explanation of why SPP could not complete the verification. If, prior to the expiration of such fourteen (14) calendar days, the Market Participant demonstrates to SPP that it has filed with the Federal Energy Regulatory Commission an appeal of SPP’s risk management verification determination, then the Market Participant shall retain its transaction rights, pending the Commission’s determination on the Market Participant’s appeal. SPP may retain outside expertise to perform the review and verification function described in this section. SPP and any third party it may retain will treat as confidential the documentation provided by a Market Participant under this section, consistent with the applicable provisions of the Tariff.
3.2.7 Material Adverse Changes. Each Credit Customer must give SPP notice of any Material
Adverse Change in its financial condition (and, as applicable, the financial condition of its Guarantor) within two (2) Business Days of the occurrence of the Material Adverse Change. If a Credit Customer or Guarantor files a Form 10-K, Form 10-Q, or Form 8-K
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with the SEC, notice of such filing, timely delivered to SPP in accordance herewith, will suffice on the condition that such notice states that the filing addresses a Material Adverse Change.
A Material Adverse Change in financial condition includes any Material change in operations or financial condition that a reasonable examiner of creditworthiness would deem material to decisions concerning the extension of credit, including but not limited to, any of the following (“Material Adverse Change”):
a. A downgrade of any debt rating or issuer rating, or change in the outlook of any
Credit Rating, including debt rating or issuer rating; b. Any placement on a credit watch with negative implication by a Rating Agency; c. The filing of a lawsuit or initiation of an arbitration, investigation or other
proceeding (including regulatory proceeding) which if decided adversely could have a Material effect on any current or future financial results or financial condition;
d. The merger, acquisition or any other form of business combination involving the
credit customer. e. Any adverse changes in financial condition which, individually, or in the aggregate,
are Material; f. Any adverse changes, events or occurrences which, individually or in the
aggregate, could affect the ability of the Credit Customer to pay its debts as they become due or could have a Material adverse effect on any current or future financial results or financial condition;
g. Discovery or disclosure of conflict of interest issues; h. Resignation or removal of a key officer or director; i. Any action requiring the filing of a Form 8-K; j. Any report of a quarterly or annual loss or a decline in earnings of ten (10) percent
or greater compared to the prior period; k. Any restatement of prior financial statements; and l. Failure of a Market Participant to continue to satisfy the minimum capitalization
criteria for market participation specified in 3.1.1.8.2.
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4.4 Financial Security Requirement. If a Credit Customer (i) is denied an Unsecured Credit Allowance, or (ii) is granted an Unsecured Credit Allowance that is below its Total Potential Exposure calculated pursuant to Article 5, then the Credit Customer may submit Financial Security to cover or exceed the difference in the amount of the Unsecured Credit Allowance granted to the Credit Customer and the amount of its Total Potential Exposure. A Credit Customer electing to satisfy the alternative criteria for market participation specified in Section 3.1.1.8.2(e)(d) and whose anticipated or actual market activity exceeds One Hundred Thousand Dollars ($100,000) in Market Exposure shall provide Financial Security that is twice the amount calculated to satisfy its Financial Security Requirement pursuant to this Section 4.4. Any Credit Customer may provide Financial Security in lieu of or in addition to the Unsecured Credit Allowance it was granted. Upon the Credit Customer’s request, SPP shall provide a written explanation of how it determined the amount of required Financial Security for that Credit Customer. A Credit Customer also is required to submit Financial Security to cover or exceed its Total TCR Credit Requirement pursuant to Section 5A.8.
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Appendix “E” Annual Minimum Market Participation Criteria and Risk Management Certification Form
SPP ANNUAL MINIMUM MARKET PARTICIPATION CRITERIA - ANNUAL
RISK MANAGEMENT CERTIFICATION FORM
I, _____________________________, a duly authorized officer of ______________________________________ (“Market Participant”), understanding that Southwest Power Pool, Inc. (“SPP”) is relying on this certification as evidence supporting SPP’s determination that Market Participant meets the risk management and minimum market participation requirements as set forth in Attachment X to SPP’s Open Access Transmission Tariff (“Tariff”), hereby certify that I have full authority to certify and represent on behalf of Market Participant and further certify and represent as follows:
1. Training. Employees or agents transacting in markets or services provided pursuant to the Tariff on behalf of the Market Participant have received, or will receive, applicable training with regard to their participation under the Tariff as a condition of being authorized to transact on behalf of Market Participant. As used in this representation, training is deemed ‘applicable’ where it is commensurate and proportional in sophistication, scope and frequency to the volume of transactions and the nature and extent of the risk taken by the Market Participant.
2. Risk Management. Market Participant maintains current written risk management policies and procedures that address those risks that could materially affect Market Participant’s ability to pay its SPP invoices when due, including, but not limited to, credit risks, liquidity risks and market risks.
3. Operational Capabilities. Market Participant has available appropriate personnel resources, operating procedures, and technical abilities to promptly and effectively respond to SPP communications and directions related to, but not limited to, settlements, billing, credit requirements and other financial matters.
4. Minimum Participation Criteria, Market Participant maintains that it meets or exceeds the minimum market participationfinancial criteria, including capitalization requirements, as specified in Section 3.1.1.8 of Attachment X of the Tariff. The Market Participant shall submit audited financial statements for the most recent fiscal year to demonstrate minimum Tangible Net Worth or minimum total assets, or provide a report produced by a Rating Agency to establish its Credit Rating as specified in Section 3.1.1.8.2. In the event the Market Participant is unable to meet at least one of these minimum financial requirements, the Market Participant shall maintain
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with SPP the amount of Financial Security required by Section 3.1.1.8.2(e) of Attachment X to the Tariff.
Date:
(Signature)
Print Name:
Title:
Subscribed and sworn before me , a notary public of the State of ,
in and for the County of , this __ day of , 20 .
_______________________________
(Notary Public Signature)
My commission expires: / /
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Proposed Market Protocol Language Revision (Redlined) n/a
Tariff Revision Request (TRR)
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Proposed Business Practices Language Revision (Redlined)
n/a
Proposed Criteria Language Revision (Redlined)
n/a
Revisions to Other Corporate Documents (Redlined)
n/a
MWG MPRR Recommendations to MOPC_071613.docx Page 1 of 2
Southwest Power Pool, Inc.
Market and Operations Policy Committee Recommendation to the Board of Directors
MPPRs 117, 118, 120, 121, 122, 123, 124, 125, 128, and PRR 244 July 29-30, 2013
Organizational Roster
The following members represent the Market Working Group:
Richard Ross, AEP, Chairman Gene Anderson, OMPA, Vice Chairman Will Amos, OGE Lee Anderson, Lincoln Electric System Amber Metzker, Xcel Energy Neal Daney, KMEA Jim Flucke, KCPL Clifford Franklin, Westar Energy, Inc. Matt Johnson, City Utilities, Springfield, MO Chris Lyons, Constellation Energy Commodities Group Rick McCord, EDE Matt Moore, Golden Spread Electric Cooperative Aaron Rome, Midwest Energy, Inc. Ann Scott, Tenaska Power Services Co. Mike Swearingen, Tri-County Electric Cooperative, Inc. Ron Thompson, NPPD Bruce Walkup, AECC Rick Yanovich, OPPD Debbie James, SPP, Secretary
Background
Please see the MPRR Recommendation Report for MPPRs, 117, 118, 120, 121, 122, 123, 124, 125, 128, and PRR 244 that were included in the MOPC July 16-17, 2013 background materials.
Analysis
Please see the MPRR Recommendation Report for MPPRs 117, 118, 120, 121, 122, 123, 124, 125, 128, and PRR 244 that were included in the MOPC April 16-17, 2013 background materials.
Recommendation
The MOPC recommends that the BOD approve its request regarding Marketplace Protocol Revision Requests MPPRs 117, 118, 120, 121, 122, 123, 124, 125, 128, and PRR 244.
Action Requested: Approval of MWG’s request on MPPRs 117, 118, 120, 121, 122, 123, 124, 125, 128, and PRR 244.
MWG MPRR Recommendations to MOPC_071613.docx Page 2 of 2
APPROVED: MOPC July 16-17, 2013 Approved Unanimously-MPRR’s 117, 120, 121, 122, 124, 125, & 128 Approved with abstentions- MPRR 118 Flat Ridge 2 Wind Energy MPRR 123 Flat Ridge 2 Wind Energy & ITC Great Plains
MPRR Number
Description
MWG Meeting Vote
RTWG Meeting Vote
ORWG Meeting Vote
117 SPP Congestion Management
4/24/2013 Unanimously approved
6/28/2013
Unanimously approved
6/27/2013 Approved
6/19/2013 Approved with modifications
118 Split-bus Logic for TCR Market 5/21/2013 Unanimously approved
6/27/2013 Approved
6/19/2013 Approved with no Reliability Impact
120 MPRR Mitigated Offer Formula Corrections
5/8/2013 Approved
6/28/2013
Unanimously approved
5/22/2013 Approved
6/20/2013 Approved with no Reliability Impact
121 Removal of NERC’s
Administration of Reliability and Grid Management Tools
5/22/2013 Unanimously approved
5/29/2013
Unanimously approved
5/22/2013 Approved
6/19/2013 Approved with no Reliability Impact
122 Offer Curve and Bid Curve Development Clarifications
5/29/2013 Approved
6/28/2013
Unanimously approved
6/27/2013 Approved
6/19/2013 Approved with no Reliability Impact
123 Quick-Start Resource Treatment 5/29/2013 Approved
6/27/2013 Approved
6/19/2013 Approved
124 Resource Specific TSR Creation 5/21/2013 Unanimously approved
6/27/2013 Approved
6/19/2013 Approved with no Reliability Impact
125 Qualifying Facility Registration as NDVER
5/21/2013 Approved
6/27/2013 Approved
6/19/2013 Approved
128 Day-Ahead Virtual Energy Transaction Fee Rate
5/22/2013 Approved
6/28/2013
Unanimously approved
6/27/2013 Approved with modifications
6/19/2013 Approved with no Reliability Impact
PRR 244 Removal of NERC’s
Administration of Reliability and Grid Management Tools
5/22/2013 Unanimously approved
5/29/2013 Approved
5/22/2013 Approved
6/19/2013 Approved with no Reliability Impact
MWG PRR 244 Recommendation Report.docx Page 1 of 20
PRR Recommendation Report
PRR No. 244 PRR
Title Removal of NERC’s Administration of Reliability and Grid Management Tools
Timeline Normal Expedited Urgent Action
Provide explanation if Expedited and/or Urgent Action is selected:
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 3.1; 6.6.1; 6.6.4; 6.8.1; 6.8.3; 6.8.5; 6.8.6; 9.2.3; 11.2.4; 13.4 Title: Resource Plans - Introduction; External Resource Tags; Network/Native Load and Portfolio Scheduling; SPP Congestion Management under TLR Operations; Market Flow; NERC IDC Curtailments; Market Flow Curtailments/Adjustments; Net Scheduled Interchange; Public Market Data for Settlement; Procedures for Handling Incorrect Schedule Adjustments Resulting from Market Software and Data Input Errors; Protocol Version: 34.0
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
NERC is terminating its administration of reliability tools IDC and SDX. SPP will continue its utilization of these tools through a separate association with other Reliability Coordinators and users. As NERC is terminating its relationship with these tools, all Protocol, Tariff and Criteria references that associate NERC with these tools should be revised. Any references to NERC that remain in the Protocols, Tariff and Criteria related to IDC or other reliability tools are obsolete. Section 6.8.3 was updated to show the recent JOA with WAPA.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment C Methodology to Assess Available Transfer Capability Section 4.1.1 Network Topology; 4.1.2 Load Forecast; 4.1.3 Net Interchange; 4.2.1 Network Topology; 4.2.2 Load Forecast; 4.3.1 Network Topology; 4.3.2 Load Forecast; 8 AFC Flowchart Attachment G Network Operating Agreement Section 6, Scheduling Procedures Attachment AE Energy Imbalance Service Market; Section 1.1 Definitions; 4.3 Coordination of Market Operations under SPP Congestion Management
No
EIS Market
Integrated Marketplace
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MWG Review PRR Recommendation
Date of Vote: 5/22/2013 – Approved unanimously 5/29/2013 – Unanimously approved RTWG's modifications All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A
RTWG Review 5/22/2013 – Approved with modifications Changes highlighted in Yellow
ORWG Review 6/19/2013 – Approved with no Reliability Impact
MOPC Recommendation
Board Review
Date 5/3/2013
Sponsor
Name Matthew Harward E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3560
Comments Received
Comment Author Matthew Harward on behalf of RTWG Date 5/24/2013 Comment Description Attachment G added “E-“ to tag for clarification. Comment Status
Proposed Protocol Language Revision
3 Resource Plans
3.1 Introduction The Resource Plan is submitted by Market Participants with registered Resources to enable the SPP Market Operation System (MOS) to assess Resource and Ancillary Service adequacy for the SPP region, each SPP control area, and each Market Participant. The operator of the Control Area remains responsible for the balance of Load and Resources within the Control Area boundary. See Appendix 7 of SPP Criteria for requirements of data submission. External Resources have the same requirements for submitting a Resource Plan as those Resources within the SPP Market Footprint, except as specified below. For such External Resource capacity as is offered into the SPP Market, (i) only status available to External Resources is “Available” or “Unavailable”; (ii) the Min MW must be set to zero and (iii) the Max MW may not exceed the transmission service arrangements associated with the External
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Resource. If Tagged, the Max MW may not exceed the Tag value, including the curtailment limit adjusted by the NERC Interchange Distribution Calculator (IDC).
6.6.1 External Resource Tags All External Resources utilizing the Pseudo-Tie methodology will submit an hourly NERC tag. The MW amount of such tag will be the same amount of its maximum MW offer, which should be the same value as the Resource’s Max-MW value as submitted in its Resource Plan. The Pseudo-Tie tags will be utilized by NERC IDC.
The Transmission Provider will not forward these Pseudo-Tie tags to the Market Operations System (“MOS”) or its Commercial Operations System (“COS”). The Transmission Provider will not utilize these tags as bilateral transactions.
6.6.4 Network/Native Load and Portfolio Scheduling A Native Load and Portfolio Schedule (NLPS) is a unilateral schedule between one or more Resource Settlement Locations and Load Settlement Locations registered by the same Transmission Customer in the same Control Area. NLPS schedules do not utilize NERC tags.
Transmission Customers will have the ability to enter their NLPS into SPP’s Native Load and Portfolio Scheduling Tool (NLPS). Transmission Customers are not required to use NLPS. Such schedules will be included with all other schedules sent to the SPP’s settlement system, and will have the same impact on settlement as any other type of schedule. Due to their special nature as unilateral schedules, NLPS schedules are subject to special rules.
Special rules applied to NLPS are as follows:
• NLPS will be allowed only between Settlement Locations registered by the same Transmission Customer.
• NLPS will be allowed only between Settlement Locations in the same Control Area.
• NLPS will be validated against the transmission capacity associated with the Designated Resources. SPP shall maintain a list of transmission capacity for Designated Resources.
• NLPS may be adjusted for a given Operating Hour no later than 20 minutes prior to the beginning of the schedule start or change (beginning of ramp).
• NLPS is not permitted from Resources in the Unavailable status.
• NLPS is permitted from Resources in the Available Quick-start status.
• Schedules conforming to these rules shall be automatically accepted.
6.8.1 SPP Congestion Management under TLR Operations If there are curtailable schedules/NNL in IDC at the SPP Congestion Management Event priority level in either current operating hour or next hour, a TLR will be requested through the IDC. When TLR is requested, MOS, the NERC IDC and the SPP Curtailment/Adjustment Tool
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(SPP CAT) will work with each other to manage congestion on constrained flowgates and handle curtailments of Energy Schedules as appropriate.
The appropriate level of TLR must be requested in the IDC. The IDC will prescribe curtailments of those tags that are not included in Market Flows. The IDC will also prescribe curtailment of Market Flows. SPP will then activate or continue activation of the constraint in MOS. In the meantime; CAT will receive the Market Flow relief obligation from the IDC. Used in conjunction with Market Flows received from MOS, CAT will calculate EIS and appropriately curtail/adjust those schedules included in Market Flow. All curtailments are fed into RTOSS from the IDC and CAT to facilitate proper generation response for Self-dispatched Resources. LIPs will not be updated after a schedule curtailment until those curtailments are recognized in the Market dispatch.
6.8.3 Market Flow As required by the Congestion Management Process (CMP) prescribed by the SPP-MISO Joint Operating Agreement and the Joint Operating Agreement between SPP and the Western Area Power Administration (“WAPA”), SPP will determine and submit to the NERC IDC its Market Flows on all SPP Coordinated Flowgates (CFs) and Reciprocal Coordinated Flowgates (RCFs). SPP’s CFs are those flowgates identified as being impacted by activities within SPP. SPP’s RCFs are those flowgates identified as being impacted by activities within SPP and one or more entities operating under the requirements similar to those of the CMP. Currently those entities include SPP, MISO, MAPP, PJM, TVA, and WAPAPJM. SPP’s Market Flows represent impacts from one or more of the following components:
1) The Native Load Schedule component of NLPS from both Market and Self-dispatched Resources. NLPR impacts are considered implicit in the Portfolio Schedules they are supporting and therefore are not included in Market Flow. 2) Tagged intra-Balancing Authority schedules from both Market and Self-dispatched Resources 3) Tagged schedules where the source is a market Resource or Load Settlement Location and the sink is a Load Settlement Location 4) Any unscheduled output from generation resources offered into the EIS Market and dispatched by SPP in accordance with these Protocols (hereinafter referred to as “EIS impact.”)
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In accordance with the CMP, Firm Flow Limits are derived for CFs while both Firm and Non-firm Network limits are derived for RCFs. For CFs, SPP will establish a Firm Flow Limit equal to the sum of firm transmission reservations and Gen-to-Load impacts. For RCFs, SPP will establish a Firm Flow Limit based upon the allocation of Flowgate Capacity determined pursuant to the reciprocal coordination process. For CFs, SPP will assign Firm (F-7) curtailment priorities to those Market Flows that are scheduled (i.e., categories 1-3 from the above list) using firm transmission service, up to the applicable Firm Flow Limit. On CFs, any remaining Market Flows will be assigned Non-firm Network (NN-6) curtailment priorities. For RCFs, SPP will assign Firm (F-7) curtailment priorities up to the Firm Flow Limit established by the CMP. For RCFs, SPP will assign Non-firm Network (NN-6) curtailment priorities up to the Non-firm Network Limit established by the CMP. On RCFs, any Market Flow in excess of the Non-firm Network Limit will be prioritized as Non-firm Hourly (NH-2). At least every 15 minutes, SPP will send Market Flow values for all CFs and RCFs to the IDC in the appropriate priority levels for the current hour and next hour. During an SPP Congestion Management event, the IDC will use this information to prescribe appropriate reductions in Market Flows and curtailments of tags whose impacts are not reflected in Market Flows. SPP systems will identify Market Flows that must be curtailed to achieve any obligation assigned by the IDC by binding of the constraint in the security constrained economic dispatch system. SPP will determine the amount of Market Flows associated with EIS impacts by subtracting scheduled Market Flows from total Market Flows. For CFs, EIS impacts are considered to have Non-firm Network priority. For RCFs, any EIS impacts that cannot be allocated to the Non-firm Network priority will be considered to have Non-firm Hourly priority.
6.8.5 NERC IDC Curtailments The NERC IDC will receive all tagged transactions involving SPP. Under SPP Market Operations, the NERC IDC will be responsible during TLR events for prescribing curtailment of certain types of tagged transactions and prescribing Market Flow relief that SPP must achieve internally through its Market Operations. The NERC IDC will be responsible for prescribing curtailment of only those tags involving SPP for which impacts are not included in SPP’s Market Flows (see section 6.7.1). These include tags for schedules with external parties that are sourced or sunk in the SPP Market and tags for Interchange Transactions from Self-Dispatched Resources. Those tags for which impacts are included in SPP’s Market Flows will not be explicitly curtailed by the IDC. As stated in section 6.7.1, included in SPP’s Market Flows are impacts of tagged schedules where the source is a Resource or Load Settlement Location and the sink is a Load Settlement Location. In order for the IDC to distinguish those tags, MOS will communicate a market flag for each such Resource to the IDC each hour based on information in the Resource Plan. At least every 15 minutes, SPP will also send to the IDC the Balancing Authority(ies) wherein the marginal unit(s) reside. This information will be used by the IDC to calculate Transaction
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Distribution Factors (TDFs) for those schedules with external parties that source in the SPP Market. This is reflected in the IDC as the SWPP_EXP marginal zone. If a generation resource in the SPP Market footprint is self-dispatched and has tagged schedules with external parties, the IDC will use resource level granularity in determining the TDF impact on flowgates.
6.8.6 Market Flow Curtailments/Adjustments CAT is used to compute curtailments/adjustments of those schedules for which impacts are included in Market Flows. These include the following types of impact:
1) Native Load Schedules from both Market and Self-dispatched Resources 2) Tagged intra-Balancing Authority schedules from both Market and Self-dispatched Resources 3) Tagged schedules where the source is a market Resource or Load Settlement Location and the sink is a Load Settlement Location 4) Unscheduled output from Non-Dispatchable Resources. These schedules are only created for Resources that become commercially operational on or after October 15, 2012.
Any curtailments or adjustments made by CAT are based on the Market Flow relief responsibility determined by the IDC, during a TLR event, or the amount of EI supporting schedules, during a SPP Congestion Management Event (CME) where TLR is not initiated. In all cases, it is SPPs responsibility to achieve the required Market Flow relief. SPP will first determine if the EIS component of the Market Flows at the applicable priority is sufficient to achieve required Market Flow relief. If so, then EIS will be reduced to provide the required relief and no schedule curtailments or adjustments will be necessary. However, if the adjustment of the EIS component of Market Flow is not sufficient to achieve the required relief, the scheduled curtailments will be handled as outlined in the following sections. The SPP CAT will use the same Transfer Distribution Factor (TDF) threshold as the NERC IDC to determine whether a tag/schedule materially impacts a flowgate and should be curtailed. The NERC IDC TDF threshold is defined in the Joint NERC/NAESB System Operator TLR Reference Manual. The SPP CAT will communicate any schedule curtailments/adjustments to RTO_SS. In addition, Curtailment/Adjustments of schedules will be communicated to the Market Participant via XML and will include Resource name, original schedule, and adjusted schedule. For Non-Dispatchable Resources that became commercially operational on or after October 15, 2012, the XML notification will also include an indicator flag to follow dispatch instruction. If any Self-Dispatched Resources identified in NLS are required to be curtailed, SPP CAT will also send the aggregate curtailment responsibility to each Resource owner for its curtailed Resources. Generator Shift Factors (GSF’s) will also be provided through a viewer to the Market Participants. These may be used by the Market Participants to determine how to best modify their Self-Dispatch Resource schedules while still maintaining the total level of reduction required.
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The SPP CAT will run automatically, at least once every hour, and will produce solutions that will be communicated to RTO_SS. CAT will also run at the beginning of the next Dispatch Interval immediately following a Congestion Management status change. As warranted, the SPP CAT will also receive from the IDC the re-load amounts for Market Flows as a flowgate starts to become unconstrained. SPP CAT will use this information to re-load any curtailed or adjusted schedules.
Internal Flowgates
If the EIS component is positive and is not sufficient to achieve the required Market Flow relief, SPP will reduce the EIS and then curtail and/or adjust schedules, both in order of priority, to provide the required relief. If the net EIS component is negative, SPP will curtail schedules so that the net negative EIS impact on the flowgate is eliminated and the requested relief is achieved. SPP will increase the TLR or SPP Congestion Management level as necessary up to and including Level 5.
External Flowgates
If the EIS component is positive and is not sufficient to achieve the required Market Flow relief, SPP will reduce the EIS and then curtail and/or adjust schedules, both in order of priority, to provide the required relief. If the net EIS component is negative, SPP will curtail Schedules so that the net negative EIS impact on the flowgate is as close to zero as possible. SPP will only curtail schedules up to and including the TLR level declared by the external entity that manages the flowgate. In the event SPP is unable to remove all negative EIS impacts through schedule curtailments, this may result in a revenue neutrality shortfall. In all cases, it is SPPs responsibility to achieve the required Market Flow relief.
9.2.3 Net Scheduled Interchange Net Scheduled Interchange is calculated as a net of all approved inter Control Area schedules in SPP’s Electronic Scheduling System, RTO_SS and for use in additional MOS calculations. This includes schedules from NERC Tags, schedules that are a result of an Automated Reserve Sharing (ARS) event and Loss Repayment schedules that are created within RTO_SS. Dynamic schedules are not included in the calculation of NSI. Every 4 seconds the following occurs:
RTO_SS will send real time NSI values to SPP’s Energy Management System Real Time Manager (EMS RTSMGR). The RTSMGR will sum the real time NSI from RTO_SS with the EI component from Market Operations System (MOS) and send this signal to SPP Control Areas via ICCP on an approximate 4-second interval. SPP shall provide a backup mechanism for SPP Control Areas to receive the EI NSI.
Every 5 minutes the following occurs:
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1. SCED is performed for the next 5 minute interval using four primary sets of inputs under
normal circumstances. • The first set of inputs includes the latest generation values collected from the SPP
EMS AGC (fed from ICCP). • The second input includes the Resource ramp rates and availability flags in effect for
that interval. • The third input includes the Resource offers for EIS. • The fourth input includes Resource requirements based on the short term SPP Control
Area forecast and the net of schedules flowing into or out of the SPP footprint (obtained from RTO_SS).
2. MOS calculates the total SPP NSI and RTO_SS CA NSIs using the schedules that were
collected from RTO_SS. • MOS performs security constrained economic dispatch using SPP NSI and control
area Load Forecasts for the interval. • The generation for each Control Area is summed and the Control Area Load Forecast
is subtracted from that generation to calculate the Economic Dispatch NSI (ED NSI). • MOS subtracts the CA NSI from the ED NSI to produce the Energy Imbalance NSI
(EI NSI).
3. MOS sends the EI NSI component (one per SPP control area) to the EMS.
11.2.4 Public Market Data for Settlement The Commercial Model, COS Entity Validation (SL to TSIN mapping), and SPP Loss Matrix shall be available to all market participants for download via the SPP portal and via the Commercial Operations Systems Programmatic Interface. The data will consist of a separate XML file for each. Each file will contain the following information: • Commercial Model shall contain SPP’s transaction point list with details of transaction point
type (i.e. GEN, AGG, LOAD, Controllable Load, etc), start date, and end date. This list will be maintained by SPP and communicated when transaction points are added, changed, and/or deleted.
• COS Entity Validation (SL to TSIN mapping) shall contain the relationship between Settlement Location, PNode, NERC Source/Sink Name, Start Date, End Date, PSE, and Control Area. This list will be maintained by SPP and communicated when transaction points are added, changed, and/or deleted.
• SPP Loss Matrix shall contain Season, Source, Sink, and the loss % for each Transmission Owner for each Source/Sink pair in the SPP Loss Matrix table.
13.4 Procedures for Handling Incorrect Schedule Adjustments Resulting from Market Software and Data Input Errors
Due to software or data input errors, the CAT or IDC may incorrectly adjusts schedules in real-time by either adjusting or failing to adjust schedules properly for the given system conditions.
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SPP will notify the appropriate stakeholder group of the incorrect operation, the financial impact to revenue neutrality and the steps taken to mitigate this event in the future.
In the event the CAT or IDC failed to curtail schedules in real-time, SPP will not make any after the fact schedule adjustments.
In the event the CAT or IDC curtailed a schedule in real-time beyond what was appropriate for the given system conditions, SPP will notify and coordinate with the affected MPs to determine the appropriate after-the-fact schedule reinstatement. Due to actions that may have been taken by MPs in response to the adjustment, the MP(s) affected by the incorrect curtailment(s) may, but are not required, to agree to after-the-fact-schedule reinstatement. In the case of NERC tagged schedules, the affected parties to the NERC tag must agree on any after the fact reinstatements. After-the-fact reinstatements will not be allowed if SPP and the affected MP(s) do not reach an agreement or if the associated NERC tags cannot also be revised. After-the-fact schedule reinstatements will only be allowed if such changes would not have resulted in changes in dispatch or prices.
Proposed Tariff Language Revision Attachment C
4.1.1 Network Topology
Network topology is established by the State Estimator. The models for the first four hours following the latest State Estimator snapshot include all outages, both planned and contingency, that existed in the State Estimator snapshot. Models for the remaining hours of the Operating Horizon are adjusted with hour-to-hour outage data of generators, transmission lines and transformers as submitted by Balancing Authorities within the SPP Reliability Coordination Area and approved by the Reliability Coordinator. This outage data includes both planned outages and contingency outages that are expected to remain in effect for each hour modeled. The Transmission Provider shall also include outage data from neighboring Reliability Coordinators that is available through NERC System Data Exchange (SDX).
4.1.2 Load Forecast The hourly load forecast data (for day 1 – day 7) is created by the Transmission Provider for the State Estimator model from the short-term and mid-term load forecast tools that use weather data from weather stations spread over the Transmission System and historical actual load data received from Balancing Authorities within the SPP Reliability Coordination Area. The Transmission Provider also includes load forecast data from neighboring Reliability Coordinators that is available through NERC SDX. The Transmission Provider derives load forecast data for day 8 – day 31 from the data of day 1 – day 7 by applying a factor that represents an historical increase or decrease of load on weekly basis during the year.
4.1.3 Net Interchange The net interchange of the Balancing Authority Areas that are part of the State Estimator Model is based on the existing schedules at the time the RTRFCALC application perform its Operating
MWG PRR 244 Recommendation Report.docx Page 10 of 20
Horizon run at least once per day. The schedule data is retrieved from NERC Tagdump and from SPP’s scheduling system (RTOSS).
4.2.1 Network Topology
Network topology is established by the State Estimator and adjusted with hour-to-hour outage data of generators, transmission lines and transformers. Such outage data shall be as submitted by Transmission Operators and Generation Operators that are within the SPP Reliability Coordination Area and approved by the Reliability Coordinator. This outage data includes both planned outages and contingency outages that are expected to remain in effect for each time period modeled. The Transmission Provider shall also include outage data from neighboring Reliability Coordinators that is available through NERC SDX.
4.2.2 Load Forecast
The hourly load forecast data (for day 1 – day 7) is created by the Transmission Provider for the State Estimator from the short-term and mid-term load forecast tools that use weather data from weather stations spread over the Transmission System and historical actual load data received from Transmission Operators within the SPP Reliability Coordination Area. The Transmission Provider also includes load forecast data from neighboring Reliability Coordinators that is available through NERC SDX. The Transmission Provider derives load forecast data for day 8 – day 31 from the data of day 1 – day 7 by applying a factor that represents an historical increase or decrease of load on weekly basis during the year.
4.3.1 Network Topology Network topology is established by the State Estimator and adjusted for outages of generators, transmission lines and transformers. Such outage data shall be as submitted by Transmission Operators and Generation Operators that are within the SPP Reliability Coordination Area and approved by the Reliability Coordinator. This outage data includes both planned outages and contingency outages that are expected to remain in effect for some period within this horizon. The Transmission Provider also includes outage data from neighboring Reliability Coordinators that is available through NERC SDX. The Transmission Provider includes approved planned outages and contingency outages which are active on 15th of the month and last more than 15 days.
4.3.2 Load Forecast
The Transmission Provider utilizes monthly forecast data from the EIA411 annual report. For Balancing Authority Areas not included in the EIA411 annual report, the Transmission Provider uses forecast data that is available through NERC SDX.
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8. AFC Flowchart Process Flow diagram Operating, Planning, and Study Horizons
Topology State Estimator Models Updated with outages.
Outage data from NERC SDX
Short and mid-term load forecast (Operating and Planning Horizons) Load forecast data from EIA411 – annual report (Study Horizon) ExternalSchedules.txt (Operating Horizon): File that has Reservation numbers of scheduled Transmission Service Requests
ucfile.csv: Unit commitment data file
Powerflow AC Power flow Operating Horizon: • Day1. Day1,2 after 12:00 noon • Updated at least once/day Planning Horizon: • Day after Operating thru day 31 • Updated at least once/day Study Horizon: • 12 values (Month 2, 13) • Updated at least once/month Calculates: • Base flows of flow gates • DF of paths
webTrans Calculates: • AFC of all flow gates • ATC of all paths
Base flows DF values
Transmission Service Requests
Transmission Service Requests OASIS plus ExternalReservations.csv
AtcDataSourceRFCalcGSF.csv (Operating and Planning Horizons)MonthAtcDataSourceRFCalcGSF.csv (Study Horizon)
Base flows DF values TFC values
MWG PRR 244 Recommendation Report.docx Page 12 of 20
Process Diagram webTrans
EMS/RTRFCALC AtcDataSourceRFCalcGSF.csv (Operating, Planning Horizons) * Base flows flow gates * DF values paths * TFC values flow gates MonthAtcDataSourceRFCalcGSF.csv (Study Horizon) *Base flows flowgates *DF Values paths *TFC values flowgates
webTrans Calculates: • AFC of all flow gates • ATC of all paths Shows impact of new Transmission Service Requests. Allows approving / refusing of reservation. POR/POD Ultimate Data: Mapping table with Source/Sink Name to ZONE relation. Provider Segment: Table that has counterflow factors for all flow gates. TSR Source Point Mapping: Dropdown for Source/Sink names in relation to POR/POD
OASIS DATABASE • Transmission Service Requests • Flow gates • Paths
Transmission Service Requests
ExternalReservations.csv ExcludeReservations.csv
Customer Interface OASIS Submit Transmission Service Requests Use Scenario Analyzer Review results of test Request
AFC/ATC
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Process diagram UC Application
Effective Date: 5/16/2011 - Docket #: ER11-3101
EMS / RTRFCALC AC Power flow Operating Horizon: • Day 1. Day1,2 after
12:00 noon • Updated at least
once/day Planning Horizon: • Day after operating
thru day 31 • Updated at least
once/day Calculates: • Base flows of flow
gates • DF of paths
Unit Dispatch Application runs every hour
Load forecast of Balancing Authority and Net Interchange of the Balancing Authority
Unit Dispatch data: UCFILE.CSV
EMS / STATE ESTIMATOR
Database that contains generation level of all generators of last 21 days
NETMOM DB
Unit Commitment data
Unit Commitment data
OASIS DB
Database that contains Transmission Service Requests sourcing from Zones that have units that are not commonly dispatched with units of Balancing Authority
Transmission Service Requests
MW level units
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Attachment G 6.0 Scheduling Procedures
6.1 Prior to the beginning of each week, the Network Customer shall provide to the
Transmission Provider expected hourly energy schedules for that week for all energy
flowing into the Transmission System administered by Transmission Provider.
6.2 In accordance with Section 36 of the Tariff, the Network Customer shall provide to the
Transmission Provider the Network Customer’s hourly energy schedules for the next
calendar day for all energy flowing into the Transmission System administered by the
Transmission Provider. The Network Customer may modify its hourly energy schedules
up to twenty (20) minutes before the start of the next clock hour provided that the
Delivering Party and Receiving Party also agree to the schedule modification. The
hourly schedule must be stated in increments of 1000 kW per hour. The Network
Customer shall submit, or arrange to have submitted, to the Transmission Provider a
NERC transaction identification E-Tag where required by NERC Standard INT-001.
These hourly energy schedules shall be used by the Transmission Provider to determine
whether any Energy Imbalance Service charges, pursuant to Schedule 4 of the Tariff
apply. Attachment AE
1.1 Definitions I
Imbalance Energy
The amount of Energy Imbalance Service in megawatts per hour that is provided or consumed by a
Market Participant at a Settlement Location in an hour.
Interchange Distribution Calculator (IDC)
The mechanism used by Reliability Coordinators in the Eastern Interconnection to calculate the
distribution of interchange transactions over specific flowgates.
Intermittent Resource
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A Resource that meets all of the following criteria: a) the fuel source can not be stored, b) the output of
the Resource is by nature weather-driven, and c) it has limited capabilities to be dispatched and to
respond to changes in system demand and transmission security constraints.
1.1 Definitions N
NERC Interchange Distribution Calculator (NERC IDC)
The mechanism used by Reliability Coordinators in the Eastern Interconnection to calculate the
distribution of interchange transactions over specific flowgates.
Net Energy Imbalance Service Charge/Credit
The sum of a Market Participant’s Settlement Location specific Energy Imbalance Service
Charge/Credits in an hour.
4.3 Coordination of Market Operations under SPP Congestion Management The Transmission Provider shall use the following process to coordinate the operations of the
Energy Imbalance Market during times when a Congestion Management and/or TLR event is declared
to manage congestion on one or more flowgates:.
(a) The Transmission Provider shall identify schedules in the NERC IDC that are also
included in Market Flows.
(b) The Transmission Provider shall submit the Market Flow impact on each Coordinated
Flowgate and Reciprocal Coordinated Flowgate to the NERC IDC. The Market Flow
impact on each flowgate shall include the aggregate MW flow impacts on the identified
flowgate including the following:
i. Energy Schedules relating to native load for which no tag has been identified;
ii. Energy Schedules entirely within a Balancing Authority Area for which a tag has
been identified and where the source is either a Dispatchable Resource or Self-
Dispatched Resource; and
iii. Energy Schedules between Balancing Authority Areas for which a tag has been
identified where the source is a Dispatchable Resource or Load Settlement
Location and the sink is a Load Settlement Location.
iv. Unscheduled output from Non-Dispatchable Resources.
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(c) The Transmission Provider shall assign curtailment priorities to the Energy Schedules
causing Market Flow on each flowgate using the identified tags, or for an Energy
Schedule associated with native load using an assumed Network Service tag, and in the
following priority categories:
i. Curtailment priorities for flowgates that have not been defined as a Coordinated
Flowgate or a Reciprocal Coordinated Flowgate shall be assigned in accordance
with NERC TLR procedures.
ii. For Coordinated Flowgates, the Transmission Provider will assign Market Flow
in the Firm priority up to the Firm limit with any excess Market Flow assigned as
Non-Firm Network.
iii. For Reciprocal Coordinated Flowgates, the Transmission Provider will divide its
Market Flows into Firm, Non-Firm Network, and Non-Firm Hourly curtailment
priorities. The Transmission Provider will first assign Market Flow in the Firm
priority up to the Firm limit, then assign remaining Market Flow in the Non-firm
Network priority up to the Non-firm Network limit, and finally assign any excess
Market Flow as Non-firm Hourly.
(d) The Market Flow contribution associated with Energy Imbalance Service shall be
determined by the Transmission Provider by subtracting the Market Flow associated with
the Energy Schedules defined in Section 4.3(b) within that priority level defined in
Section 4.3(c) from the total calculated Market Flow for that priority. For Coordinated
Flowgates, any Market Flow contribution of Energy Imbalance Service in excess of that
assigned to the Firm priority shall be assigned a Non-Firm Priority. For Reciprocal
Coordinated Flowgates, any Market Flow contribution of the Energy Imbalance Service
in excess of amounts assigned to Firm or Non-Firm Network priorities shall be assigned a
Non-Firm Hourly priority.
(e) When congestion occurs on a flowgate that requires a TLR event, the NERC IDC will
prescribe curtailments for tags of all Physical Schedules and identify the amount of relief
required from Market Flows on the Coordinated Flowgate or Reciprocal Coordinated
Flowgate.
(f) The Transmission Provider shall achieve the required reduction in Market Flows
provided by the NERC IDC using its security constrained dispatch software and
curtailment/adjustment tool (“CAT”), which curtails schedules identified in Sections
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4.3(c) and 4.3(d) in the following order until the desired reduction in Market Flows is
achieved:
i. To the extent that Market Flows are contributing to the constrained condition, the
Transmission Provider shall restrict the ability of the market operating system
from contributing further to the constrained condition by binding the Coordinated
Flowgate or Reciprocal Coordinated Flowgate constraint. The security
constrained dispatch of Dispatchable Resources shall continue within each
priority level until the Market Flows within that priority level have been reduced
to zero or the flowgate constraint is eliminated, whichever comes first. Any
impact on Locational Imbalance Prices will be calculated per Section 4.4 of
Attachment AE.
ii. Simultaneously with the security constrained dispatch of Dispatchable Resources
that contribute to Market Flows, the CAT shall determine if sufficient Energy
Imbalance Service exists to achieve the desired Market Flow relief. If there is an
insufficient amount of Energy Imbalance Service to achieve the desired Market
Flow relief, CAT shall curtail the remaining schedules identified in Section 4.3(c)
impacting the Coordinated Flowgate or Reciprocal Coordinated Flowgate, using
their assigned priority level, starting from lowest priority to highest, until the
desired Market Flow reduction is achieved or until all such schedules in that
priority have been reduced to zero. During this curtailment process, CAT also
adjusts the Scheduled Generation of Resources, to the extent that such Resources
need to be dispatched below their scheduled amount to achieve the desire Market
Flow relief, and such adjusted Scheduled Generation shall be used for settlement
purposes. The impact of schedule curtailments on Locational Imbalance Prices
will be realized as soon as the changes to Self-Dispatched Resource schedules
resulting from the curtailments are reflected within the EIS Market dispatch
software and Locational Imbalance Prices shall continue to be calculated in
accordance with Section 4.4.
(g) The Transmission Provider shall notify each Market Participant of the aggregate
curtailments it is required to make, and such notification shall include Resource name,
original schedule, and the generation shift factor associated with their Resources for the
constrained flowgates.
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(h) The Transmission Provider shall notify each Market Participant if a curtailment is
expected to continue into the next Operating Hour. Market Participants may revise their
Energy Schedules or operating schedule for Self-Dispatched Resources for the next
Operating Hour so long as they maintain the required reduction level in Market Flows
required.
(i)Non-Dispatchable Resources shall be instructed to curtail via an XML notification. Such notification shall include the resource name, time period of curtailment, and the curtailment level. When instructed, a Non-Dispatchable Resource shall operate at the lower of its (1) curtailment level or (2) actual net output. In the case of a Qualifying Facility exercising its rights under PURPA to deliver all of its net output to its host utilities, its output shall be curtailed proportionately, equivalent to Firm Service. The curtailment level of a Non-Dispatchable Resource shall be the sum of the curtailed unscheduled and scheduled portion of the output of Resource as determined by CAT.
Proposed Criteria Language Revision
4.5.5.4 Hourly Calculations (Day 1) These calculations are for hourly non-firm service only. All known schedule information from NERC
Electronic-tags will be applied to base flow calculations. These schedules determine base interchange
values. Since these are expected schedules, all counter flow impacts are allowed in this calculation.
OASIS reservation information is not considered for determination of existing impacts in this calculation.
12.3 System Operating Limits (SOLs) The value (such as MW, MVar, Amperes, Frequency or Volts) that satisfies the most limiting of the
prescribed operating criteria for a specified system configuration to ensure operation of the Bulk Electric
System (BES) within acceptable reliability criteria. System Operating Limits are based upon certain
operating criteria. These include, but are not limited to: Facility Ratings (Applicable pre- and post-
Contingency equipment or facility ratings), Transient Stability Ratings (Applicable pre- and post-
Contingency Stability Limits), Voltage Stability Ratings (Applicable pre- and post-Contingency Voltage
Stability), and System Voltage Limits (Applicable pre- and post-Contingency Voltage Limits). SPP
monitors and controls the BES using Flowgates and the NERC TLR process.
SPP also monitors numerous other BES facilities within its footprint and creates temporary flowgates
when operating conditions reveal any additional limiting system configurations. Since SPP is utilizing
these flowgates to ensure the system is operating within acceptable reliability criteria, these flowgate
limits serve as the SPP System Operating Limits.
12.3.1 Methodology for Determination of Operating Horizon SOLs
• This methodology is applicable for developing SOLs used in the operating horizon.
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• Based on results of system studies (as described below), SOLs are determined per the
definition.
• SOLs shall not exceed Facility Ratings. SOLs equal applicable Facility Ratings unless
additional studies have established a lower limit based on other operational issues such
as transient, dynamic and voltage stability, etc.
• Anticipated system topology, generation dispatch, and load levels are utilized daily via
SPP member submission on OPS1 CROW Outage Scheduler and NERC SDX for non-
members.
• Pre-contingency and first contingency studies will be conducted to investigate thermal and
voltage violations for current and next day.
• Voltage and angular stability issues are investigated off-line as deemed necessary by
operator and engineer experience and engineering judgment.
• As deemed necessary by study results, an operating guide to aid operators in mitigating
potential SOL violations may be produced. These guides may be temporary or
permanent, depending whether the violation is due to a short-term outage, seasonal
loading issues, etc. At a minimum, this operating guide will include:
1. Statement of type(s) of violations revealed by study (voltage/thermal/stability)
2. Applicable dates
3. Available/recommended mitigation methods, including generation redispatch
(maximum MW and/or minimum Mvar generation), transmission reconfiguration,
reclosing reconfiguration, load shedding, and Transmission Loading Relief (TLR).
• Identified SOLs are screened to compile a list of potential IROLs per the following criteria:
1. Potential IROLs will be investigated when a contingency analysis highlights a thermal
overload in excess of 120% of the SOL of the monitored facility.
2. Potential IROLs will also be investigated when a contingency analysis highlights an
under-voltage condition characterized by bus voltages of less than 90% across three
or more BES facilities.
The potential IROL condition will be reviewed further by evaluating the system response to
the loss of the SOL violated facility. The original potential IROL contingency will be
assumed to be a confirmed IROL condition if the evaluation reveals that the ensuing SOL
violated facility contingency results in another BES facility being overloaded to greater
than 120% of its SOL or three or more additional BES facilities with bus voltages in the
area experiencing projected post-contingency voltages less than 90%, unless there are
studies or system knowledge that the SOL is not an IROL.
• The IROL TV is 30 minutes.
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• Special Protection Schemes (SPS’s) are allowed to prevent prolonged undervoltage and
to preserve system voltage and machine stability. The Transmission Owner shall provide
the RC with the location and description of each SPS, and shall notify the RC when the
schemes are enabled/disabled.
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PRR Recommendation Report PRR No. Marketplace-PRR117 PRR
Title SPP Congestion Management
Timeline Normal Expedited Urgent Action
Provide explanation if Expedited and/or Urgent Action is selected:
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 1., 4.4.2.2.2, 4.4.2.6 (new), 4.4.2.6.1 (new), 4.4.2.6.2 (new), 4.4.2.6.3 (new) Title: Glossary, In-Operating Hour Inputs, SPP Congestion Management (new), SPP Congestion Management under TLR Operations (new), Congestion Management – Market Flow (new), NERC IDC Curtailments (new) Protocol Version: 13.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
Currently, the Protocols are not clear on how SPP will handle Real-Time congestion management in the Integrated Marketplace. This MPRR allows SPP to redispatch Resources with a Transmission Loading Relief (TLR) or Congestion Management Event (CME). This MPRR describes the process that will be used when a constraint causes real-time congestion. The definitions of CME and TLR are defined in this MPRR.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE 6.2.2.3 Seems Coordination
No
MWG Review PRR Recommendation
Date of Vote: 4/24/2013—Unanimously approved 6/28/2013—Unanimously approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A
RTWG Review 6/27/2013—Approved
ORWG Review 6/19/2013—Approved
MOPC Recommendation
EIS Market
Integrated Marketplace
MWG MPRR 117 Recommendation Report.docx 7/1/2013 Page 2 of 7
Board Review
Date 3/22/2013
Sponsor Name Chris Lax E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3594
Comments Received Comment Author Micha Bailey on behalf of MWG Date 4/26/2013
Comment Description Changed curtailable schedules to lower case because it is not a defined term. Changed definition of Market Flow to add clarity. The words “market dispatch” was replaced by “Resources serving market load”.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Comments Received
Comment Author Jason Smith on behalf of ORWG Date 6/19/2013
Comment Description ORWG deleted the word “NERC” out of “NERC IDC” to conform to MPRR121. ORWG changes highlighted in Yellow
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Proposed Protocol Language Revision
1. Glossary
Common Bus
A single bus to which two or more Resources that are owned by the same Asset Owner are connected in an electrically equivalent manner where such Resources may be treated as interchangeable for certain compliance monitoring purposes.
Congestion Management Event (CME)
An event during which constraints are activated in RTBM in order to re-dispatch the system to reduce the impact of SPP Market Flow on a Coordinated Flowgate or Reciprocal Coordinated Flowgate or in order to redispatch the system to remove projected limit violation on flowgates other than a Coordinated Flowgate or Reciprocal Coordinated Flowgate. This event may entail a parallel issuance of TLR.
Contingency Reserve
Resource capacity held in reserve for Resource contingencies which is the sum of Spinning Reserve and Supplemental Reserve.
MWG MPRR 117 Recommendation Report.docx 7/1/2013 Page 3 of 7
Market Clearing Price (MCP)
The price used for settlements of an Operating Reserve product in each Reserve Zone. A separate price is calculated for Regulation-Up, Regulation-Down, Spinning Reserve and Supplemental Reserve.
Market Flow
The impact on transmission system flowgate flows resulting from an operational entity’s market dispatch Resources serving market load within a defined market footprint.
Transmission Congestion Rights Markets
The Auction Revenue Rights annual and monthly allocation processes and the annual and monthly Transmission Congestion Rights auctions.
Transmission Loading Relief (TLR)
The NERC prescribed method for relieving congestion on Coordinated Flowgates and Reciprocal Coordinated Flowgates through reductions in tagged flow and Market Flow associated with these flowgates.
Turn-Around Ramp Rate Factor
A percentage factor between 0% and 100% applied to a Resources Ramp-Rate-Up or Ramp-Rate-Down that applies only in the next Dispatch Interval when the Resource is issued a Dispatch Instruction that is in the opposite direction of the previous Dispatch Instruction.
4.4.2.2.2 In-Operating Hour Inputs:
(1) Latest State Estimator solution for:
(a) dDistribution of load forecast throughout the Network Model;
(b) lLatest transmission topology for the Network Model; and
(c) bBackup initial energy injection of Resources if SCADA not available.
(2) Actual Resource output from latest SCADA snapshot to determine initial energy injection of Resources and Generator outages;
(3) Active transmission constraints including RCFs with firm flow entitlement adjustments if applicable where these constraints are selected and activated as described under Section 4.4.2.6;
(4) Intra-Hour adjustments to Interchange Transactions due to curtailments or initiation of a Reserve Sharing Event involving external Balancing Authorities;
(5) Intra-Hour adjustments to Resource Offer parameters;
(a) Market Participants are required to keep their Resource Offer operating parameters up-to-date during the Operating Day. In the event of a required change in a Resource Offer
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operating parameter due to physical Resource changes during an Operating Hour, the Market Participant is responsible for notifying SPP of required changes, and SPP will make the required modification for the current Operating Hour. Market Participants shall remain responsible for accurately reflecting Resource operating parameters in their Resource Offer submissions for subsequent hours.
(6) Intra-hour adjustments to selection of regulating Resources as described under Section 4.4.2.1;
(7) SPP Short-Term Load Forecast (STLF) as described under Section 4.1.2.1;
(a) SPP distributes the STLF down to the associated PNodes using weighting factors for modeling purposes as described under Section 4.1.2.1.6
(8) (7) Wind Resource output forecast as described under Section 4.1.2.2.
4.4.2.6 SPP Congestion Management
Except as provided for Emergency conditions as described under Section 4.4.2.5, when a constraint is observed in real-time, an SPP Congestion Management Event (CME) may be initiated and the constraint may be activated in RTBM. The CME can be initiated through declaration of a TLR and/or through an activation of a constraint in RTBM if an overload situation has been identified internal to the SPP Balancing Authority Area that does not require a TLR. SPP will declare a TLR if Curtailable Schedulecurtailable schedules exist in IDC above the curtailment threshold. A Ccurtailable Sschedule is defined as a tagged SPP Interchange Transaction, external Market Flows and/or external non-market Balancing Authority flows.
The CME will cause RTBM to produce a Security Constrained Economic Dispatch using all available dispatchable Resources to provide appropriate reduction in flows to relieve the constraint. An analysis will be performed to determine if Curtailable Schedulecurtailable schedules exist in IDC above the curtailment threshold for the current Operating Hour and the next hour. SPP will use RTBM to reliably manage and economically maximize the flow of power on flowgates to within the applicable operating limits as prescribed by NERC for CME events initiated either by IDC via a TLR or initiated through constraint activation for internal SPP constraints not requiring a TLR.
4.4.2.6.1 SPP Congestion Management under TLR Operations
If there are cCurtailable Sschedules in IDC at the SPP Congestion Management Event priority level in either the current Operating Hour or the next hour, a TLR will be requested through the IDC. When the TLR is requested, RTBM and the NERC IDC will work jointly to manage congestion on constrained flowgates between the SPP Balancing Authority Area and the applicable external Balancing Authority Areas.
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The appropriate level of TLR must be requested in the IDC. The IDC will prescribe curtailments of Curtailable Schedulecurtailable schedules. The IDC will also prescribe curtailment of SPP Market Flows. SPP will then activate or continue activation of the constraint in RTBM. All Interchange Transaction curtailments are fed into RTOSS from the IDC.
4.4.2.6.2 Congestion Management - Market Flow
As required by the Congestion Management Process (CMP) (Attachment 1 of the SPP-MISO Joint Operating Agreement), SPP will determine and submit to the NERC IDC its Market Flows on all SPP Coordinated Flowgates (CFs) and Reciprocal Coordinated Flowgates (RCFs). SPP’s CFs are flowgates identified as being impacted by activities within SPP. SPP’s RCFs are those flowgates identified as being impacted by activities within SPP and one or more entities operating under the requirements similar to those of the CMP. Currently those entities include SPP, MISO, MAPP, TVA and PJM. For additional details regarding the calculation of Market Flow, see SPP-MISO Joint Operating Agreement.
4.4.2.6.3 NERC IDC Curtailments The NERC IDC will receive all tagged transactions involving SPP. Under SPP RTBM operations, the NERC IDC will be responsible during TLR events for prescribing curtailment of certain types of tagged transactions and prescribing Market Flow relief that SPP must achieve internally.
The NERC IDC will be responsible for prescribing curtailment of only those tags associated with Interchange Transactions involving SPP for which impacts are not included in SPP’s Market Flows.
Proposed Tariff Language Revision
Attachment AE
6.2.2.3 Seams CoordinationCongestion Management
The Transmission Provider shall use the following process to coordinate the operations of
the RTBM to manage congestion within the SPP Balancing Authority Area and between the SPP
Balancing Authority Area and external Balancing Authority Areas:
(a) The Transmission Provider shall submit the Market Flow impact on each
Coordinated Flowgate and Reciprocal Coordinated Flowgate to the NERC IDC.
(b) The Transmission Provider shall assign curtailment priorities to the Market Flow
on each flowgate in the following priority categories:
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(i) Curtailment priorities for flowgates that have not been defined as a
Coordinated Flowgate or a Reciprocal Coordinated Flowgate shall be
assigned in accordance with NERC TLR procedures.
(ii) For Coordinated Flowgates, the Transmission Provider will assign Market
Flow in the firm priority up to the firm limit with any excess Market Flow
assigned as non-firm network.
(iii) For Reciprocal Coordinated Flowgates, the Transmission Provider will
divide its Market Flows into firm, non-firm network, and non-firm hourly
curtailment priorities. The Transmission Provider will first assign Market
Flow in the firm priority up to the firm limit, then assign remaining
Market Flow in the non-firm network priority up to the non-firm network
limit, and finally assign any excess Market Flow as non-firm hourly.
(c) The Market Flow associated with operation of the RTBM shall be determined by
the Transmission Provider. For Coordinated Flowgates, any Market Flow from
RTBM operation in excess of that assigned to the firm priority shall be assigned a
non-firm priority. For Reciprocal Coordinated Flowgates, any Market Flow from
RTBM operation [JG1] in excess of amounts assigned to firm or non-firm network
priorities shall be assigned a non-firm hourly priority.
(d) When congestion occurs on a flowgate that requires a TLR event, the NERC IDC
will identify the amount of relief required from Market Flows on the Coordinated
Flowgate or Reciprocal Coordinated Flowgate.
(e) When congestion occurs on a flowgate that does not require a TLR event, the
Transmission Provider shall manage such congestion using its security
constrained dispatch software until the flowgate loading is within its applicable
operating limits.
(ef) The Transmission Provider shall achieve the required reduction in Market Flows
provided by the NERC IDC using its security constrained dispatch software in the
following order until the desired reduction in Market Flows is achieved:
(i) To the extent that Market Flows are contributing to the constrained
condition, the Transmission Provider shall restrict the ability of the market
operating system from contributing further to the constrained condition by
binding the Coordinated Flowgate or Reciprocal Coordinated Flowgate
constraint. The security constrained dispatch of Dispatchable Resources
MWG MPRR 117 Recommendation Report.docx 7/1/2013 Page 7 of 7
shall continue within each priority level until the Market Flows within that
priority level have been reduced to zero or the flowgate constraint is
eliminated, whichever comes first.
Proposed Criteria Language Revision N/A
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PRR Recommendation Report PRR No. Marketplace-PRR118 PRR
Title Split-bus Logic for TCR Market
Timeline Normal Expedited Urgent Action
Provide explanation if Expedited and/or Urgent Action is selected:
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 5.2.2, 5.3.1, 5.5.1 Title: ARR Allocation, TCR Bid Submittal, TCR Bid and Offer Submittal Protocol Version: 13.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
Currently, Market Participants may take positions in SPP’s TCR Market that take advantage of price separation that is not due to congestion – especially within a single station – and may be paid out on a daily basis. This Protocol Revision Request (PRR) addresses these transactions by limiting the ability to purchase Transmission Congestion Rights (TCRs) within the same station to prevent this activity and the resulting costs to the market.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE: 7.2.2 Auction Revenue Right Allocation; 7.3.1 Transmission Congestion Right Offer and Bid Submittal; 7.5.1 Monthly Transmission Congestion Right Offer and Bid Submittal
No
MWG Review PRR Recommendation
Date of Vote: 5/21/2013 – Approved Unanimously All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A
RTWG Review 6/27/2013 – Approved
ORWG Review 6/19/2013 – Approved with No Reliability Impact
MOPC Recommendation
Board Review
EIS Market
Integrated Marketplace
MWG MPRR 118 Recommendation Report.docx 7/1/2013 Page 2 of 9
Date 3/22/2013
Sponsor Name Nick Parker E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3574
Comments Received Comment Author Nick Parker (SPP) Date 5/13/2013
Comment Description This MPRR was initially reviewed during the April 23rd MWG meeting. SPP had some action items to look into the affiliate and net effect language that was put into the MPRR. After some internal discussions, SPP has removed this language referring to affiliates and net effect.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Comments Received
Comment Author Debbie James on behalf of the MWG Date 5/21/2013
Comment Description Added language “prohibited collocated and electrically equivalent Settlement Location pairs” to Section 5.2, 5.3 and 5.5 of Integrated Marketplace Protocols.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Proposed Protocol Language Revision
5.2 Annual ARR Allocation Process The Annual ARR Allocation Process addresses how candidate ARRs verified in the Annual ARR Verification Process may be nominated and converted to ARRs. Eligible Entities may nominate the candidate ARRs that they wish to receive up to their ARR Nomination Caps. The annual allocation process determines the portion of the nominated candidate ARRs that are simultaneously feasible to allocate to each Eligible Entity. 100% of the SPP Residual Transmission System Capability, as defined under Section 5.2.3, is made available during the Annual ARR Allocation Process. Candidate ARRs are nominated on a monthly and seasonal basis in a three-round process. No later than five (5) Business Days prior to the start of the Annual ARR Allocation Process, SPP will post the transmission system network topology data for each of the monthly and seasonal on-peak and off-peak models, along with corresponding Parallel Flow, prohibited collocated and electrically equivalent Settlement Location pairs, and transmission line outage assumptions, that SPP will use in the upcoming allocation process for use by Eligible Entities in developing their candidate ARR nomination strategies. Exhibit 5-3 provides a representative timeline of the three-round annual ARR allocation process.
5.3 Annual TCR Auction The Annual TCR Auction Process is the mechanism through which Market Participants may obtain annual TCRs through submission of TCR Bids to purchase TCRs and/or through direct [MCRR5.1]conversion of ARRs into TCRs through self-conversion. Various percentages of the SPP
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Residual Transmission System Capability, as calculated under Section 5.2.3 is made available during the Annual TCR Auction Process as shown in Exhibit 5-2. TCRs in the annual auction are auctioned in a single round process for all months and seasons. If there are any changes to the transmission system topology, or Parallel Flow data, or prohibited collocated and electrically equivalent Settlement Location pairs after the conclusion of Annual ARR Allocation Process, SPP will post such changes no later than three (3) Business Days prior to the start of the Annual TCR Auction Process. Exhibit 5-5 provides a representative timeline of the two-round and single round annual TCR auction process.
5.5 Monthly TCR Auction Processes The Monthly TCR Auction Process is the mechanism through which Market Participants may obtain TCRs over and above those obtained in the Annual TCR Auction Process through submission of TCR Bids to purchase TCRs and/or through direct [MCRR5.2]conversion of remaining ARRs awarded in the Annual ARR Allocation Process and/or ARRs awarded in the IncrementalMonthly[MCRR6.3] ARR Allocation Process into TCRs through Self-Conversion. Market Participants may also offer for sale TCRs awarded in the Annual TCR Auction Process. 100% of the SPP Transmission System capability is made available during the Monthly TCR Auction Process. The remaining TCRs for the months of July through September are auctioned in a single-round process. The remaining TCRs for the months of October through May are auctioned in a two-round process. No later than three (3) Business Days prior to the start of the Monthly TCR Auction Process, SPP will post the transmission system network topology data, along with corresponding Parallel Flow, prohibited collocated and electrically equivalent Settlement Location pairs, and transmission line outage assumptions, that SPP will use in the upcoming Monthly TCR Auction Process for use by Market Participants in developing their TCR Bid, TCR Offer and/or TCR self-conversion strategies. Exhibit 5-6 provides a representative timeline of the single-round and two-round Monthly TCR Auction Processes.
5.2.2 ARR Allocation
ARRs are allocated in a three-round process as follows:
(1) In Round 1, Eligible Entities may nominate:
(a) ARRs from their NITS Candidate ARRs that total to no more than 50% of their NITS ARR Nomination Cap;
(b) ARRs from their GFA NITS Candidate ARRs that total to no more than 50% of their GFA NITS ARR Nomination Cap;
(c) ARRs from their FPTP Candidate ARRs that total to no more than 50% of their FPTP ARR Nomination Cap; and
(d) ARRs from their GFA FPTP Candidate ARRs that total to no more than 50% of their GFA FPTP ARR Nomination Cap.
(2) In Round 2, Eligible Entities may nominate:
MWG MPRR 118 Recommendation Report.docx 7/1/2013 Page 4 of 9
(a) ARRs from their NITS Candidate ARRs that total to no more than 100% of their NITS ARR Nomination Cap less any nominated NITS Candidate ARRs awarded in Round 1;
(b) ARRs from their GFA NITS Candidate ARRs that total to no more than 100% of their GFA NITS ARR Nomination Cap less any nominated GFA NITS Candidate ARRs awarded in Round 1;
(c) ARRs from their FPTP Candidate ARRs that total to no more than 100% of their FPTP ARR Nomination Cap less any nominated FPTP Candidate ARRs awarded in Round 1; and
(d) ARRs from their GFA FPTP Candidate ARRs that total to no more than 100% of their GFA FPTP ARR Nomination Cap less any nominated GFA FPTP Candidate ARRs awarded in Round 1.
(3) In Round 3, Eligible Entities may nominate from any source to sink that total to no more than 100% of their ARR Nomination Cap less any nominated candidate ARR amounts awarded in Rounds 1 and 2. In Round 3, a Market Participant is limited to a maximum combined submittal of 2000 ARR Nominations per product for each Asset Owner it represents. Market Participants may not obtainnominate candidate ARRs between Settlement LocationsResources that are collocated and electrically equivalent. other than from a firm TSR with the same Source Settlement Location and Sink Settlement Location to a maximum of that TSR MW amount. ARR Nominations may not be submitted by any combination of affiliated Market Participants which create the net effect of an ARR between ResourcesSettlement Locations that are collocated and electrically equivalent.
Exhibit 5-4 provides an example of valid Round 1 NITS Candidate ARR nominations for a NITS Transmission Customer with a three year average historical annual peak load of 1942 MW and total Candidate ARRs of 2400 MW.
Exhibit 5-1: Candidate ARR Nomination for NITS
NITS ARR Nomination
Cap
Round 1 ARR Nomination
Limit
NITS Candidate ARR MW
Source Sink Nominated NITS
Candidate ARR MW
2000 MW1 1000 MW2 1200 G1 L1 800
800 G2 L1 200
400 G3 L1 0
1 Lesser of (1.03 * 1942 MW) or 2400 MW 2 50% of ARR Nomination Cap
MWG MPRR 118 Recommendation Report.docx 7/1/2013 Page 5 of 9
Total 2400 1000
5.3.1 TCR Bid Submittal
(1) Any Market Participant that has satisfied the applicable credit requirements may participate in the Annual TCR Auction;
(2) Market Participants holding ARRs may elect to self-convert all or a portion of those ARRs into TCRs with the same source and sink by specifying the Self-Convert option as part of the TCR Bid submittal;
(3) For each month and season included in the Annual TCR Auction period, Market Participants may submit TCR Bids in 0.1 MW increments separately, for On-Peak and Off-Peak periods (8 separate transmission system models created representing each month in an annual auction period and on-peak and off-peak periods within each month and 6 separate transmission system models created representing each season in an annual auction period and on-peak and off-peak periods within each season). The following information is submitted for a TCR Bid:
(a) Source (any valid Settlement Location);
(b) Sink (any valid Settlement Location);
(c) Class (on-peak or off-peak);
(d) Period (month or season);
(e) Type (Bid, or Self-Convert);
(f) TCR MW;
(g) TCR Price ($/MW);
(i) TCR Bids cannot exceed $100,000/MW-Month;
(ii) TCR Bids cannot be less than ($100,000/MW-Month).
(4) For each TCR Round, a Market Participant is limited to a maximum combined submittal of 2000 TCR Bids for each Asset Owner it represents.
(5) Market Participants may not submit offers to buy obtain TCRs between ResourcesSettlement
Locations that are collocated and electrically equivalent. other than from a self-convert type bid
associated with an ARR with the same Source Settlement Location and Sink Settlement Location
to a maximum of that ARR MW amount. TCR bids may not be submitted by any combination of
affiliated Market Participants which create the net effect of an ARRTCR between
ResourcesSettlement Locations that are collocated and electrically equivalent.
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5.5.1 TCR Bid and Offer Submittal
(1) Any Market Participant that has satisfied the applicable credit requirements may participate in the Monthly TCR Auction Process;
(2) Market Participants may submit TCR Bids and TCR Offers separately, for On-Peak and Off-Peak periods (two (2) separate transmission system models created). The following information is submitted for a TCR Bid or TCR Offer:
(a) Source (any valid Settlement Location);
(b) Sink (any valid Settlement Location);
(c) Class (on-peak or off-peak);
(d) Type (Bid, Offer or Self-Convert);
(e) TCR MW (0.1 MW increments, may not exceed ARR MW held on path if Self-Convert Type selected);
(f) TCR Price ($/MW);
(i) TCR Bids and Offers cannot exceed $100,000/MW-Month;
(ii) TCR Bids and Offers cannot be less than ($100,000/MW-Month).
(3) For each TCR Round, a Market Participant is limited to a maximum combined submittal of 2000 TCR Bids and/or TCR Offers.
Market Participants may not obtainsubmit offers to buy TCRs between ResourcesSettlement Locations that are collocated and electrically equivalent. other than from a self-convert type bid associated with an ARR with the same Source Settlement Location and Sink Settlement Location to a maximum of that ARR MW amount. TCR bids may not be submitted by any combination of affiliated Market Participants which create the net effect of an ARR
Proposed Tariff Language Revision
7.2.2 Auction Revenue Right Allocation
ARRs are allocated in a three round process as follows:
(1) In round 1, Eligible Entities may nominate:
(a) ARRs from their Network Integration Transmission Service Candidate ARRs that
totals no more than fifty percent (50%) of their Network Integration Transmission
Service ARR Nomination Cap;
(b) ARRs from their Grandfathered Agreement Network Integration Transmission
Service Candidate ARRs that totals no more than fifty percent (50%) of their
Grandfathered Agreement Network Integration Transmission Service ARR
Nomination Cap;
MWG MPRR 118 Recommendation Report.docx 7/1/2013 Page 7 of 9
(c) ARRs from their Firm Point-To-Point Candidate ARRs that totals no more than
fifty percent (50%) of their Firm Point-To-Point ARR Nomination Cap; and
(d) ARRs from their Grandfathered Agreement Firm Point-To-Point Candidate ARRs
that totals no more than fifty percent (50%) of their Grandfathered Agreement
Firm Point-To-Point ARR Nomination Cap.
(2) In round 2, Eligible Entities may nominate:
(a) ARRs from their Network Integration Transmission Service Candidate ARRs that
totals no more than one hundred percent (100%) of their Network Integration
Transmission Service ARR Nomination Cap less any nominated Network
Integration Transmission Service Candidate ARRs awarded in round 1;
(b) ARRs from their Grandfathered Agreement Network Integration Transmission
Service Candidate ARRs that totals no more than one hundred percent (100%) of
their Grandfathered Agreement Network Integration Transmission Service ARR
Nomination Cap less any nominated Grandfathered Agreement Network
Integration Transmission Service Candidate ARRs awarded in round 1;
(c) ARRs from their Firm Point-To-Point Candidate ARRs that totals no more than
one hundred percent (100%) of their Firm Point-To-Point ARR Nomination Cap
less any nominated Firm Point-To-Point Candidate ARRs awarded in round 1;
and
(d) ARRs from their Grandfathered Agreement Firm Point-To-Point Candidate ARRs
that totals no more than one hundred percent (100%) of their Grandfathered
Agreement Firm Point-To-Point ARR Nomination Cap less any nominated
Grandfathered Agreement Firm Point-To-Point Candidate ARRs awarded in
round 1.
(3) In round 3, any Eligible Entity may nominate ARRs from any source to sink that totals no
more than one hundred percent (100%) of its ARR Nomination Cap less any nominated
candidate ARR amounts awarded in rounds 1 and 2. In this round an Eligible Entity is
limited to a maximum combined submittal of two-thousand (2,000) ARR nominations for
each Asset Owner it represents. Market Participants may not obtainnominate candidate
ARRs between ResourcesSettlement Locations that are collocated and electrically
equivalent. other than from a firm TSR with the same Source Settlement Location and
Sink Settlement Location to a maximum of that TSR MW amount. ARR Nominations
may not be submitted by any combination of affiliated Market Participants which create
MWG MPRR 118 Recommendation Report.docx 7/1/2013 Page 8 of 9
the net effect of an ARR between ResourcesSettlement Locations that are collocated and
electrically equivalent.
7.3.1 Transmission Congestion Right Offer and Bid Submittal
(1) Market Participants that have satisfied the applicable credit requirements may participate
in the annual TCR auction.
(2) Market Participants holding ARRs associated with a specific source and sink may elect to
self-convert all or a portion of those ARRs into TCRs by specifying the self-convert
option as part of the TCR Bid submittal.
(3) For each month and season included in the annual TCR auction, Market Participants may
submit TCR Bids in 0.1 MW increments, for On-Peak and Off-Peak periods. A valid
TCR Bid must contain the following information:
(a) Source: any valid Settlement Location;
(b) Sink: any valid Settlement Location;
(c) Class: On-Peak or Off-Peak;
(d) Period: specific month or season;
(e) Type: Bid or self-convert;
(f) TCR MW; and
(g) TCR Price;
(i) TCR Bids cannot exceed $100,000/MW-Month;
(ii) TCR Bids cannot be less than negative $100,000/MW-Month;
(4) For each TCR round, a Market Participant is limited to a maximum of 2,000 TCR Bids
for each Asset Owner it represents. Market Participants may not obtainsubmit offers to
buy TCRs between ResourcesSettlement Locations that are collocated and electrically
equivalent. other than from a self-convert type bid associated with an ARR with the
same Source Settlement Location and Sink Settlement Location to a maximum of that
ARR MW amount. TCR bids may not be submitted by any combination of affiliated
Market Participants which create the net effect of an ARR
7.5.1 Monthly Transmission Congestion Right Offer and Bid Submittal
(1) Market Participants that have satisfied the applicable credit requirements may participate
in the monthly TCR auction.
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(2) Market Participants may submit TCR Bids and Offers for On-Peak and Off-Peak periods.
The following information is submitted for a TCR Bid or Offer:
(a) Source: any valid Settlement Location;
(b) Sink: any valid Settlement Location;
(c) Class: On-Peak or Off-Peak;
(d) Type: Bid, Offer or self-convert;
(e) TCR MW: 0.1 MW increments, may not exceed ARR MW held on path if self-
convert type selected; and
(f) TCR Price:
(i) TCR Bids cannot exceed $100,000/MW-Month;
(ii) TCR Bids cannot be less than negative $100,000/MW-Month;
(3) Market Participants may not submit more than a total of 2,000 TCR Bids and Offers in
each TCR round for each Asset Owner it represents. Market Participants may not
obtainsubmit offers to buy TCRs between ResourcesSettlement Locations that are
collocated and electrically equivalent. other than from a self-convert type bid associated
with an ARR with the same Source Settlement Location and Sink Settlement Location to
a maximum of that ARR MW amount. TCR bids may not be submitted by any
combination of affiliated Market Participants which create the net effect of an ARRTCR
between Settlement Locations that are electrically equivalent.
Proposed Criteria Language Revision N/A
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PRR Recommendation Report PRR No. Marketplace-PRR120 PRR
Title MPRR Mitigated Offer Formula Corrections
Timeline
Normal Expedited Urgent Action Provide explanation if Expedited and/or Urgent Action is selected: This MPRR was created to provide Protocol changes and Tariff revisions as a result of MPRR112 Mitigated Offer Development Guidelines (Appendix G).
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 8.2.2.3; 8.2.2.4; 8.2.2.5; Appendix G 7.6 Title: Mitigation Measures for Energy Offer Curves; Mitigation Measures for Start-up and No-Load Offers; Mitigation Measures for Operating Reserves Offers; Appendix G Mitigated Offers Development Guidelines: Spinning Reserve: Hydro Unit Costs Protocol Version: 13.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
MCRR 10 was written as a result of a FERC order to “require SPP to include the details for development of mitigated offers for energy, each type of operating reserve, start-up and no-load in its Tariff”. (p420) MCRR 10 added the language to the Tariff Attachment AF (Sections 2 and 3) and to the Protocols (Section 8.2). MPRR112-Mitigated Offer Development Guidelines (Appendix G) changed formulas in Section 8.2.2.3, 8.2.2.4, and 8.2.2.5 in the Protocols. These formulas are deleted from Sections 8.2 of the Protocols and replaced with a reference to Appendix G. Appendix G will hold all formulas related to Mitigated Offers for the Protocols. Attachment AF (Sections 2 and 3) of the Tariff has been changed to match the formulas in Appendix G of the Protocols. Appendix G goes into detail on how to submit a Mitigated Offer. It has the formulas to show how to calculate the “mitigated offers for energy, each type of operating reserve, start-up and no-load” (p.420) that were required by FERC. The changes are reflected below in this MPRR.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AF: 2.3 Definitions (new); 3.2 Mitigation Measures for Energy Offer Curves; 3.3 Mitigation Measures for Start-Up Offers and No-Load Offers; 3.4 Mitigation Measures for Operating Reserve Offers
No
EIS Market
Integrated Marketplace
MWG MPRR 120 Recommendation Report.docx 7/19/2013 Page 2 of 16
MWG Review PRR Recommendation
Date of Vote: 5/8/2013 – Approved 6/28/2013 – Unanimously Approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: Abstained - GSEC
RTWG Review
5/22/2013 – Approved the modified tariff revisions in MPRR 120 to implement the protocols as approved by MWG in MPRR 112. RTWG Tariff changes highlighted in yellow. Segment of Parties that voted No or Abstained: Opposed - WFEC
ORWG Review 6/20/2013 – Approved with no Reliability Impact
MOPC Recommendation
Board Review
Date 5/10/2013
Sponsor Name Micha Bailey E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.2522
Comments Received Comment Author Micha Bailey on behalf of MWG Date 5/8/2013
Comment Description
1. Changed sentence structure on No-Load Fuel and No-Load Cost. 2. Added Appendix G Section 7.6 to Protocols to include changes to Mitigated Spinning Reserve Offer. The formula had an incorrect term (Condensing MW/start). The term was removed which corrected the equation. 3. Added VOM to No-Load Fuel Approach in the Tariff. 4. In Tariff, change word “capability” to “operating” in the Mitigated Spinning Reserve Offer to add clarity.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Comments Received
Comment Author Brenda Fricano on behalf of RTWG Date 5/22/2013 Comment Description RTWG updated some language in the Tariff.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Proposed Protocol Language Revision
MWG MPRR 120 Recommendation Report.docx 7/19/2013 Page 3 of 16
8.2.2.3 Mitigation Measures for Energy Offer Curves
Mitigated energy offer curves shall be submitted on a daily basis by the Market Participant in accordance with the Mitigated Offer Development Guidelines. The mitigated energy offer curve may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource is not committed by the DA Market, the mitigated energy offer curve may be updated until the Day-Ahead RUC process begins. For Resources committed by the DA Market, the mitigated energy offer curve submitted as of 1100 hours on the day before the Operating Day will apply to the DA Market on the day before the Operating Day and the RTBM on the Operating day; for all other Resources the mitigated energy offer submitted at the time the Day-Ahead RUC process begins will apply to the Day-Ahead RUC process on the day before the Operating Day, and the Intra-Day RUC processes and the RTBM on the Operating Day.
The Energy Offer Curve conduct thresholds are as follows:
(1) For Resources with local market power as described in Section 8.2.2.6(4), the threshold is a 10% increase above the Mitigated Energy Offer Curve;
(2) For Resources located in a Frequently Constrained Area and not subject to the threshold in Section 8.2.2.3(1), the threshold is a 17.5% increase above the Mitigated Energy Offer Curve.
(3) For all other Resources the threshold is a 25% increase above the Mitigated Energy Offer Curve.
The Transmission Provider shall apply mitigation measures by replacing the Energy Offer Curve with the Mitigated Energy Offer Curve if:
(1) The Resource’s Energy Offer Curve exceeds the Mitigated Energy Offer Curve by the applicable conduct threshold; and
(2) The Resource has local market power as determined in Section 8.2.2.6; and (3) The Resource either:
(a) Fails the Market Impact Test as described in Section 8.2.2.8, or (b) Has local market power as described in Section 8.2.2.6(4).
An Energy Offer below $25/MWh will not be subject to mitigation measures.
The Mitigated Energy Offer Curve shall be the resource’s short-run marginal cost of producing energy as determined by the unit’s heat rate, fuel costs and the costs related to fuel usage, such as transportation and emissions costs (“total fuel related costs”), and variable operations and maintenance costs (VOM) as detailed in the Mitigated Offer Development Guidelines. The following formula shall apply to all for Mitigated Energy Offer Curves can be found in Appendix G Section 2.5:
[MCB1]
Opportunity costs may be reflected in the total fuel related costs and/or the VOM under the following circumstances:
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(1) Externally imposed environmental run-hour restrictions; or (2) Physical equipment limitations on the number of starts or run-hours; or (3) Fuel supply limitations.
The Market Participant shall submit heat rates and the methods for determining fuel costs, fuel related costs including emissions costs, opportunity costs, and variable operation and maintenance costs to the Market Monitoring Unit. The information will be sufficient for replication of the Mitigated Energy Offer Curve. Further details associated with the development and validation of these costs are included in SPP’s Mitigated Offer Development Guidelines.
For Demand Response Resources with behind the meter generation the Mitigated Energy Offer Curve shall be developed in the same manner, described above, as any other generating Resource. For load response Demand Response Resources, the mitigated Energy Offer Curve shall reflect the quantifiable opportunity costs associated with the reduction, net of related offsetting increases in usage.
Intra-day changes to the Mitigated Energy Offer Curve are allowed under the following conditions:
(1) The Market Participant incurs higher fuel procurement costs due to a request by the Transmission Provider for a Resource to remain online past the scheduled commitment period by the DA Market or a RUC process; or
(2) A Resource must switch fuels due to unforeseen operating conditions;
Intra-day changes to the Mitigation Energy Offer Curve must follow the Mitigated Offer Development Guidelines and will be validated by the Market Monitor.
8.2.2.4 Mitigation Measures for Start-Up and No-Load Offers
A Mitigated Start-up Offer and a Mitigated No-load Offer shall be submitted daily by the Market Participant in accordance with the Mitigated Offer Development Guidelines. The Mitigated Start-up and No-load Offers may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource in not committed by the DA Market, the Mitigated Start-up and No-load Offers may be updated until the Day-Ahead RUC process begins. The Mitigated Start-up and No-load Offers submitted at the time the Day-Ahead RUC process begins will apply to the Day-Ahead RUC process on the day before the Operating Day and the Intra-Day RUC processes on the Operating Day.
The Start-Up and No-Load Offer conduct thresholds are as follows:
(1) For Resources with local market power as described in Section 8.2.2.6(4), the threshold is a 10%
increase above the mitigated offer for the applicable offer;
(2) For all other Resources the threshold is a 25% increase above the mitigated offer for the
applicable offer.
The Transmission Provider shall apply mitigation measures by replacing the Start-Up or No-Load Offer with the applicable Mitigated Start-up or mitigated No-load Offer if:
(1) The Resource’s Start-Up or No-Load Offer exceeds the mitigated offer by the applicable threshold; and
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(2) The Resource has local market power as determined in Section 8.2.2.6; and (3) The Resource fails the Market Impact Test as described in Section 8.2.2.8, or the Resource has local
market power as described in Section 8.2.2.6(4).
The mitigated Start-Up Offer shall represent the cost per start as determined from start fuel usage and the costs related to that fuel usage, electrical costs (station service), maintenance costs attributed to starts, and additional labor costs, if required above normal station manning levels. The following formula shall apply to allfor mitigated Start-Up Offers can be found in Appendix G Section 2.6:
[MCB2]
The mitigated Start-Up Offer for Demand Response resources shall be the cost to shut down or curtail load for a given period, which does not vary with output, or the start cost of a behind the meter generator.
The mitigated No-Load Offer shall be the hourly fixed cost required to create a monotonically increasing mitigated Energy Offer Curve. It shall be calculated according to either of two methods found in Appendix G Section 2.7 which are No-Load Fuel Approach and No-Load Cost Approach.:
(1) No-Load Fuel Approach
[MCB3]
(2) No-Load Cost Approach
[MCB4]
The Mitigated No-Load Offer for behind the meter Demand Response resources shall adhere to the same definition above as a generating Resource. For load response Demand Response Resources, the
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Mitigated No-Load Offer shall not exceed the quantifiable ongoing hourly costs associated with manufacturing process changes associated with a reduction in load consumption.
The Market Participant shall submit documentation of the method for calculating mitigated Start-Up and mitigated No-Load Offers that is adequate to permit the MMU to verify submitted offers. Further details associated with the development of these costs are included in SPP’s Mitigated Offer Development Guidelines.
8.2.2.5 Mitigation Measures for Operating Reserve Offers
A mitigated offer for each Operating Reserve product shall be submitted daily by the Market Participant in accordance with the Mitigated Offer Development Guidelines. The mitigated operating reserve offers may be updated up to 1100 hours on the day before the Operating Day for use in the DA Market. In the case a Resource is not committed by the DA Market, the mitigated operating reserve offers may be updated until the Day-Ahead RUC process begins. For Resources committed by the DA Market, the mitigated operating reserve offers submitted as of 1100 hours on the day before the Operating Day will apply to the DA Market on the day before the Operating Day and the RTBM on the Operating Day; for all other Resources, the mitigated operating reserve offers submitted at the time the Day-Ahead RUC process begins will apply to the RTBM on the Operating Day.
The offer conduct thresholds for each of the Operating Reserve products are as follows:
(1) For Resources with local market power as described in Section 8.2.2.6(4), the threshold is a 10% increase above the mitigated offer for the applicable Operating Reserve Offer;
(2) For all other Resources the threshold is a 25% increase above the mitigated offer for the applicable Operating Reserve Offer.
Any Operating Reserve Offer exceeding the applicable threshold, except offers below $10/MW, will be deemed excessive.
The Transmission Provider shall apply mitigation measures by replacing the relevant Operating Reserve Offer with the applicable mitigated operating reserve offer if:
(1) The Resource’s Operating Reserve Offer exceeds the mitigated offer by the applicable conduct threshold and;
(2) The Resource has local market power as determined in Section 8.2.2.6; and (3) The Resource either:
(a) Fails the Market Impact Test as described in Section 8.2.2.8, or (b) Has local market power as described in Section 8.2.2.6(4).
The mitigated Spinning Reserve Offer shall not exceed the sum of any increased fuel related costs necessary to be prepared for deployment for Spinning Reserves and any cost increase from heat rate degradation due to operating at lower loads:
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[MCB5] For load responding Demand Response Resources, the mitigated Spinning Reserve Offer shall not exceed the quantifiable costs necessary to be prepared to shut-down or curtail load. For behind the meter generation Demand Response Resources the mitigated Spinning Reserve Offer shall adhere to the same definition above for generating Resources.
The mitigated Spinning Reserve Offer shall be equal to zero for Resources other than CTs and Hydro Resource with synchronous condenser capability. No known incremental costs are incurred for providing Spinning Reserves from other resource types. Mitigated Spinning Reserve Offers for CTs and Hydro Resources with synchronous condenser capability are calculated as described in Appendix G, Sections 6 and 7.
The mitigated Supplemental Reserve Offer shall not exceed any fuel related costs and labor costs necessary for the unit to be prepared for deployment. The formula for mitigated Supplement Reserve Offer can be found in Appendix G Section 2.9:
[MCB6]
The mitigated Regulation-Up Offer shall not exceed the sum of the cost increase due to:
(1) Unit specific heat rate degradation due to operating at lower loads;
(1) The heat rate increase during non-steady state operation;
(2) An uncompensated increase in costs attributable to moving between a lower economic and a higher regulating minimum operating limit and operating at the higher regulating minimum operating limit;
(3)(2) The cost increase in variable operations and maintenance costs due to non-steady state operation; and
(3) Uncompensated costs attributable to moving from a higher economic to a lower regulating maximum operating limit and operating at the lower regulating maximum operating limit.
The formula for mitigated Regulation-Up and Regulation-Down Offers can be found in Appendix G Section 2.10
MWG MPRR 120 Recommendation Report.docx 7/19/2013 Page 8 of 16
[MCB7]
The mitigated Regulation-Down Offer shall not exceed the sum of the cost increase due to:
(1) Unit specific heat rate degradation due to operating at lower loads;
(1) The heat rate increase during non-steady state operation;
(2) An uncompensated increase in costs attributable to moving between a lower economic and a higher regulating minimum operating limit and operating at the higher regulating minimum operating limit;
(3)(2) The cost increase in variable operations and maintenance costs due to non-steady state operation; and
(4)(3) Uncompensated costs attributable to moving from a higher economic to a lower regulating maximum operating limit and operating at the lower regulating maximum operating limit:
[MCB8] Further details associated with the development of the exact costs in the formulas above are included in SPP’s Mitigated Offer Development Guidelines.
Appendix G - Mitigated Offers Development Guidelines
7.6 Spinning Reserve: Hydro Unit Costs
Note: The information in Section 2.7 contains basic Spinning Reserve information relevant for all unit types. The following additional information only pertains to hydro units if applicable.
Total spinning costs for Hydro units shall include the following components:
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Start costs – if applicable, start costs shall be applied when a unit moves from cold to condensing operations and when a unit moves from condensing operations to energy generation, but shall not be applied when a unit moves from energy generation to condensing operations.
In addition (+) identified variable Operating and Maintenance cost in $/hour. divided by the Spinning MW provided. These costs shall be totaled over the Maintenance Period and divided by total MWh generated over the maintenance period. These variable Operating and Maintenance costs shall include:
• Maintenance of Electric Plant as derived from FERC Account 544
• Maintenance of Reservoirs as derived from FERC Account 543
Total hydro condensing offers must be expressed in dollars per hour per MW of Spinning Reserve ($/MW) and must specify the total MW of Spinning Reserve offered.
Proposed Tariff Language Revision
Attachment AF
2. Definitions
2.2 Measures
SPP’s Market Mitigation Measures set forth in this document.
2.3 Performance Factor is the calculated ratio of actual fuel burn to either theoretical fuel
use (design heat input) or the most recent heat rate performance test, consistent with the
Market Protocols.
2.43 Plan
SPP’s Market Power Mitigation Plan set forth in this Attachment AF.
3.2 Mitigation Measures for Energy Offer Curves
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Mitigated Energy Offer Curves shall be submitted on a daily basis by the Market
Participant in accordance with the mitigated offer development guidelines in the Market
Protocols. The mitigated Energy Offer Curve may be updated up to 1100 hours on the
day before the Operating Day for use in the Day-Ahead Market. In the case a Resource is
not committed by the Day-Ahead Market, the mitigated Energy Offer Curve may be
updated until the Day-Ahead RUC begins. For Resources committed by the Day-Ahead
Market, the mitigated Energy Offer Curve submitted as of 1100 hours on the day before
the Operating Day will apply to the Day-Ahead Market on the day before the Operating
Day and the RTBM on the Operating Day; for all other Resources the mitigated Energy
Offer Curve submitted at the time the Day-Ahead RUC begins will apply to the Day-
Ahead RUC on the day before the Operating Day, and the Intra-Day RUC processes and
the RTBM on the Operating Day.
The Energy Offer Curve conduct thresholds are as follows:
(1) For Resources with local market power as described in Section 3.1(4), the
conduct threshold is a 10% increase above the mitigated Energy Offer Curve;
(2) For Resources located in a Frequently Constrained Area and not subject to
Section 3.2(1), the conduct threshold is a 17.5% increase above the mitigated
Energy Offer Curve;
(3) For all other Resources the conduct threshold is a 25% increase above the
mitigated Energy Offer Curve.
The Transmission Provider shall apply mitigation measures by replacing the Energy
Offer Curve with the mitigated Energy Offer Curve if:
(1) The Resource’s Energy Offer Curve exceeds the mitigated Energy Offer Curve by
the applicable conduct threshold; and
(2) The Resource has local market power as determined in Section 3.1; and
(3) The Resource either:
(a) Fails the Market Impact Test as described in Section 3.6, or
(b) Has local market power as described in Section 3.1(4).
An Energy Offer below $25/MWh will not be subject to mitigation measures.
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The mitigated Eenergy Ooffer Curve (“EOC”) shall be the Resource’s short-run
marginal cost of producing energy as determined by the unit’s heat rate; fuel costs and
the costs related to fuel usage, such as transportation and emissions costs (“total fuel
related costs”); and Energy Offer Curve (“EOC”) variable operations and maintenance
costs (“VOM”) as detailed in the Market Protocols. The following formula shall apply to
all mitigated Energy Offer Curves:
Mitigated Energy Offer ($/MWh) = HeatRate (mmBtu/MWh) *
Performance Factor * Total Fuel Related Costs ($/mmBtu) +EOC VOM ($/MWh)
Opportunity cost shall be an estimate of the Energy and Operating Reserve Markets
revenues net of short run marginal costs for the marginal foregone run time during the
period of limitation as detailed in the Market Protocols. Opportunity costs may be
reflected in the total fuel related costs and/or the VOM under the following
circumstances:
(1) Externally imposed environmental run-hour restrictions; or
(2) Physical equipment limitations on the number of starts or run-hours; or
(3) Fuel supply limitations.
The Market Participant shall submit heat rates and the methods for determining fuel
costs, fuel related costs including emissions costs, opportunity costs, and VOM to the
Market Monitoring Unit. The information will be sufficient for replication of the
mitigated Energy Offer Curve. Further details associated with the development and
validation of these costs are included in the Market Protocols.
For Demand Response Resources utilizing Behind-The-Meter Generation, the mitigated
Energy Offer Curve shall be developed in the same manner as any other generating
Resource as described above. For Demand Response Resources utilizing load reduction,
the mitigated Energy Offer Curve shall reflect the quantifiable opportunity costs
associated with the reduction, net of related offsetting increases in usage.
In the event that the Transmission Provider requests that a Resource remain online past
their commitment period by the Day-Ahead Market or a RUC process, the Market
Participant may submit an updated mitigated energy offer curve that reflects the
procurement of higher cost fuel. Intra-day changes to the mitigated energy offer curve
must follow the mitigated offer development guidelines in the Market Protocols and will
be validated by the Market Monitor.
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3.3 Mitigation Measures for Start-Up Offers and No-Load Offers
A mitigated Start-Up Offer and a mitigated No-Load Offer shall be submitted daily by
the Market Participant in accordance with the mitigated offer development guidelines in
the Market Protocols. The mitigated Start-Up and No-Load Offers may be updated up to
1100 hours on the day before the Operating Day for use in the Day-Ahead Market. In the
case a Resource is not committed by the Day-Ahead Market, the Start-Up and No-Load
Offers may be updated until the Day-Ahead RUC begins. The mitigated Start-Up and
No-Load Offers submitted at the time the Day-Ahead RUC begins will apply to the Day-
Ahead RUC on the day before the Operating Day and the Intra-Day RUC on the
Operating Day.
The Start-Up and No-Load Offer conduct thresholds are as follows:
(1) For Resources with local market power as described in Section 3.1(4), the
conduct threshold is a 10% increase above the mitigated Start-Up or mitigated
No-Load Offer, as applicable;
(2) For all other Resources the conduct threshold is a 25% increase above the
mitigated Start-Up or mitigated No-Load Offer, as applicable.
The Transmission Provider shall apply mitigation measures by replacing the Start-Up or
No-Load Offer with the applicable mitigated Start-Up or No-Load Offer if:
(1) The Resource’s Start-Up or No-Load Offer exceeds the mitigated Start-Up or
mitigated No-Load Offer, as applicable, by the applicable conduct threshold; and
(2) The Resource has local market power as determined in Section 3.1; and
(3) The Resource either:
(a) Fails the Market Impact Test as described in Section 3.6, or
(b) Has local market power as described in Section 3.1(4).
The mitigated Start-Up Offer shall represent the cost per start as determined from start
fuel usage and the costs related to that fuel usage, pPerformance fFactor, cost of
electricity for station use to start (“Station Service”), maintenance costs attributed to
starts, and additional labor costs, if required above normal station staffing levels. The
following formula shall apply to all mitigated Start-Up Offers:
Mitigated Start-Up Offer ($/Start) = [Start Fuel (mmBtu/Start) *
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Total Fuel Related Costs ($/mmBtu) * Performance Factor] + [Station Service
(MWh/Start) * Station Service Rate ($/MWh)] + Start Maintenance VOM Adder
($/Start) + Start Additional Labor Cost ($/Start)
The mitigated Start-Up Offer for Demand Response resources shall be the cost to shut
down or curtail load for a given period, which varies with the number of deployments
rather than the amount of response, and/or the start cost of Behind-The-Meter
Generation utilizing the mitigated Start-Up Offer calculation applicable to other
generation Resources as defined above.
The mitigated No-Load Offer shall be the hourly fixed cost required to create a
monotonically increasing mitigated Energy Offer Curve. It shall be calculated according
to either of two methods:
(1) No-Load Fuel Approach
Mitigated No-Load Offer ($/hour) = No Load Fuel (mmBtu/hour) * Performance
Factor * (No-Load VOM ($/mmBtu) + Total Fuel Related Cost ($/mmBtu))
(2) No-Load Cost Approach
Mitigated No-Load Offer ($/hour) =
(Heat Input at Min.Econ.Capacity (mmBtu/hour) * Performance Factor *
(Total Fuel Related Cost ($/mmBtu) + No Load VOM ($/mmBtu) ) ) –
(Incremental Cost up to Min.Econ.Capacity ($/MWh) * Min.Econ.Capacity
(MW))
The mitigated No-Load Offer for Demand Response Resources utilizing Behind-The-
Meter Generation shall adhere to the same definition above as a generating Resource.
For Demand Response Resources utilizing load reduction, the mitigated No-Load Offer
shall not exceed the quantifiable ongoing hourly costs associated with load reduction.
The Market Participant shall submit documentation of the method for calculating
mitigated Start-Up and mitigated No-Load Offers that is adequate to permit the
Market Monitor to verify submitted offers. Further details associated with the
development of these costs are included in the Market Protocols.
3.4 Mitigation Measures for Operating Reserve Offers
A mitigated offer for each Operating Reserve product shall be submitted daily by the
Market Participant in accordance with the mitigated offer development guidelines in the
Market Protocols. The mitigated Operating Reserve Offers may be updated up to 1100
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hours on the day before the Operating Day for use in the Day-Ahead Market. In the case
a Resource is not committed by the Day-Ahead Market, the mitigated Operating Reserve
Offers may be updated until the Day-Ahead RUC begins. For Resources committed by
the Day-Ahead Market, the mitigated Operating Reserve Offers submitted as of 1100
hours on the day before the Operating Day will apply to the Day-Ahead Market on the
day before the Operating Day and the RTBM on the Operating Day; for all other
Resources, the mitigated Operating Reserve Offers submitted at the time the Day-Ahead
RUC begins will apply to the RTBM on the Operating Day.
The offer conduct thresholds for each of the Operating Reserve products are as follows:
(1) For Resources with local market power as described in Section 3.1(4), the
conduct threshold is a 10% increase above the mitigated offer for the applicable
Operating Reserve Offer;
(2) For all other Resources, the conduct threshold is a 25% increase above the
mitigated offer for the applicable Operating Reserve Offer.
Any Operating Reserve Offer exceeding the applicable threshold, except offers below
$10/MWh, will be deemed excessive. The Transmission Provider shall apply mitigation
measures by replacing the Operating Reserve Offer with the applicable mitigated
Operating Reserve Offer if:
(1) The Resource’s Operating Reserve Offer exceeds the applicable mitigated offer by
the conduct threshold; and
(2) The Resource has local market power as determined in Section 3.2.2; and
(3) The Resource either:
(a) Fails the Market Impact Test as described in Section 3.6, or
(b) Has local market power as described in Section 3.1(4).
The mitigated Spinning Reserve Offer shall not exceed the sum of any increased fuel
related costs necessary for the Resource to be prepared for deployment of Spinning
Reserve and any cost increase from heat rate degradation due to operating at a lower
output level:
Mitigated Spinning Reserve Offer ($/MW) <
Marginal Increase in Total Fuel Related Cost +
Unit Specific Heat Rate Degradation due to Operating at a Lower Output Level
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For Demand Response Resources utilizing load reduction, the mitigated Spinning
Reserve Offer shall not exceed the quantifiable costs necessary to be prepared to shut-
down or curtail load. For Demand Response Resources utilizing Behind-The-Meter
Generation the mitigated Spinning Reserve Offer shall adhere to the same definition
above for generating Resources.
The mitigated Spinning Reserve Offer shall be equal to zero for Resources other than combustion turbines, reciprocating engines and hydro Resources withoperationg as a synchronous condenser capability. No known incremental costs are incurred for providing Spinning Reserves from other resource types.
Total mitigated Spinning Reserve Offer for combustion turbines, reciprocating engines and hydro rResources withoperating as a synchronous condenser capability shall not exceed any additional fuel related costs, maintenance costs and power consumption costs necessary for the Resource to be prepared for deployment of Spinning Reserve:
Mitigated Spinning Reserve Offer ($/MW) ≤
(Additional Fuel Cost($/Hr) + Additional Maintenance Cost ($/Hr) + Condensing
Power Cost ($/Hr) ) / Spinning Reserve MW
The mitigated Supplemental Reserve Offer shall not exceed any fuel related costs and
labor costs necessary for the Resource to be prepared for deployment of Supplemental
Reserve, and any cost increase from heat rate degradation due to operating at a lower
output level:
Mitigated Supplemental Reserve Offer ($/MW) ≤
Marginal Increase in Total Fuel Related Cost +
Unit Specific Heat Rate Degradation due to Operating at a Lower Output Level +
Additional Labor Cost($) / Average Supplemental Reserve MW
The mitigated Regulation-Up Offer shall not exceed the sum of the cost increase due to:
i. unit specific heat rate degradation due to operating at a lower output
level,
ii.i. the heat rate increase during non-steady state operation,
iii. uncompensated increase in costs attributable to moving between a lower
economic and a higher regulating minimum operating limit and operating
at the higher regulating minimum operating limit,
iv.ii. increase in VOM due to non-steady state operation,
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v.iii. uncompensated costs , as described in the Market Protocols attributable
to moving from a higher economic to a lower regulating maximum
operating limit and operating at the lower regulating maximum operating
limit:
Mitigated Regulation-Up Offer ($/MW) ≤
Unit Specific Heat Rate Degradation due to Operating at a Lower Output Level +
Cost Increase due to Heat Rate Increase during non-steady state operation
($/MW) + Uncompensated Minimum Operating Limit +
Cost Increase in VOM ($/MW) + Uncompensated Maximum Operating LimitCost
($/MW)
The mitigated Regulation-Down Offer shall not exceed the sum of the cost increase due
to:
i. unit specific heat rate degradation due to operating at a lower output
level,
ii.i. the heat rate increase during non-steady state operation,
iii. uncompensated increase in costs attributable to moving between a lower
economic and a higher regulating minimum operating limit and operating
at the higher regulating minimum operating limit,
iv.ii. increase in VOM due to non-steady state operation,
v.iii. uncompensated costs, as described in the Market Protocols attributable to
moving from a higher economic to a lower regulating maximum operating
limit and operating at the lower regulating maximum operating limit:
Mitigated Regulation-Down Offer ($/MW) ≤
Unit Specific Heat Rate Degradation due to Operating at a Lower Output Level +
Cost Increase due to Heat Rate Increase during non-steady state operation
($/MW) + Uncompensated Minimum Operating Limit +
Cost Increase in VOM ($/MW) + Uncompensated Maximum Operating LimitCost
($/MW)
Further details associated with the development of the exact costs in the formulas above
are included in the Market Protocols.
Proposed Criteria Language Revision N/A
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PRR Recommendation Report PRR No. Marketplace-PRR121 PRR
Title Removal of NERC’s Administration of Reliability and Grid Management Tools
Timeline Normal Expedited Urgent Action
Provide explanation if Expedited and/or Urgent Action is selected:
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 4.2.2.7, 4.2.3.3, 4.2.4, 4.2.5 Title: Import Interchange Transaction Offers; Export Interchange Transaction Bids; Through Interchange Transactions; Ramp Reservation Requirements; Protocol Version: 13.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
NERC is terminating its administration of reliability tools IDC and SDX. SPP will continue its utilization of these tools through a separate association with other Reliability Coordinators and users. As NERC is terminating its relationship with these tools, all Protocol, Tariff and Criteria references that associate NERC with these tools should be revised. Any references to NERC that remain in the Protocols, Tariff and Criteria related to IDC or other reliability tools are obsolete.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment G Network Operating Agreement Section 6 Scheduling Procedures Attachment AE Integrated Marketplace Section 6.2.2.3 Seams Coordination
No
MWG Review PRR Recommendation
Date of Vote: 5/22/2013 – Approved unanimously 5/29/2013 – Unanimously approved RTWG's modifications All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A
RTWG Review 5/22/2013 – Approved with modifications Changes highlighted in Yellow
ORWG Review 6/19/2013 – Approved with no Reliability Impact
MOPC Recommendation
Board Review
EIS Market
Integrated Marketplace
MWG MPRR 121 Recommendation Report.docx 6/19/2013 Page 2 of 13
Date 5/3/2013
Sponsor Name Matthew Harward E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3560
Comments Received Comment Author Matthew Harward on behalf of RTWG Date 5/24/2013
Comment Description Added attachment “C” to match EIS deletion of “NERC”. Attachment G added “E-“ to tag for clarification.
Comment Status
Proposed Protocol Language Revision
4.2.2.7 Import Interchange Transaction Offers
Market Participants may submit offers to sell Energy coming from outside of the SPP Balancing Authority Area for use in the DA Market and/or RTBM using their existing network or point-to-point service or spot market transmission service. The following rules apply to Import Interchange Transaction Offer submittal.
(1) The MW amount of Import Interchange Transactions will be limited on a Dispatch Interval basis by the amount of SPP system ramping capability available. Market Participants must use the SPP ramp reservation system as described under Section 4.2.5 to ensure there is sufficient ramp to accommodate their transaction;
(2) Import Interchange Transaction Offers will be submitted via NERC E-tag and Real-Time Operations Scheduling System (RTOSS) as described under the SPP OATT Business Practices. Additional fields will be available through E-tagging to identify transaction type and to submit price-based information as necessary;
(3) Three types of Import Interchange Transaction Offers will be supported: Fixed, Dispatchable and Up-To-Transmission Usage Charge or ‘Up-to-TUC”.
(a) A Fixed Offer is a specified MW that will be cleared regardless of the price at the External Interface Settlement Location (Source GCA specified on NERC E-tag). If the Fixed Import Interchange Transaction is submitted for use in the DA Market, it will be cleared in the DA Market and automatically roll forward as a fixed schedule for use in RUC and the RTBM. If specified for use in the RTBM only, the Fixed Import Interchange Transaction will be considered a fixed schedule for the RUC processes and RTBM.
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(b) A Dispatchable Offer specifies both a MW amount and a minimum $/MWh price that the Market Participant must be paid if the transaction clears the DA Market. Dispatchable Offers are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a fixed schedule for use in RUC and the RTBM. Any adjustment to the schedule will be settled as a deviation from the DA Market.
(c) An Up-To-TUC Offer specifies both a MW amount and the maximum amount of congestion cost and marginal loss cost, in $/MWh, between the specified NERC E-tag Source and Sink Settlement Location the Market Participant is willing to pay if the transaction clears the DA Market. Up-To-TUC Offers are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a fixed schedule for use in the RUC and RTBM. Any adjustment to the schedule will be settled as a deviation from the DA Market.
4.2.3.3 Export Interchange Transaction Bids
Market Participants may submit bids to purchase Energy from the DA Market for sale outside of the SPP Balancing Authority Area. A Market Participant must reserve transmission service prior to submittal of the Bid in accordance with the procedures specified in the SPP OATT Business Practices. The following rules apply to Export Interchange Transaction Bid submittal.
(1) The MW amount of Export Interchange Transactions will be limited on a Dispatch Interval basis by the amount of SPP system ramping capability available. Market Participants must use the SPP ramp reservation system as described under Section 4.2.5 to ensure there is sufficient ramp to accommodate their transaction;
(2) Export Interchange Transaction Bids will be submitted via NERC E-tag and RTOSS. Additional fields will be available through E-tagging to submit price-based information as necessary;
(3) Three types of Export Interchange Transaction Bids will be supported: Fixed, Dispatchable and Up-To-TUC;
(a) A Fixed Bid is a specified MW that will be cleared regardless of the price at the External Interface Settlement Location (Sink LCA specified on NERC E-tag). If the Fixed Export Interchange Transaction is submitted for use in the DA Market, it will be cleared in the DA Market and automatically roll forward as a fixed schedule for use in RUC and the RTBM. If specified for use in the RTBM only, the Fixed Export Interchange Transaction will be considered a fixed schedule for the RUC processes and RTBM.
(b) A Dispatchable Bid specifies both a MW amount and a maximum $/MWh price that the Market Participant is willing to pay if the transaction clears the DA Market. Dispatchable Bids are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a Fixed schedule for use in RUC and the
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RTBM. Any adjustment to the schedule will be settled as a deviation from the DA Market.
(c) An Up-To-TUC Bid specifies both a MW amount and the maximum amount of congestion cost and marginal loss cost, in $/MWh, between the specified NERC E-tag Source and Sink Settlement Location the Market Participant is willing to pay if the transaction clears the DA Market. Up-To-TUC Bids are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a Fixed schedule for use in the RUC and RTBM. Any adjustment to the schedule will be settled as a deviation from the DA Market.
(4) Export Interchange Transaction Bids are eligible to supply Supplemental Reserve subject to meeting the follow eligibility requirements:
(a) The Market Participant must notify SPP as part of their NERC eE-Tag of their intent to supply Supplemental Reserve with an Export Interchange Transaction Bid;
(b) The Export Interchange Transaction Bid must be fixed and submitted for use in the DA Market;
(c) The Export Interchange Transaction must be fully recallable within a 10-minute period for the amount of Supplemental Reserve specified;
(d) An Export Interchange Transaction Bid may reduce the Market Participant’s Supplemental Reserve obligation. The reduction to Market Participant’s Supplemental Reserve obligation will be the lesser of (i) the reduction in the system requirement based on the delivery of reserve energy, provided by the curtailment of the export schedule as determined by SPP; or (ii) the Market Participant’s Supplemental Reserve obligation. The reduction, if applied, will be proportional to the Market Participant’s zonal Supplemental Reserve obligation;
(e) Supplemental Reserve supplied by an Export Interchange Transaction in excess of the Market Participant’s Supplemental Reserve obligation within the Reserve Zone will not be eligible for payment.
(f) Provision of Supplemental Reserve from an Export Interchange Transaction Bid is limited to Export Interchange Transactions associated to DC tie-lines.
4.2.4 Through Interchange Transactions
Energy scheduled through the SPP Balancing Authority Area will be settled in the DA Market, RTBM or both. A Market Participant must reserve transmission service prior to submittal of the schedule in accordance with the procedures specified in the SPP OATT Business Practices in an amount sufficient to cover the request.
(1) Through Interchange Transactions will be submitted via NERC E-tag and RTOSS;
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(2) Two types of Through Interchange Transactions will be supported: Fixed and Up-To-TUC;
(a) A Fixed Through Interchange Transaction is a specified MW that will be cleared regardless of the price at either of the External Interface Settlement Locations (Source GCA and Sink LCA specified on E-Tag). If submitted for use in the DA Market, a Fixed Through Interchange Transaction will automatically roll forward as a Fixed schedule for use in RUC and the RTBM. If submitted for use in the RTBM, the Fixed Through Interchange Transaction will clear in the RTBM and will be considered a fixed schedule for use in any RUC Processes.
(b) An Up-To-TUC Through Interchange Transaction specifies both a MW amount and the maximum amount of congestion cost and marginal loss cost, in $/MWh, between the specified E-Tag Source GCA and Sink LCA Settlement Location the Market Participant is willing to pay if the transaction clears the DA Market. Up-To-TUC Through Interchange Transactions are only available for use in the DA Market. If the transaction clears the DA Market, it automatically rolls forward as a Fixed schedule for use in the RUC and RTBM. Any adjustment to the schedule in the RTBM would be settled as a deviation from the DA Market.
4.2.5 Ramp Reservation Requirements
SPP uses a ramp reservation system to limit schedule changes to an amount equal to or less than the available ramp capability. The ramp reservation system allows SPP to ensure that sufficient ramp is available before the schedules created under Sections 4.2.2.7 and 4.2.3.3 are approved. SPP determines a limit for the net amount of schedule change into or out of the SPP BA for any 10 minute period based on projected available ramping capability and updates these limits on an ongoing basis. SPP will not approve schedules that violate this limit.
Market Participants may optionally submit requests to reserve ramping capability. A ramp reservation can be made to “hold” ramp room while Market Participants complete their scheduling responsibilities. Ramp reservations are then associated on the NERC Tag when the Market Participant submits the schedule. The ramp reservation is validated against the submitted NERC Tag to ensure the energy profile and path matches. If a Market Participant does not submit a specific request, the ramp reservation system will automatically generate a ramp reservation when the schedule is submitted, if there is sufficient ramp capability available. The follow business rules apply to submittal and approval of ramp reservation requests:
(1) There are two time periods during which Market Participants can submit requests to reserve ramping capability:
(a) Up to 1100 hours on the day prior to the Operating Day in order to reserve ramping capability for import or export transactions that clear in the DA Market. Any unused
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reserved ramping capability is made available for use in import and/or export scheduling in the RTBM for the Operating Day.
(b) Beginning at 1100 hours on the day prior to the Operating Day, ramp reservation requests may be submitted for import and/or export scheduling in the RTBM for the Operating Day, up to 30 minutes prior to the Operating Hour.
(2) Market Participant ramp reservation requests are evaluated and granted on a first come, first served basis;
(3) Market Participants may be required to shift their schedule requests in order to get their ramp reservation requests approved. If the Market Participant shifts their schedule up to one hour in either direction, they are not required to purchase additional transmission;
(4) If a Market Participant chooses to fix their ramp violation by extending the duration of the transaction, they do not have to purchase additional transmission if the total MWh capacity of the transmission request is not exceeded;
(5) Market Participants may submit one or more schedules associated with one or more approved ramp reservations, such that the sum of the submitted schedule MWhs do not exceed the MWhs of approved ramp on that path. Any approved ramp reservations for a path in excess of the associated schedules is released for use in the RUC processes and RTBM;
SPP updates available ramping capability on a five (5) minute basis.
Proposed Tariff Language Revision Attachment C
4. Base Case Models
The AFC process generates a base case model that simulates anticipated system conditions. The base system conditions include projected load, generation dispatch, network topology (based on system configuration and both planned and contingency outages), and base flow transactions. The impacts on Flowgates due to transactions outside the purpose of representing NR exchange are removed by applying the DFs determined to each transaction identified in the base case. In addition to adjusting the model flow in this manner, positive and Counterflows of existing OASIS commitments are applied according to the type of Base Loading (Firm or Non-Firm) under consideration. 50% of Counterflows resulting from firm Confirmed reservations act to reduce the Non-Firm Base Loading. This process establishes the Base Loading expected to serve the Network Load. The base flows are based on AC power flow calculations performed by RTRFCALC using the following data:
- Network topology - Hourly load forecast data of the Balancing Authority Areas
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- Net interchange of the Balancing Authority Areas - Unit dispatch data
4.1 Operating Horizon
The AFC calculations of the Operating, Planning, and Study Horizons are performed by RTRFCALC in combination with webTrans. WebTrans receives the following information from RTRFCALC:
- base flows for all Flowgates, - DFs for all paths, and - TFC values for all Flowgates.
The base flows are the product of the AC powerflow calculations performed by RTRFCALC using following data:
4.1.1 Network Topology
Network topology is established by the State Estimator. The models for the first four hours following the latest State Estimator snapshot include all outages, both planned and contingency, that existed in the State Estimator snapshot. Models for the remaining hours of the Operating Horizon are adjusted with hour-to-hour outage data of generators, transmission lines and transformers as submitted by Balancing Authorities within the SPP Reliability Coordination Area and approved by the Reliability Coordinator. This outage data includes both planned outages and contingency outages that are expected to remain in effect for each hour modeled. The Transmission Provider shall also include outage data from neighboring Reliability Coordinators that is available through NERC System Data Exchange (SDX). 4.1.2 Load Forecast The hourly load forecast data (for day 1 – day 7) is created by the Transmission Provider for the State Estimator model from the short-term and mid-term load forecast tools that use weather data from weather stations spread over the Transmission System and historical actual load data received from Balancing Authorities within the SPP Reliability Coordination Area. The Transmission Provider also includes load forecast data from neighboring Reliability Coordinators that is available through NERC SDX. The Transmission Provider derives load forecast data for day 8 – day 31 from the data of day 1 – day 7 by applying a factor that represents an historical increase or decrease of load on weekly basis during the year. 4.1.3 Net Interchange The net interchange of the Balancing Authority Areas that are part of the State Estimator Model is based on the existing schedules at the time the RTRFCALC application perform its Operating Horizon run at least once per day. The schedule data is retrieved from NERC Tagdump and from SPP’s scheduling system (RTOSS). 4.1.4 Unit Dispatch
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RTRFCALC utilizes unit dispatch data for all units within the SPP Balancing Authority Area and for the Balancing Authority Areas adjacent to the SPP Balancing Authority Area. The unit dispatch data of commonly dispatched units of a Balancing Authority Area is based on real time behavior of the units in the last 3 weeks. The unit dispatch data of units not commonly dispatched with the other units of an external Balancing Authority Area, is based on the Firm confirmed reservations that have the units’ zone name identified as the source on the reservations.
4.2 Planning Horizon The AFC calculations of the Operating, Planning, and Study Horizons are performed by RTRFCALC application in combination with webTrans.
WebTrans receives the following information from RTRFCALC:
- base flows for all Flowgates, - DFs for all paths, and - TFC values for all Flowgates.
The base flows are a product of the AC power flow calculations performed by RTRFCALC using following data:
4.2.1 Network Topology
Network topology is established by the State Estimator and adjusted with hour-to-hour outage data of generators, transmission lines and transformers. Such outage data shall be as submitted by Transmission Operators and Generation Operators that are within the SPP Reliability Coordination Area and approved by the Reliability Coordinator. This outage data includes both planned outages and contingency outages that are expected to remain in effect for each time period modeled. The Transmission Provider shall also include outage data from neighboring Reliability Coordinators that is available through NERC SDX.
4.2.2 Load Forecast
The hourly load forecast data (for day 1 – day 7) is created by the Transmission Provider for the State Estimator from the short-term and mid-term load forecast tools that use weather data from weather stations spread over the Transmission System and historical actual load data received from Transmission Operators within the SPP Reliability Coordination Area. The Transmission Provider also includes load forecast data from neighboring Reliability Coordinators that is available through NERC SDX. The Transmission Provider derives load forecast data for day 8 – day 31 from the data of day 1 – day 7 by applying a factor that represents an historical increase or decrease of load on weekly basis during the year. 4.2.3 Net Interchange Initially, the model assumes the net interchange of the Balancing Authority Areas is 0. If a Balancing Authority Area has a confirmed network reservation from a NR outside the Balancing Authority Area boundary, that reservation is incorporated into the net interchange of both Balancing Authority Areas. That particular network reservation will be added to the exclude file to prevent double counting of impacts.
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4.2.4 Unit Dispatch RTRFCALC utilizes unit dispatch data for all units within the SPP Balancing Authority Area and for the Balancing Authority Areas adjacent to the the SPP Balancing Authority Area. The unit dispatch data of commonly dispatched units of a Balancing Authority Area is based on real time behavior of the units in the last 3 weeks. The unit dispatch data of units not commonly dispatched with the other units of an external Balancing Authority Area is based on the Firm confirmed reservations that have the units’ zone identified as the source on the reservations.
4.3 Study Horizon
The AFC calculations of the Operating, Planning, and Study Horizon are performed by RTRFCALC application in combination with webTrans. WebTrans receives the following information from RTRFCALC:
- Base flows for all Flowgates, - DFs for all paths, and - TFC values for all Flowgates.
The base flows are a product of the AC power flow calculations performed by RTRFCALC using the following data: 4.3.1 Network Topology Network topology is established by the State Estimator and adjusted for outages of generators, transmission lines and transformers. Such outage data shall be as submitted by Transmission Operators and Generation Operators that are within the SPP Reliability Coordination Area and approved by the Reliability Coordinator. This outage data includes both planned outages and contingency outages that are expected to remain in effect for some period within this horizon. The Transmission Provider also includes outage data from neighboring Reliability Coordinators that is available through NERC SDX. The Transmission Provider includes approved planned outages and contingency outages which are active on 15th of the month and last more than 15 days.
4.3.2 Load Forecast
The Transmission Provider utilizes monthly forecast data from the EIA411 annual report. For Balancing Authority Areas not included in the EIA411 annual report, the Transmission Provider uses forecast data that is available through NERC SDX. 4.3.3 Net Interchange Initially, the model assumes net interchange of the Balancing Authority Areas is 0. If a Balancing Authority Area has a confirmed network reservation from a NR outside the Balancing Authority Area boundary, that reservation is incorporated into the net interchange of both Balancing Authority Areas. That particular network reservation will be added to the exclude file to prevent double counting of impacts. 4.3.4 Unit Dispatch
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RTRFCALC utilizes unit dispatch data for all units within the SPP Balancing Authority Area and for the Balancing Authority Areas adjacent to the Transmission System. The unit dispatch data of commonly dispatched units of a Balancing Authority Area is based on real time behavior of the units in the last three weeks. The unit dispatch data of units not commonly dispatched with the other units of an external Balancing Authority Area is based on the Firm confirmed reservations that have the units’ zone identified as the source on the reservations.
4.4 Exclusion of Reservations in the Calculations of AFC Values
The Transmission Provider shall exclude or limit certain reservations under the following conditions:
- If total sum of reservations (Confirmed, Accepted, Study) impacting a specific corridor exceeds the total capacity of the corridor, - If total sum of reservations (Confirmed, Accepted, Study) sinking in a Balancing Authority Area exceeds the total load of the Balancing Authority Area, - If total sum of reservations (Confirmed, Accepted, Study) sourcing from a group of commonly dispatched units exceeds the total available generation capacity of that group of units. - If the reservation is a network reservation from a NR outside the Balancing Authority Area boundary and that particular reservation is already included in the base flow calculations of the Study Horizon.
4.5 Resynchronization of Base Loading Values The Transmission Provider uses webTrans to evaluate Transmission Service requests that are submitted by Transmission Customers on OASIS. RTRFCALC recalculates the base flows and DF values of the Operating Horizon every hour at least once per day. RTRFCALC recalculates the base flows and DF values of the Planning Horizon at least once per day. The base flows of the Study Horizon are calculated and updated in webTrans once per month. Every month the Transmission Provider reviews the changes to outage data and, if necessary, recalculates the base flows for the Study Horizon to account for the changes in outage data. Finally, webTrans recalculates Firm and Non-Firm Base Loading upon each change of status of a reservation that impacts the relevant Base Loading. WebTrans makes adjustments to Firm and Non-Firm Base Loading upon the change of the following inputs: For Firm ETC
• The transmission capability utilized in serving native load commitments, to include native load growth, load forecast error and losses not otherwise included in TRM or CBM. • The impact of Firm Network Integration Transmission Service serving Network Load, to include load forecast error and losses not otherwise included in TRM or CBM.
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• The impact of grandfathered firm Transmission Service agreements and bundled contracts for energy and transmission, where executed prior to the effective date of a Transmission Service Provider’s OATT or Safe Harbor Tariff accepted by FERC. • The impact of Firm Point-To-Point Transmission Service into, out of or through the SPP Balancing Authority Area. • The impact of maintaining roll-over rights for firm Transmission Service contracts, five years or longer in duration, granting Transmission Customers the right of first refusal to take or continue to take Transmission Service from a Transmission Owner when the Transmission Customer’s Transmission Service contract expires or is eligible for renewal. • The impact of any Ancillary Services not otherwise included in CBM or TRM. • Postbacks of redirected or released Firm services. • The impact of Counterflows not otherwise accounted for in the AFC calculation. • The impact of any other services, contracts, or agreements not specified above using transmission that serves native load or Firm Network Integration Transmission Service. • The impact of any relevant third-party firm Transmission Service that has not already been accounted for.
For Non-Firm ETC,
• The impact of Non-Firm Network Integration Transmission Service serving load, to include load forecast error and losses not otherwise included in TRM or CBM. • The impact of grandfathered non-firm Transmission Service Agreements and bundled contracts for energy and transmission, where executed prior to the effective date of a Transmission Service Provider’s OATT or Safe Harbor Tariff accepted by FERC. • The impact of Non-Firm Point-To-Point Transmission Service into, out of or through the SPP Balancing Authority Area. • The impact of Counterflows not otherwise accounted for in the ATC calculation. • Capacity utilized for TRM that the Transmission Service Provider has elected to be released for as Non-Firm ATC. • Postbacks due to the reinstating of Firm from a “Firm-to-Non-Firm” redirect. • The impact of any relevant third-party non-firm Transmission Service that has not already been accounted for. 4.6 Changes in TFC
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In the event of a change in Network Topology due to actual or anticipated system conditions that impacts one or more TFC values, the Transmission Provider shall adjust the TFC in the EMS RTRFCALC for the applicable time periods. The Network Topology from the SPP State Estimator shall be adjusted as described in sections 4.1.1, 4.2.1, and 4.3.1 for the applicable horizons.
Attachment G
6.0 Scheduling Procedures
6.1 The Network Customer is responsible for providing its Resource and load information to
the Transmission Provider in accordance with Attachment AE.
6.2 For Interchange Transactions the Network Customer shall submit, or arrange to have
submitted, the schedule of Energy to or from the Transmission Provider and a NERC
transaction identification E-Tag for each such schedule where required by NERC
Standard INT-001. Attachment AE
6.2.2.3 Seams Coordination
The Transmission Provider shall use the following process to coordinate the operations of
the RTBM to manage congestion between the SPP Balancing Authority Area and external
Balancing Authority Areas:
(a) The Transmission Provider shall submit the Market Flow impact on each
Coordinated Flowgate and Reciprocal Coordinated Flowgate to the NERC IDC.
(b) The Transmission Provider shall assign curtailment priorities to the Market Flow
on each flowgate in the following priority categories:
(i) Curtailment priorities for flowgates that have not been defined as a
Coordinated Flowgate or a Reciprocal Coordinated Flowgate shall be
assigned in accordance with NERC TLR procedures.
(ii) For Coordinated Flowgates, the Transmission Provider will assign Market
Flow in the firm priority up to the firm limit with any excess Market Flow
assigned as non-firm network.
(iii) For Reciprocal Coordinated Flowgates, the Transmission Provider will
divide its Market Flows into firm, non-firm network, and non-firm hourly
curtailment priorities. The Transmission Provider will first assign Market
Flow in the firm priority up to the firm limit, then assign remaining
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Market Flow in the non-firm network priority up to the non-firm network
limit, and finally assign any excess Market Flow as non-firm hourly.
(c) The Market Flow associated with operation of the RTBM shall be determined by
the Transmission Provider. For Coordinated Flowgates, any Market Flow from
RTBM operation in excess of that assigned to the firm priority shall be assigned a
non-firm priority. For Reciprocal Coordinated Flowgates, any Market Flow from
RTBM operation in excess of amounts assigned to firm or non-firm network
priorities shall be assigned a non-firm hourly priority.
(d) When congestion occurs on a flowgate that requires a TLR event, the NERC IDC
will identify the amount of relief required from Market Flows on the Coordinated
Flowgate or Reciprocal Coordinated Flowgate.
(e) The Transmission Provider shall achieve the required reduction in Market Flows
provided by the NERC IDC using its security constrained dispatch software in the
following order until the desired reduction in Market Flows is achieved:
(i) To the extent that Market Flows are contributing to the constrained
condition, the Transmission Provider shall restrict the ability of the market
operating system from contributing further to the constrained condition by
binding the Coordinated Flowgate or Reciprocal Coordinated Flowgate
constraint. The security constrained dispatch of Dispatchable Resources
shall continue within each priority level until the Market Flows within that
priority level have been reduced to zero or the flowgate constraint is
eliminated, whichever comes first.
Proposed Criteria Language Revision N/A
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PRR Recommendation Report PRR No. Marketplace-PRR122 PRR
Title Offer Curve and Bid Curve Development Clarifications
Timeline Normal Expedited Urgent Action
Provide explanation if Expedited and/or Urgent Action is selected:
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 1., 4.2.2.1, 4.2.2.6, 4.2.3.1, 4.2.3.2 Title: Glossary; Resource Offer Parameters; Virtual Energy Offers; Demand Bids; Virtual Energy Bids Protocol Version: 13.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description Sufficient detail was not included in the Market Protocols regarding Offer curve and Bid curve submittal rules which caused the MUI Business Validation Rules for submittal of Demand Bid curves and Virtual Energy Bid curves to be invalid.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE 4.3.1 Demand Bids
No
MWG Review PRR Recommendation
Date of Vote: 5/29/2013 – Unanimously approved 6/28/2013 – Unanimously approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A
RTWG Review 6/27/2013 – Approved
ORWG Review 6/19/2013 – Approved with no Reliability Impact
MOPC Recommendation
Board Review
EIS Market
Integrated Marketplace
MWG MPRR 122 Recommendation Report.docx 7/1/2013 Page 2 of 14
Date 5/3/2013
Sponsor Name Jared Greenwalt E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.8314
Comments Received Comment Author Micha Bailey on behalf of MWG Date 5/31/2013
Comment Description MWG added the word “to” for clarification in section 4.2.3.2 in front of the word zero.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Comments Received
Comment Author Jared Greenwalt (SPP) Date 5/31/2013
Comment Description Tariff language was modified in Attachment AE, Section 4.3.1 (Demand Bids) to more closely match the Protocol language in 4.2.3.1 (Demand Bids).
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Comments Received
Comment Author Jared Greenwalt on behalf of MWG Date 6/28/2013
Comment Description A sentence was added to Demand Bid and Virtual Bid sections to describe pricing below the lowest MW point submitted. Graphs were also added in these sections to illustrate this concept.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Proposed Protocol Language Revision
1. Glossary Demand Bid Curve
As defined in the SPP Tariff.
Virtual Energy Bid Curve
As defined in the SPP Tariff.
4.2.2.1 Resource Offer Parameters
The following Resource Offer parameters must be submitted to constitute a valid offer for use in either the DA Market or RTBM:
(1) Resource Name (as specified during Market Registration and cannot be changed as part of Resource Offer submittal);
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(2) Start-Up Offer ($/Start, Hot, Intermediate and Cold – Unit Commitment)1;
(3) Mitigated Start-Up Offer ($/Start, Hot, Intermediate and Cold – Unit Commitment);
(4) No-Load Offer ($/Hour)1;
(5) Mitigated No-Load Offer ($/Hour) 1;
(6) Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, slope or block option, monotonically non-decreasing $/MWh, increasing MW and slope or block optionblock and slope pairs may not coexist – the Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs);
(a) Block and slope pairs may not coexist. The Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs.
(a)(b) The price of all MWhs below the first pricing point MWh is equal to the first pricing point price. The price of all MWhs above the last pricing point MW is equal to the last pricing point price.
(b)(c) Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-4 illustrates Energy Offer Curves developed from submitted price/MWh pairs for both the slope and block options.
1 For Market Participants that have registered a JOU under the Combined Resource Option (see Section Error! Reference source not found.), this value must be submitted by or on behalf of the designated Asset Owner and represents the value for the entire Physical JOU Resource. See Section 4.2.2.5.4)
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Exhibit 4-1: Energy Offer Curve Development
(7) Mitigated Energy Offer Curve (MW, $/MWh, up to 10 price/quantity pairs, slope or block
option, monotonically non-decreasing $/MWh, increasing MW and slope or block option, block and slope pairs may not coexist – the Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs);
(a) Block and slope pairs may not coexist. The Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs.
(8) Regulation-Up Offer ($/MW); (9) Mitigated Regulation-Up offer ($/MW); (10) Regulation-Down Offer ($/MW); (11) Mitigated Regulation-Down Offer ($/MW); (12) Spinning Reserve Offer ($/MW); (13) Mitigated Spinning Reserve Offer ($/MW); (14) Supplemental Reserve Offer ($/MW);
MW $/MW100 20.00200 40.00400 60.00500 80.00
Submitted DataEnergy Offer Curve
0.00
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
0 100 200 300 400 500 600
MW
$/M
Wh
Slope Option
Block Option
MW $/MWh100 20.00200 40.00400 60.00500 80.00
Submitted Data
Slope Option
Block Option
0.00
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
0 100 200 300 400 500 600
$/M
Wh
MW
Energy Offer Curve
Slope Option
Block Option
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(15) Mitigated Supplemental Reserve Offer ($/MW) (16) Sync-To-Min Time (hours:minutes – Unit Commitment)1; (17) Min-To-Off Time (hours:minutes – Unit Commitment)1; (18) Start-Up Time (hours:minutes, Hot, Intermediate, Cold – Unit Commitment)1; (19) Hot to Intermediate Time (hours:minutes– Unit Commitment)1; (20) Hot to Cold Time (hours:minutes– Unit Commitment)1; (21) Maximum Daily Starts (Unit Commitment)1; (22) Maximum Weekly Starts – rolling 7-day (Unit Commitment1; (23) Maximum Daily Energy (MWh – Unit Commitment)1; (24) Minimum Run Time (hours:minutes– Unit Commitment)1; (25) Maximum Run Time (hours:minutes– Unit Commitment)1; (26) Minimum Down Time (hours:minutes– Unit Commitment)1; (27) Minimum Emergency Capacity Operating Limit (MW); (28) Minimum Emergency Capacity Run Time (hours:minutes – Operations Information); (29) Minimum Normal Capacity Operating Limit (MW); (30) Minimum Economic Capacity Operating Limit (MW); (31) Minimum Regulation Capacity Operating Limit (MW); (32) Maximum Regulation Capacity Operating Limit (MW); (33) Maximum Economic Capacity Operating Limit (MW); (34) Maximum Normal Capacity Operating Limit (MW); (35) Maximum Emergency Capacity Operating Limit (MW); (36) Maximum Emergency Capacity Run Time (hours:minutes – Operations Information); (37) Maximum Quick-Start Response Limit (MW, this represents the maximum amount of
Supplemental Reserve that may be supplied by an off-line Quick-Start Resource)1; (38) Ramp-Rate-Up (curve, MW/Minute - for use when the Resource is not selected for Regulation-
Up and/or Regulation-Down clearing and dispatched in the up direction). Ramp-Rate-Up submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);
(a) Breakpoint Limit 1 – Resource MW output at which segment 1 Ramp-Rate-Up will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Ramp-Rate-Up in Block 1 will apply back to the actual measured MW.
(b) Block 1 Ramp Rate Up – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to Breakpoint Limit 1.
(c) Block 1 Ramp Rate Emergency – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to Breakpoint Limit 1 during an Emergency.
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(d) Breakpoint Limit n – Resource MW output at which Ramp-Rate-Up changes from previous segment values to segment n values.
(e) Block n Ramp-Rate-Up – Rate at which Resource can change output upward in MW/min at output levels greater than or equal to the Breakpoint Limit n
(f) Block n Ramp-Rate-Up Emergency – Rate at which Resource can change output upward in MW/min at output levels greater than the Breakpoint Limit n and less than Breakpoint Limit n+1 during an Emergency.
(39) Ramp-Rate-Down (curve, MW/Minute - for use when the Resource is not selected for Regulation-Up and/or Regulation-Down clearing and dispatched in the Down direction). Ramp-Rate-Down submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);
(a) Breakpoint Limit 1 – Resource MW output at which segment 1 Ramp-Rate-Down will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Ramp-Rate-Down in Block 1 will apply back to the actual measured MW.
(b) Block 1 Ramp Rate Down – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to Breakpoint Limit 1.
(c) Block 1 Ramp-Rate-Down Emergency – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to Breakpoint Limit 1 during an Emergency.
(d) Breakpoint Limit n – Resource MW output at which Ramp-Rate-Down changes from previous segment values to segment n values.
(e) Block n Ramp-Rate-Down – Rate at which Resource can change output downward in MW/min at output levels greater than or equal to the Breakpoint Limit n.
(f) Block n Ramp-Rate-Down Emergency – Rate at which Resource can change output downward in MW/min at output levels greater than the Breakpoint Limit n and less than Breakpoint Limit n+1 during an Emergency
(40) Turn-Around Ramp Rate Factor (a percentage between 0% and 100%). This factor is used to adjust a Resource’s Ramp-Rate-Up or Ramp-Rate-Down in a Dispatch Interval for which a Resource’s Energy Dispatch Instruction has changed direction from the previous Dispatch Interval and is only used in the RTBM. For example, if in the last Dispatch Interval the Resource’s Dispatch Instruction was in the up direction and in the current Dispatch Interval its Dispatch Instruction is in the down direction, this factor is applied to the Resource’s Ramp-Rate-Down prior to the calculation of the actual Dispatch Instruction in that Dispatch Interval. A submittal of 0% creates a Ramp-Rate-Up or Ramp-Rate-Down of 0 MW/Min and a
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submittal of 100% indicates no change to the Resource’s Ramp-Rate-Up or Ramp-Rate-Down. Additionally, the Turn-Around Ramp Rate Factor is applied to limit on-line Contingency Reserve clearing when a Resource’s Energy Dispatch Instruction in the previous Dispatch Interval was in the down direction. The Turn-Around Ramp Rate Factor does not apply to a Resource that is selected as available to be cleared for Regulation-Up and/or Regulation Down;
(41) Regulation Ramp Rate (curve, MW/Minute - for use when the Resource is selected for Regulation-Up and/or Regulation Down clearing). Regulation Ramp Rate submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);
(a) Breakpoint Limit 1 – Resource MW output at which segment 1 Regulation Ramp Rate will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Regulation Ramp Rate in Block 1 will apply back to the actual measured MW.
(b) Block 1 Regulation Ramp Rate – Rate at which a Resource on Automatic Generation Control can change output in the up and down direction in MW/min at output levels greater than or equal to Breakpoint Limit 1.
(c) Breakpoint Limit n – Resource MW output at which Regulation Ramp Rate changes from previous segment values to segment n values.
(d) Block n Regulation Ramp Rate – Rate at which Resource on Automatic Generation Control can change output in the up and down direction in MW/min at output levels greater than or equal to the Breakpoint Limit n.
(42) Contingency Reserve Ramp Rate (curve, MW/Minute). Contingency Reserve Ramp Rate submittal is through a segmented profile as follows. Each profile will require at least one (1) segment and may have up to n segments where n will be defined by SPP, initially set to ten (10);
a. Breakpoint Limit 1 – Resource MW output at which segment 1 Contingency Reserve Ramp Rate will apply. In the RTBM, if the actual measured MW during deployment is less than the Breakpoint Limit 1, the Contingency Reserve Ramp Rate in Block 1 will apply back to the actual measured MW.
b. Block 1 Contingency Reserve Ramp Rate – Rate at which a Resource not on Automatic Generation Control can change output in the up direction in MW/min when deploying Contingency Reserve at output levels greater than or equal to Breakpoint Limit 1.
c. Breakpoint Limit n – Resource MW output at which Contingency Reserve Ramp Rate changes from previous segment values to segment n values.
d. Block n Contingency Reserve Ramp Rate – Rate at which Resource not on Automatic Generation Control can change output in the up direction in MW/min
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when deploying Contingency Reserve at output levels greater than or equal to the Breakpoint Limit n.
(43) Resource Status (see Section Error! Reference source not found.); and (44) JOU Ownership Percent Share (Unit Commitment)2.
4.2.2.6 Virtual Energy Offers
Virtual Energy Offers are supported in the DA Market only. Virtual Energy Offers are purely financial, only apply to Energy and are not associated with a physical Resource asset. The following rules apply to Virtual Energy Offer submittal.
(1) A Virtual Energy Offer can be submitted by a Market Participant at any Settlement Location;
(2) A Market Participant may submit a single Virtual Energy Offer for each Asset Owner at any Settlement Location for a particular Hour in the form of a Virtual Energy Offer Curve (MW, $/MWh, up to ten (10) price/quantity pairs, and slope or block option, block and slope pairs may not coexist – the Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs). The submitted MW values must be increasing and the submitted $/MWh values must be monotonically non-decreasing. A Virtual Energy Offer will clear when the price at the applicable Settlement Location is greater than or equal to the specified curve price for that Operating Hour. with tThe highest MW quantity submitted in the Virtual Energy Offer Curve representsing the maximum MW amount that can be cleared. The minimum MW amount that can be cleared is equal to zero;
(a) Block and slope pairs may not coexist. The Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs.
(b) If the LMP is less than the lowest $/MWh submitted in the curve, then the cleared MWs will be zero.
(c) Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-5 illustrates Virtual Energy Offer curves developed from submitted price/MWh pairs for both the slope and block options.
Exhibit 4-5: Virtual Energy Offer Curve Development
2 Only applicable for the designated Asset Owner identified by the Market Participant that has registered a JOU under the Combined Resource Option (see Section 4.2.2.5.4). A value for each Asset Owner must be submitted by or on behalf of the designated Asset Owner and represents each Asset Owners percentage share of the Physical JOU Resource and must add up to 100%.
MWG MPRR 122 Recommendation Report.docx 7/1/2013 Page 9 of 14
(2)(3) Each Virtual Energy Offer must specify a start and stop Hour within the applicable Operating Day;
(3)(4) Virtual Energy Offers are subject to a transaction fee as described under Section Error! Reference source not found..
4.2.3.1 Demand Bids
Only Market Participants with registered load assets may submit Demand Bids for use in the DA Market. Demand Bids are associated with physical load assets. The following rules apply to Demand Bid submittal:
(1) A Market Participant can only submit Demand Bids for the registered load Settlement Location of the Asset Owner(s);
(2) Two types of Demand Bids will be supported: Fixed and Price Sensitive;
(a) A Fixed Demand Bid is a specified MW that will be cleared in the DA Market regardless of the price at the Load Settlement Location based on the start and stop time submitted for the applicable Operating Day.
(b) A Pprice Ssensitive Demand Bid is specified as a Demand Bid Curve (MW, $/MWh, up to 10 price/quantity pairs, and slope or block option, block and slope pairs may not coexist – the Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs). that The submitted MW values must be increasing and the submitted $/MWh values must be monotonically non-increasing. A price sensitive Demand Bid will clear only ifwhen the price at the applicable Load Settlement Location is less than or equal to the specified curve price for that Operating Hour. The maximum MW amount that can be cleared is equal to within the specified start and stop time submitted for
MW $/MWh100 20.00200 40.00400 60.00500 80.00
Submitted Data
Slope Option
Block Option
0.00
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
90.00
0 100 200 300 400 500 600
$/M
Wh
MW
Virtual Energy Offer Curve
Slope Option
Block Option
MWG MPRR 122 Recommendation Report.docx 7/1/2013 Page 10 of 14
the applicable Operating Day with the highest MW quantity submitted in the Demand Bid Curve representing. The minimum MW amount that can be cleared is equal to zero. the maximum MW amount that can be cleared. The price of all MWhs below the lowest MW amount submitted is equal to the first pricing point price.
(i) Block and slope pairs may not coexist. The price sensitive Demand Bid in effect for any given period of time must be comprised of all block or all slope price/quantity pairs
(ii) If the LMP is greater than the highest $/MWh submitted in the curve, then the cleared MWs will be zero.
(iii) Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-6 illustrates Demand Bid Curves developed from submitted price/MWh pairs for both the slope and block options.
Exhibit 4-6: Demand Bid Curve Development
MW $/MWh50 120.00
100 100.00200 80.00400 60.00500 40.00550 20.00
Submitted Data
0.00
20.00
40.00
60.00
80.00
100.00
120.00
140.00
0 100 200 300 400 500 600
$/M
Wh
MW
Demand Bid Curve
Slope Option
Block Option
MWG MPRR 122 Recommendation Report.docx 7/1/2013 Page 11 of 14
4.2.3.2 Virtual Energy Bids
Virtual Energy Bids are supported in the DA Market only. Virtual Energy Bids are purely financial in nature, only apply to Energy and are not associated with a physical Load asset. The follow rules apply to Virtual Energy Bid submittal.
(1) A Virtual Energy Bid can be submitted at any Settlement Location;
(2) A Market Participant may submit a single Virtual Energy Bid for each Asset Owner at any Settlement Location for a particular Hour in the form of a Virtual Energy Bid Curve (MW, $/MWh, up to 10 price/quantity pairs, and slope or block option, block and slope pairs may not coexist – the Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs). The submitted MW values must be increasing and the submitted $/MWh values must be monotonically non-increasing. A Virtual Energy Bid will clear when the price at the applicable Settlement Location is less than or equal to the specified curve price for that Operating Hour. The maximum MW amount that can be cleared is equal to the highest MW quantity submitted in the Virtual Energy Bid Curve. The minimum MW amount that can be cleared is equal to zero. with the highest MW quantity submitted in the Virtual Energy Bid Curve representing the maximum MW amount that can be cleared; The price of all MWhs below the lowest MW amount submitted is equal to the first pricing point price.
(a) Block and slope pairs may not coexist. The Resource Offer in effect for any given period of time must be comprised of all block or all slope price/quantity pairs
MW $/MW50 120.00
100 100.00200 80.00400 60.00500 40.00550 20.00
Submitted Data
0.00
20.00
40.00
60.00
80.00
100.00
120.00
140.00
0 100 200 300 400 500 600
$/M
W
MW
Demand Bid Curve
Slope Option
Block Option
MWG MPRR 122 Recommendation Report.docx 7/1/2013 Page 12 of 14
(b) If the LMP is greater than the highest $/MWh submitted in the curve, then the cleared MWs will be zero.
(c) Under the slope option, the set of price points that are submitted are used as the beginning and ending values for calculating a linear slope for each set of beginning and ending values. Therefore, each MW between the two price points has a different price due to the interpolation of the submitted price points. Under the block option, each MW between the two MW points is offered at the price of the larger MW point. Exhibit 4-7 illustrates Virtual Energy Bid Curves developed from submitted price/MWh pairs for both the slope and block options.
Exhibit 4-7: Virtual Energy Bid Curve Development
MW $/MWh50 120.00
100 100.00200 80.00400 60.00500 40.00550 20.00
Submitted Data
0.00
20.00
40.00
60.00
80.00
100.00
120.00
140.00
0 100 200 300 400 500 600
$/M
Wh
MW
Virtual Energy Bid Curve
Slope Option
Block Option
MWG MPRR 122 Recommendation Report.docx 7/1/2013 Page 13 of 14
(2)(3) Each Virtual Energy Bid must specify a start and stop Hour within the applicable Operating Day;
(3)(4) Virtual Energy Bids are subject to a transaction fee as described under Section Error! Reference source not found..
Proposed Tariff Language Revision
Attachment AE
4.3.1 Demand Bids
(1) Only Market Participants with registered physical load assets may submit Demand Bids
for use in the Day-Ahead Market.
(2) A Market Participant can submit Demand Bids only at Settlement Locations where its
physical load assets are registered.
(3) A fixed Demand Bid is a specified MW that will be cleared in the Day-Ahead Market
regardless of the price at the load Settlement Location based on the start and stop time
submitted for the applicable Operating Day.
(4) A price sensitive Demand Bid is specified as a Demand Bid Curve. A price sensitive
Demand Bid will clear only ifwhen the price at the applicable load Settlement Location is
less than or equal to the specified Demand Bid Curve price for that Operating Hour.
within the specified start and stop time submitted for the applicable Operating Day with
The maximum MW amount that can be cleared is equal to the highest Megawatt quantity
MW $/MWh50 120.00
100 100.00200 80.00400 60.00500 40.00550 20.00
Submitted Data
0.00
20.00
40.00
60.00
80.00
100.00
120.00
140.00
0 100 200 300 400 500 600
$/M
Wh
MW
Virtual Energy Bid Curve
Slope Option
Block Option
MWG MPRR 122 Recommendation Report.docx 7/1/2013 Page 14 of 14
submitted in the Demand Bid Curve representing the maximum Megawatt amount that
can be cleared. The minimum MW amount that can be cleared is equal to zero.
Proposed Criteria Language Revision N/A
MWG MPRR 123 Recommendation Report.docx 6/28/2013 Page 1 of 5
PRR Recommendation Report PRR No. Marketplace-PRR123 PRR
Title Quick-Start Resource Treatment
Timeline Normal Expedited Urgent Action
Provide explanation if Expedited and/or Urgent Action is selected:
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 4.4.2.3, 4.4.2.3.1 Title: RTBM Execution, Quick-Start Resource Logic Protocol Version: 13.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
Original language relating to treatment of Quick-Start Resources included under Section 4.4.2.3(6) incorrectly contemplates use of a look-ahead SCED to determine commitment of Quick Start Resources within the Operating Hour. Look-ahead SCED is an economic dispatch process that runs before the Real-Time economic dispatch process that anticipates adjustment of dispatch instructions in future dispatch intervals. This revision documents the treatment of Quick-Start Resources within Real-Time economic dispatch, which is similar to the current Quick-Start Resource treatment in the EIS Market, and revises the use of look-ahead SCED results for use in determining commitment of Resources within the Operating Hour with start-up times of greater than 10 minutes.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE; Section 6.2.2 Real-Time Balancing Market Execution
No
MWG Review PRR Recommendation
Date of Vote: 5/29/2013 – Approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: Abstained - WR
RTWG Review 6/27/2013 – Approved
ORWG Review 6/19/2013 – Approved
MOPC Recommendation
EIS Market
Integrated Marketplace
MWG MPRR 123 Recommendation Report.docx 6/28/2013 Page 2 of 5
Board Review
Date 5/3/2013
Sponsor Name Yasser Bahbaz E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.1607
Proposed Protocol Language Revision
4.4.2.3 RTBM Execution
SPP executes the RTBM every 5-minutes for the next Dispatch Interval based on the inputs described above.
(1) A simultaneous co-optimization methodology utilizing a SCED algorithm is employed to calculate Resource Dispatch Instructions and clear Regulation-Up, Regulation Down, Spinning Reserve and/or Supplemental Reserve to meet the SPP Short-Term Load Forecast and Operating Reserve requirements at minimum costs based upon submitted Offers while respecting Resource operating constraints and transmission constraints;
(2) The SCED algorithm includes marginal loss sensitivity factors which approximate the change in marginal system losses for a change in Energy dispatch. Inclusion of these factors further optimizes the Energy dispatch and reduces overall production costs;
(3) In certain situations, enforcing constraints may result in a solution that is not feasible at a Shadow Price less than an appropriately priced VRL. In such cases, SPP must apply Violation Relaxation Limits (VRLs) in SCED as described under Section 4.1.4;
(4) To ensure rational pricing of cleared Operating Reserve products, the SCED algorithm will include product substitution logic as follows:
(a) Any Regulation-Up Offers remaining once the Regulation-Up Requirement is satisfied may be used to meet Contingency Reserve requirements if Regulation-Up Offer is more economic or is needed to meet the overall Operating Reserve requirement;
(b) Any Spinning Reserve Offers remaining once the Spinning Reserve Requirement is satisfied may be used to meet the Supplemental Reserve requirements if the Spinning Reserve Offer is more economic or is needed to meet the overall Operating Reserve requirement.
MWG MPRR 123 Recommendation Report.docx 6/28/2013 Page 3 of 5
The product substitution logic ensures that the MCP for Regulation-Up is always greater than or equal to the Spinning Reserve MCP and that the Spinning Reserve MCP is always greater than or equal to the Supplemental Reserve MCP.
(5) To ensure that Market Participants are indifferent as to whether they are cleared for Energy or Operating Reserve, the co-optimization logic will provide through the Shadow Price calculation Market Clearing Prices for Operating Reserve that include any lost opportunity costs incurred as a result of Operating Reserve clearing;
(6) Additionally, SPP executes a look-ahead SCED prior to the RTBM SCED process. The look-ahead SCED results will be used to:perform at least these two functions: (1) anticipate the need to adjust Dispatch Instructions for the current Dispatch Interval to prepare to meet forecasted changes in the load several Dispatch Intervals into the future and (2) assist in determineing commitment of Quick-Start Resources within the Operating Hour that have cold Start-Up Times greater than 10 minutes and can be on-line within the Operating Hour. The look-ahead period is at least two Dispatch Intervals, one of which is the next Dispatch Interval following the current Dispatch Interval.
4.4.2.3.1 Quick-Start Resource Logic
For Resources with a cold Start-Up Time of 10 minutes or less that have submitted a Commitment Status = “Market’, an Energy Dispatch Status = “Market”, a Spinning Reserve Dispatch Status = “Fixed” or “Market” and a regulation Dispatch Status of “Fixed” or “Market”, SCED will consider such Resources as available for Energy dispatch and Operating Reserve clearing based on the rules described in Table below.
SCED Quick-Start Resource Logic
Is Resource
Synchronized? MP Submitted
Control Status1
Eligible for Energy
Dispatch
Eligible for Spinning Reserve
Clearing
Eligible for Regulation Clearing
Eligible for Supplemental
Reserve Clearing
Not Synchronized
Off-line No No No Yes
Non-Regulating
Yes No No Yes
Regulating Yes No No Yes
Manual No No No No
Synchronized Non- Yes Yes No Yes
1 See Exhibit 4-11 for Control Status descriptions
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Regulating
Regulating Yes Yes Yes Yes
Manual Yes No No No
SCED will only consider RTBM Energy Offer Curves and Operating Reserve Offers to determine Energy Dispatch Instructions and/or Operating Reserve cleared for Quick-Start Resources. Quick-Start Resources dispatched by SCED in this manner will not be eligible for RUC Make-Whole-Payment compensation as described under Section 4.5.9.8.
Proposed Tariff Language Revision
Attachment AE
6.2.2 Real-Time Balancing Market Execution
The Transmission Provider will execute the RTBM every five (5) minutes for the next
Dispatch Interval based on the inputs described above.
(1) A simultaneous co-optimization methodology utilizing a SCED algorithm is employed to
calculate Resource Dispatch Instructions and clear Regulation-Up, Regulation Down,
Spinning Reserve and Supplemental Reserve to meet the Transmission Provider load
forecast and Operating Reserve requirements at minimum costs based upon submitted
Offers while respecting Resource operating constraints and transmission constraints.
Resource Dispatch Instructions may include Dispatch Instructions for Quick-Start
Resources that are off-line as further described in the Market Protocols. Quick-Start
Resources dispatched in this manner are not eligible for compensation under Section
8.6.5 of this Attachment AE.
(2) The SCED algorithm includes marginal loss sensitivity factors that approximate the
change in marginal system losses for a change in Energy dispatch.
(3) In certain situations, enforcing constraints may result in a solution that is not feasible at a
Shadow Price less than an appropriately priced VRL. In such cases, the Transmission
Provider must apply VRLs in SCED.
(4) To ensure rational pricing of cleared Operating Reserve products, the SCED algorithm
will include product substitution logic as follows:
MWG MPRR 123 Recommendation Report.docx 6/28/2013 Page 5 of 5
(a) Any Regulation-Up Offers remaining once the Regulation-Up Requirement is
satisfied will be used to meet Contingency Reserve requirements if Regulation-Up
Offer is more economic or is needed to meet the overall Operating Reserve
requirement;
(b) Any Spinning Reserve Offers remaining once the Spinning Reserve Requirement
is satisfied will be used to meet the Supplemental Reserve requirements if the
Spinning Reserve Offer is more economic or is needed to meet the overall
Operating Reserve requirement.
(5) The co-optimization logic will provide through the Shadow Price calculation, MCPs for
Operating Reserve that include lost opportunity costs incurred as a result of Operating
Reserve clearing.
(6) Additionally, the Transmission Provider will execute a look-ahead SCED prior to the
RTBM SCED process. The Transmision Provider will use the look-ahead SCED results
towill perform at least these two functions: (1) anticipate the need to adjust Dispatch
Instructions for the current Dispatch Interval to prepare to meet forecasted changes in the
load several Dispatch Intervals into the future and (2) determine commitment of Quick-
Start Resources within the Operating Hourwith start-up times greater than ten (10)
minutes that can be on-line within the Operating Hour. The look-ahead period is at least
two Dispatch Intervals, one of which is the next Dispatch Interval following the current
Dispatch Interval.
Proposed Criteria Language Revision N/A
MWG MPRR 124 Recommendation Report.docx 6/28/2013 Page 1 of 7
PRR Recommendation Report PRR No. Marketplace-PRR124 PRR
Title Resource Specific TSR Creation
Timeline Normal Expedited Urgent Action
Provide explanation if Expedited and/or Urgent Action is selected:
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 5.1.1, 5.1.1.1 Title: Transmission Service Verification, TSR Modification for Resource Specific Source Points Protocol Version: 13.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
Many transmission service reservations on OASIS have a non-Resource specific source inside the SPP Market footprint that is equivalent to an aggregate load Settlement Location. From Section 5.1.1 of the Marketplace Protocols, for a TSR with a source inside the SPP Market that is not a specific Resource or Resource Hub, the load Settlement Location that most closely corresponds to the source on the reservation will be utilized as the source for candidate ARRs. Two examples of TSRs that this may be utilized are master NITS reservations and system sales. This MPRR describes the process to “breakout” these types of TSRs into Resource specific TSRs. This proposal was voted on and approved during the 11/30/2012 MWG meeting. It was noted during that meeting for the MWG to revisit any related Protocol revisions.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE: Section 7.1.1 Transmission Service Verification
No
MWG Review PRR Recommendation
Date of Vote: 5/21/2013 – Approved Unanimously All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: N/A
RTWG Review 6/27/2013 – Approved
ORWG Review 6/19/2013 – Approved with no Reliability Impact
EIS Market
Integrated Marketplace
MWG MPRR 124 Recommendation Report.docx 6/28/2013 Page 2 of 7
MOPC Recommendation
Board Review
Date 5/3/2013
Sponsor Name Nick Parker E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3574
Proposed Protocol Language Revision 5.1 Annual ARR Verification Process
Only Eligible Entities are eligible to nominate candidate ARRs as described under Section 5.2. Eligible Entities are Transmission Customers with firm SPP transmission service and entities with firm non-SPP transmission service (commonly referred to as a “grandfathered agreement or GFA”) into, out of, within or through the SPP Region that has been confirmed prior to the Annual ARR Allocation Process. Eligible Entities must verify such services with SPP during the Annual ARR Verification Process in order to be eligible to nominate candidate ARRs. All Eligible Entities must be a Market Participant and/or Asset Owner. The following rules apply to verification of transmission service for conversion to ARRs.
5.1.1 Transmission Service Verification
In order for Eligible Entities to obtain candidate ARRs, SPP must first verify existing transmission service entitlements, including transmission service entitlements which have been renewed in accordance with rollover rights since their initial term[MCRR1.1]. In order to qualify for candidate ARRs in a particular month and/or season, an Eligible Entity’s transmission service must span the entire monthly or seasonal period within the applicable year. SPP will verify Eligible Entity existing transmission service entitlements as follows:
(1) For Eligible Entities taking Network Integration Transmission Service (NITS) and/or Firm Point-To-Point Transmission Service (FPTP) under the SPP Tariff:
(a) SPP will obtain source, sink and Reserved Capacity information from the SPP OASIS for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period;
(b) For a TSR with a source inside the SPP Market that is not a specific Resource or Resource Hub, the load Settlement Location that most closely corresponds to the source on the reservation will be utilized as the source for candidate ARRs. Eligible Entities
MWG MPRR 124 Recommendation Report.docx 6/28/2013 Page 3 of 7
may create Resource specific TSRs that represent their current TSRs using the process described under Section 5.1.1.1;
(c) For a TSR with a source outside of the SPP Market, the interface associated with the Balancing Authority of the source will be utilized as the source;
(d) For a TSR with a sink outside of the SPP Market, the interface associated with the Balancing Authority of the sink will be utilized as the sink;
(e) SPP will provide this information to each Eligible Entity for verification;
(f) Eligible Entities will notify SPP within two (2) weeks following receipt of this information identifying and correcting inaccurate data. Otherwise, the SPP provided data will be considered verified.
(2) For Eligible Entities taking GFA service:
(a) If the transmission customer under the GFA desires to nominate ARRs associated with the GFA sources and sinks identified in the Grandfathered Agreement, the GFA Parties must notify SPP thatregister such GFA with SPP exists and provide SPP with sources, sinks and Reserved Capacity information. SPP will obtain source, sink and Reservation Capacity information from the GFA registration for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period[MCRR2.2];
(b) For a GFA with a source inside the SPP Market that is not a specific Resource or Resource Hub, the load Settlement Location that most closely corresponds to the source on the reservation will be utilized as the source for candidate ARRs;
(c) For a GFA with a source outside of the SPP Market, the interface associated with the Balancing Authority of the source will be utilized as the source for candidate ARRs;
(d) For a GFA with a sink outside of the SPP Market, the interface associated with the Balancing Authority of the sink will be utilized as the sink;
(e) In addition, the parties to the GFA must agree that the transmission customer under the GFA is eligible to nominate the ARRs associated with the GFA and both parties must confirm such with SPP. To the extent that the transmission service specified in the GFA is identified as the equivalent of SPP NITS, the transmission customer under the GFA must provide the historical non-coincident annual [MCRR2.3]peak loads (“GFA Annual Peak Load”) being served under the GFA for the previous three years since February 1, 2007[MCRR2.4].
5.1.1.1 TSR Modification for Resource Specific Source Points
Eligible Entities may “breakout” their non-Resource specific transmission service that is inside the SPP Market footprint by placing individual Resource specific transmission service reservations on OASIS
MWG MPRR 124 Recommendation Report.docx 6/28/2013 Page 4 of 7
that will be used exclusively for the TCR Market. The original transmission service will remain on OASIS.
For the master NITS breakout, Appendix 1 of the Market Participant’s current NITSA will be used to validate the process. For the breakout of non-Resource specific transmission service other than the master NITS, all Market Participants involved in the transmission service transaction will be responsible for determining which Resources and Resource capacities should be used during the breakout, as SPP is not aware which Resources the transmission service was intended to represent. The sum of all transmission service from each Resource must be less than or equal to the Maximum Capacity of the Resource.
Eligible Entities must use the following process to initiate and complete the TSR modification.
(1) Submit the required Non-Resource Specific TSR Breakout Form, found on www.SPP.org, to SPP if more than one party is involved in the transmission service transaction; and
(2) Submit new transmission service requests with the new service code of “SPP FN-7 YEARLY NITS TCR”, “SPP F-7 YEARLY PTP TCR”, “SPP FN-7 MONTHLY NITS TCR”, or “SPP F-7 MONTHLY PTP TCR”, whichever is equivalent to the original transmission service type.
(a) The only difference between the original TSR and the new TSR should be the source, the capacity, and the subclass.
(i) For Master NITS TSRs, the capacity should be the highest value per Resource found in Appendix 1 of the NITSA (including the comments column) rounded up to the nearest whole MW value. If the Eligible Entity feels that they are entitled to a different amount other than what is listed in the NITSA, they should contact the SPP Transmission Service Studies group to see about amending their NITSA. If the capacity in the NITSA changes after the TSR has been granted, then this TSR may be recalled and a new TSR may be submitted to represent the new value in the NITSA.
(ii) For other Non-Resource Specific TSRs, the capacity should be the amount the parties have agreed to.
(b) Pre-confirm all submittals to allow for immediate confirmation after acceptance by SPP.
Proposed Tariff Language Revision Attachment AE
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7.1.1 Transmission Service Verification
In order for Eligible Entities to obtain candidate ARRs, the Transmission Provider must
first verify existing Transmission Service entitlements, including Transmission Service
entitlements that have been renewed in accordance with rollover rights since their initial term.
An Eligible Entity’s Transmission Service must span the entire monthly or seasonal period for
which ARRs are allocated to qualify for candidate ARRs in a particular month or season. The
Transmission Provider will verify Eligible Entity existing Transmission Service entitlements as
follows:
(1) The following will be performed prior to each annual ARR allocation for Eligible Entities
taking Network Integration Transmission Service or Firm Point-To-Point Transmission
Service under the Tariff:
(a) The Transmission Provider will obtain source, sink and Reservation Capacity
information from the OASIS for each monthly and seasonal period for which
ARRs are allocated in which the Transmission Service spans the entire period for
the current annual allocation;
(i) For a Transmission Service reservation with a source inside the SPP
Balancing Authority Area that is not a specific Resource or Resource
Market Hub, the Transmission Provider will determine the load Settlement
Location that most electrically corresponds to the source on the
Transmission Service reservation that will be utilized as the source for
candidate ARRs. Eligible Entities may create Resource specific
Transmission Service reservations that represent their current
Transmission Service reservations using the process described in the
Market Protocols.
(ii) For a Transmission Service reservation with a source outside of the SPP
Balancing Authority Area, the interface between the Transmission
Provider and the first tier Balancing Authority Area associated with the
transmission reservation will be utilized as the source for candidate ARRs.
(iii) For a Transmission Service reservation with a sink outside of the SPP
Balancing Authority Area, the interface between the Transmission
Provider and the first tier Balancing Authority Area associated with the
transmission reservation will be utilized as the sink for candidate ARRs.
MWG MPRR 124 Recommendation Report.docx 6/28/2013 Page 6 of 7
(b) The Transmission Provider will provide this information to each Eligible Entity
for verification; and
(c) Eligible Entities will notify the Transmission Provider within 2 weeks following
receipt of this information, identifying and correcting inaccurate data on the
OASIS. Otherwise, the Transmission Provider provided data will be considered
verified.
(2) The following will be performed prior to each annual ARR allocation for the Eligible
Entity taking GFA service:
(a) Each Transmission Owner shall register any GFA for which candidate ARRs are
to be provided to the Transmission Owner or the transmission customer under the
GFA on the Transmission Provider’s OASIS. The Transmission Owner must
provide the Transmission Provider with source, sink and Reservation Capacity
information for each GFA on the Transmission Provider’s OASIS by registering
each GFA with the Transmission Provider. The Transmission Provider will use
source, sink, and Reservation Capacity information from the GFA registration for
each monthly and seasonal period for which ARRs are allocated. If both parties
to the GFA are Market Participants with respect to the GFA load, then the parties
may jointly inform the Transmission Provider which Market Participant will be
allocated the candidate ARRs. If the parties to the GFA do not so inform the
Transmission Provider, or if only the Transmission Owner that sold the GFA
service is a Market Participant, then the Transmission Owner that sold the GFA
service will be allocated the candidate ARRs associated with the GFA.
(i) For a GFA with a source inside the SPP Balancing Authority Area that is
not a specific Resource or Resource Market Hub, the Transmission
Provider will determine the load Settlement Location that most electrically
corresponds to the source on the Transmission Service reservation that
will be utilized as the source for candidate ARRs.
(ii) For a GFA with a source outside of the SPP Balancing Authority Area, the
interface between the Transmission Provider and the first tier Balancing
Authority Area associated with the transmission reservation will be
utilized as the source for the candidate ARRs.
(iii) For a GFA with a sink outside of the SPP Balancing Authority Area, the
interface between the Transmission Provider and the first tier Balancing
MWG MPRR 124 Recommendation Report.docx 6/28/2013 Page 7 of 7
Authority Area associated with the transmission reservation will be
utilized as the sink for the candidate ARRs.
(b) If the transmission customer under the GFA is receiving the candidate ARRs, to
the extent that the transmission service specified in the GFA is identified as the
equivalent of SPP Network Integration Transmission Service, the transmission
customer under the GFA must provide the historical peak loads being served
under the GFA for the previous three years.
Proposed Criteria Language Revision N/A
MWG MPRR 125 Recommendation Report.docx 6/28/20137/19/2013 Page 1 of 7
PRR Recommendation Report PRR No. MarketPlace-PRR125 PRR
Title Qualifying Facility Registration as NDVER
Timeline
Normal Expedited Urgent Action Provide explanation if Expedited and/or Urgent Action is selected: This MPRR is Expedited so that it is clear that QF resources can register as NDVERs before Go-Live.
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 6.1.8 Title: Dispatchable Variable Energy Resources Protocol Version: 13.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
Referencing Docket No. ER12-2292-000; FERC stated, “Qualify Facility (QF) output sold under PURPA receives curtailment priority on an equivalent basis with firm network resources and also that such QFs will not incur Uninstructed Deviation Charges.” There are very few circumstances that QF resources will be curtailed in the Integrated Marketplace. QFs should be allowed to register as NDVER resources. This MPRR makes clear that all QF resources can be registered as NDVERs in the Integrated Marketplace.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE Section 2.2 (10) Application and Asset Registration
No
MWG Review PRR Recommendation
Date of Vote: 5/21/2013 – Approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: TNSK, NPPD - abstained
RTWG Review 6/27/2013 – Approved
ORWG Review 6/19/2013 – Approved
MOPC Recommendation
Board Review
EIS Market
Integrated Marketplace
MWG MPRR 125 Recommendation Report.docx 6/28/20137/19/2013 Page 2 of 7
Date 5/7/2013
Sponsor Name Amber L. Metzker E-mail Address [email protected] Company Xcel Energy Phone Number 303.571.6202
Comments Received Comment Author Micha Bailey on behalf of MWG Date 5/21/2013
Comment Description MWG changed Section 6.1.8 language and Attachment AE Section 2.2 to conform to FERC’s ruling on Qualifying Facilities.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report
Proposed Protocol Language Revision 6.1.8 Dispatchable Variable Energy Resource
All Variable Energy Resources must register as a Dispatchable Variable Energy Resource except for (i) Variable Energy Resources with an interconnection agreement executed on or [MCRR15.1]prior to May 21, 2011 and that commenced Commercial Operation before October 15, 2012[MPRR111.2] or (ii) a Qualifying Facility Rresource exercising theirits rights under PURPA rights to putdeliver all of its net output to aits host utility., VERS included in (i) above may register as Dispatchable Variable Energy Resources if they are capable of being incrementally dispatched by the Transmission Provider. A Qualifying Facility Resource exercising its rights under PURPA to deliver all of its net output to its host utility, may register as a Dispatchable Variable Energy Resource if it is capable of being incrementally dispatched by the Transmission Provider and will be subject to the DVER market rules including Uninstructed Resource Deviation Charges. which may register as Dispatchable Variable Energy Resources if they are capable of being incrementally dispatched by the Transmission Provider.[MCRR15.3] Non-wind (e.g. solar, run-of-the-river hydro, biomass) Variable Energy Resources shall not be required to register as a Dispatchable Variable Energy Resources unless they choose to register as such. Any Resource that has previously registered as a Dispatchable Variable Energy Resource shall not subsequently register as a Non-Dispatchable Variable Energy Resources.[MCRR15.4]
(1) A Dispatchable Variable Energy Resource is eligible to submit Offers for Regulation-Down if that Resource qualifies to provide Regulation-Down by passing the test described under Section 6.1.11.3.
(2) A Dispatchable Variable Energy Resource is not eligible to submit Offers for Regulation-Up, Spinning Reserve or Supplemental Reserve;
MWG MPRR 125 Recommendation Report.docx 6/28/20137/19/2013 Page 3 of 7
(3) Dispatchable Variable Energy Resources are committed and dispatched the same as any other Resource in the Day-Ahead Market.
(4) For the RUC and RTBM, special commitment and dispatch rules apply as defined under Section 4.2.2.5.5.
(3)(5) Dispatchable Variable Energy Resource data submittal requirements are defined in the SPP Criteria.[MPRR74.5]
6.1.9 Non-Dispatchable Variable Energy Resource
Variable Energy Resources that qualify may register as a Non-Dispatchable Variable Energy Resource. The Market Participant registering a Non-Dispatchable Variable Energy Resource must provide documentation to SPP verifying that it meets one or more of the exceptions in Section 6.1.8. Otherwise, the Resource must be registered as a Dispatchable Variable Energy Resource. NDVERs are committed and dispatched the same as any other Resource in the Day-Ahead Market. For the RUC and RTBM, special commitment and dispatch rules apply as defined under Section 4.2.2.5.6. Non-Dispatchable Variable Energy Resource data submittal requirements are defined in the SPP Criteria.
Proposed Tariff Language Revision
Attachment AE
2.2 Application and Asset Registration
(1) Applications for a Market Participant to provide services in the Integrated Marketplace
must be submitted to the Transmission Provider prior to the expected date of participation
consistent with Section 6.4 of the Market Protocols. Applications must conform to the
procedures specified in the Market Protocols and may be rejected if not complete. New
Market Participants will follow the timeframe as specified in Section 6.4 of the Market
Protocols in addition to the detailed model update timing requirements in Appendix E of
the Market Protocols.
(2) As part of the application process, Market Participants must register all Resources and
load, including applicable load associated with Grandfathered Agreements (“GFAs”),
Non-Conforming Load and Demand Response Load with the Transmission Provider in
accordance with the registration process specified in the Market Protocols. As part of
Resource registration, Market Participants must specify whether settlement meter data
will be submitted on a gross basis or net basis, where gross meter data does not include
MWG MPRR 125 Recommendation Report.docx 6/28/20137/19/2013 Page 4 of 7
reductions for auxiliary load and net meter data is gross meter data reduced by auxiliary
load. Both Non-Conforming Load and Demand Response Load may only be associated
with a single Price Node. Non-participating embedded load and/or generation must
either: (i) register its load and/or generation in the Integrated Marketplace; or (ii)
transfer its load and/or generation to an external Balancing Authority.
(3) Market Participants may elect to define a single Settlement Location that aggregates
multiple Meter Data Submittal Locations associated with their load assets. Market
Participants may not aggregate multiple Resource Meter Data Submittal Locations into a
single Resource Settlement Location. A single Resource must be registered and settled at
a single Resource Settlement Location unless the Resources are at the same physical and
electrically equivalent injection point to the Transmission System.
(4) In addition to the responsibilities described in Section 4.1.2 of this Attachment AE and
under the Market Protocols, Market Participants wishing to model each participant’s
share of a Jointly Owned Unit as a separate Resource must choose one of the two options
described below and provide the specified additional information. A Resource registered
as a combined cycle Resource may not register as a Jointly Owned Unit.
(a) Individual Resource Option
Under the individual Resource option, each participant’s share is modeled
as a separate Resource for the purposes of commitment and dispatch and each
Resource may be committed independent of the other Resource shares. In order
to qualify for this option, each Market Participant must register its share and
certify that it is greater than or equal to the minimum physical capacity operating
limit of the physical Jointly Owned Unit.
The operating owner’s Meter Agent will be the Meter Agent for that
Jointly Owned Unit unless each individual Jointly Owned Unit participant
registers a Meter Agent for its share of the Resource.
Unless otherwise agreed to by the Jointly Owned Unit participants, the
operating owner will be responsible for submitting the following data:
• Jointly Owned Unit maximum physical capacity operating limit;
• Jointly Owned Unit minimum physical capacity operating limit; and
• Maximum physical ten (10) minute response from an off-line state. (b) Combined Resource Option
MWG MPRR 125 Recommendation Report.docx 6/28/20137/19/2013 Page 5 of 7
Under the combined Resource option each participant’s share is modeled
and must be registered as a separate Resource. Under this option, the
commitment decision is made assuming that all Resource shares must be
committed or none at all. Once committed, each share is dispatched
independently. This option must be selected if the eligibility criteria stated under
the individual Resource option cannot be met.
The operating owner’s Meter Agent will be the Meter Agent for that
Jointly Owned Unit unless each individual Jointly Owned Unit participant
registers a Meter Agent for its share of the Resource.
Unless otherwise agreed to by the Jointly Owned Unit participants, the
operating owner will be responsible for submitting the following data:
• Jointly Owned Unit maximum physical capacity operating limit;
• Jointly Owned Unit minimum physical capacity operating limit;
• Maximum physical ten (10) minute response from an off-line state;
and
• Participant share percentage by Market Participant.
(5) Market Participants may modify their registered assets in accordance with the asset
registration procedures specified in the Market Protocols.
(6) All loads and all Resources, excluding Behind-The-Meter Generation less than 10
Megawatts (“MWs”), must register. Failure or refusal to register a Resource will result in
the Transmission Provider filing an unexecuted version of the service agreement as
specified in Attachment AH of this Tariff for that Resource with the Commission under
the name of the generation interconnection customer under an interconnection agreement
with the Transmission Provider or the applicable Transmission Owner. In the case of a
Qualifying Facility exercising its rights under PURPA to deliver all of its net output to its
host utility, such registration will not require the Qualifying Facility to participate in the
Energy and Operating Reserve Markets or subject the Qualifying Facility to any charges
or payments related to the Energy and Operating Reserve Markets.
(7) A Market Participant wishing to Offer an External Resource in the Energy and Operating
Reserve Markets will utilize an External Resource Pseudo-Tie in accordance with
Attachment AO. In addition to the responsibilities outlined in Attachment AO, the
Market Participant registering the External Resource will be responsible for registering
MWG MPRR 125 Recommendation Report.docx 6/28/20137/19/2013 Page 6 of 7
and performing all responsibilities that are required of Resources in the Energy and
Operating Reserve Markets.
(8) A Market Participant wishing to offer Demand Response Load as a Demand Response
Resource in the Energy and Operating Reserve Markets must include in its application
and registration a certification that participation in the Energy and Operating Reserve
Markets by its Demand Response Resource is not precluded under the laws or regulations
of the relevant electric retail regulatory authority. Consistent with Section 2.8 of this
Attachment, an aggregator of retail customers wishing to offer Demand Response Load
in the form of a Demand Response Resource on behalf of one or more retail customers
must also include in its application and registration a certification that participation of
each retail customer is either: (1) not precluded by the laws or regulations of the relevant
electric retail regulatory authority if the customer is served by a utility that distributed
more than 4 million MWh in the previous fiscal year; or (2) affirmatively permitted by the
laws or regulations of the relevant electric retail regulatory authority if the customer is
served by a utility that distributed 4 million MWh or less in the previous fiscal year.
Demand Response Resources must meet all application, registration and technical
requirements applicable to the Energy and Operating Reserve Markets. The
Transmission Provider is not responsible for interpreting the laws or regulations of a
relevant electric retail regulatory authority and shall be required only to verify that the
Market Participant has included such a certification in its application materials. The
Transmission Provider is not liable or responsible for Market Participants participating in
the Energy and Operating Reserve Markets in violation of any law or regulation of a
relevant electric retail regulatory authority including state-approved retail tariff(s).
(9) An aggregator of retail customers offering Demand Response Load of one or more end-
use retail customers as a Demand Response Resource in the Energy and Operating
Reserve Markets must be a Market Participant, satisfying all registration and certification
requirements applicable to Market Participants as well as certification consistent with
Section 2.8 of this Attachment.
(10) A wind-powered Variable Energy Resource with (1) an interconnection agreement
executed after May 21, 2011 or (2) an interconnection agreement executed on or prior to
May 21, 2011 and that commenced Commercial Operation on or after October 15, 2012,
must register as a Dispatchable Variable Energy Resource. A wind-powered Variable
Energy Resource with an interconnection agreement executed on or prior to May 21,
MWG MPRR 125 Recommendation Report.docx 6/28/20137/19/2013 Page 7 of 7
2011 may register as a Dispatchable Variable Energy Resource if it is capable of being
incrementally dispatched by the Transmission Provider. Variable Energy Resources with
fuel sources other than wind may optionally register as a Dispatchable Variable Energy
Resource. Otherwise, Variable Energy Resources must register as Non-Dispatchable
Variable Energy Resources. A Qualifying Facility Resource exercising its rights under
PURPA to deliver all of its net output to its host utility A Qualifying Facility exercising
their PURPA rights may register as a Non-Dispatchable Variable Energy Resource or a
Dispatchable Variable Energy Resource as described in the Market Protocols. Any
Resource that has previously registered as a Dispatchable Variable Energy Resource
shall not subsequently register as a Non-Dispatchable Variable Energy Resource.
(11) A Market Participant that is selling firm power to the load asset under a bilateral
contract may, with the agreement of the buyer, register all or a portion of the buyer’s
load as its load asset. For purposes of this Section 2.2(11) of this Attachment AE, the
sale of firm power shall refer to power sales deliverable with firm transmission service,
where the capacity and energy is supplied under standards of reliability and availability
equivalent to supply of native load customers with the supplier assuming the obligation to
provide both capacity and energy.
Proposed Criteria Language Revision N/A
MWG MPRR 128 Recommendation Report.docx 7/5/2013 Page 1 of 3
PRR Recommendation Report PRR No. Marketplace-PRR128 PRR
Title Day-Ahead Virtual Energy Transaction Fee Rate
Timeline Normal Expedited Urgent Action
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 4.5.8.20 Title: Day-Ahead Virtual Energy Transaction Fee Amount Protocol Version: 15.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
Each Virtual Energy Offer and Virtual Energy Bid will be subject to a Day-Ahead Virtual Energy Transaction Fee Amount. The calculation of this amount is in Section 8.5.17 of Attachment AE of the Tariff. The Protocol language in Section 4.5.8.20 points to this section.
Section 8.5.17 of AE has been modified to define the Virtual Transaction Fee Rate. It has also been changed to say that the submitted offer is as of the close of the Day-Ahead Market. Section 4.5.8.20 of the Protocols has been modified to reflect the hourly nature of the offers/bids, which is already covered in the Tariff. “As of the close of the Day-Ahead Market” was added to the Protocols as well.
Tariff Implications or Changes
Yes – Section No: (Include a summary of impact and/or specific changes) Attachment AE Section 8.5.17 Day-Ahead Virtual Energy Transaction Fee Amount
No
MWG Review PRR Recommendation
Date of Vote: 5/22/2013 – Approved 6/28/2013 – Unanimously Approved with modifications All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: WR, CUS - abstained
RTWG Review 6/27/2013—Approved with modifications
ORWG Review 6/19/2013 – Approved with no Reliability Impact
MOPC Recommendation
Board Review
EIS Market
Integrated Marketplace
MWG MPRR 128 Recommendation Report.docx 7/5/2013 Page 2 of 3
Date 5/14/2013
Sponsor Name Micha Bailey E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.2522
Comments Received Comment Author Debbie James on behalf of the MWG Date 5/22/2013 Comment Description Changed the rate of the Virtual Transaction Fee from $0.005 to $0.05.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Comments Received
Comment Author Brenda Fricano on behalf of the RTWG Date 6/27/2013
Comment Description Section 8.5.17 of AE has been modified to define the Virtual Transaction Fee Rate. It has also been changed to say that the submitted offer is as of the close of the Day-Ahead Market.
Comment Status MWG approved the MPRR as modified by RTWG. The MWG also added the changes below to section 4.5.8.20 of the Protocols in order to parallel the Tariff language. The approved language is reflected in this recommendation report.
Proposed Protocol Language Revision
4.5.8.20 Day-Ahead Virtual Energy Transaction Fee Amount
(1) A DA Market credit1 or charge for each hour of the Operating Day in which a submitted Virtual Energy Offer and Virtual Energy Bid is submitted as of the close of the Day-Ahead Market will be calculated for each Asset Owner for each Operating Day. Charges collected by SPP under this charge type are used by SPP to reduce the SPP budgeted expenses used to calculate the rate specified under Schedule 1-A of the SPP Tariff. The amount is calculated as follows:
#DaVTxnFeeAoAmt a, m, d = DaVTxnDlyCnt a, d * DaVTxnFeeDlyRate d
(2) For each Market Participant, a daily amount is calculated representing the sum of Asset Owner amounts associated with that Market Participant. The net daily charge or credit is calculated as follows:
DaVTxnFeeMpAmt m, d = ∑a
DaVTxnFeeAoAmt a, m, d
1 Note that this charge type will almost always produce a charge. The credit is included here for the rare occasion when a credit may be produced as a result of a data error and/or a resettlement.
MWG MPRR 128 Recommendation Report.docx 7/5/2013 Page 3 of 3
Proposed Tariff Language Revision ATTACHMENT AE
8.5.17 Day-Ahead Virtual Energy Transaction Fee Amount
A Day-Ahead Market charge for each submitted Virtual Energy Offer and Virtual Energy
Bid will be calculated for each Asset Owner for each Operating Day. Charges collected by the
Transmission Provider under this charge type are used by the Transmission Provider to reduce
the Transmission Provider budgeted expenses used to calculate the rate specified under Schedule
1-A of the Tariff and are calculated as follows:
Day-Ahead Virtual Energy Transaction Fee Amount =
[(Day-Ahead Virtual Energy Transaction Daily Count) * (Day-Ahead Virtual Energy
Transaction Fee Rate)]
(1) Day-Ahead Virtual Energy Transaction Daily Count is equal to the sum of submitted
Virtual Energy Bids and Virtual Energy Offers submitted as of the close of the Day-
Ahead Market for all Settlement Locations and hours in the Operating Day.
(2) Day-Ahead Virtual Energy Transaction Fee Rate is $0.05 for each Virtual Energy Offer
or Virtual Energy Bid the rate defined under Schedule 1 of the Tariff.
Proposed Criteria Language Revision N/A
Southwest Power Pool, Inc. SOUTHWEST POWER POOL STAFF
Markets and Operations Policy Committee Recommendation to the Board of Directors
On Attachment J Aggregate Study Waiver Requests July 29-30, 2013
Organizational Roster The following members represent the Southwest Power Pool:
Carl Monroe, Executive Vice President and Chief Operating Officer Paul Suskie, Senior Vice President, Regulatory Policy and General Counsel Lanny Nickell, Vice President, Engineering Pat Bourne, Director, Transmission Policy Katherine Prewitt, Director, Planning Nicole Wagner, Manager, Regulatory Policy Steve Purdy, Manager, Transmission Service Studies
Attachment J of the SPP Tariff Addresses recovery of costs associated with new transmission facilities. Subsection III of this section addresses Base Plan funding for network upgrades, including Safe Harbor Cost Limit of $180,000/MW, and provides for waivers, whereby application may be made for additional Base Plan funding for a network upgrade in excess of the Safe Harbor Limit based on three independent factors.
KMEA Waiver Request
Background On April 19, 2013, SPP received a request from Kansas Municipal Energy Agency (KMEA) for waiver under Attachment J of the SPP Tariff of costs in excess of the Safe Harbor Cost Limit for Base Plan funding for a new Designated Resource of 15 MW. KMEA is seeking a waiver for this cost above the Safe Harbor Limit so that all of the allocated expenses associated with the request are eligible for Base Plan funding. SPP’s 120-day deadline under Attachment J is August 17, 2013.
Analysis KMEA requested a waiver based on Section III.C.2.ii of Attachment J, which provides for consideration to be given for terms that exceed the minimum five years required for Base Plan funding. The term of the requested service is 10 years.
A project (Hawthorne-Birmingham-Liberty South 161 kV) which consists of three individual upgrades was allocated to KMEA’s request based on the 3% TDF threshold required for cost allocation. KMEA’s request is only responsible for a fraction (less than 10%) of the flow increase on the facilities, but because KMEA’s request is the only one with more than a 3% TDF, KMEA is bearing 100% of the cost. The SPP Board previously approved waivers for other customers in similar situations, given that they were bearing the entire cost, but were only responsible for a small fraction of the impact.
The Cost Allocation Working Group (CAWG) reviewed the waiver request at its regular meeting on June 12, 2013. The CAWG chose to take no action and registered no opposition to SPP Staff’s recommendation.
Given that the study is at an early stage, final cost allocation can be expected to change as the study undergoes further refinements.
Recommendation
MOPC recommends that the BOD approve the cost of this project not be allocated to KMEA’s request.
APPROVED: MOPC July 16-17, 2013
Approved unanimously
Southwest Power Pool, Inc.
MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors
July 29-30, 2013
Re-evaluation of Hays Plant – South Hays 115 kV Rebuild
Organizational Roster The following persons represent the Southwest Power Pool:
Carl Monroe, Executive Vice President and Chief Operating Officer Lanny Nickell, Vice President, Engineering Katherine Prewitt, Director, Planning Jody Holland, Manager, Steady State Planning Antoine Lucas, Manager, Economic Planning
Background On February 20, 2013, SPP issued Notification to Construct (NTC) No. 200210 to Midwest Energy, Inc. (MIDW) for a project to rebuild a 3.25-mile 115 kV line from Hays Plant to South Hays. The project was identified as a reliability need in the 2013 ITP Near-Term Assessment (ITPNT).
On May 16, 2013, MIDW submitted to SPP a commitment to construct the Network Upgrades included in NTC No. 200210 and an NTC Project Estimate (NPE) of $8,832,219 for the Hays Plant - South Hays 115 kV Rebuild project. This cost estimate represented an 82.0% increase from the Study Estimate1 indicated on the ITPNT.
Analysis
Further evaluation of the Hays Plant substation by MIDW revealed the need for further substation upgrades to meet the 199 MVA line specification listed on NTC No. 200210. The needed substation upgrades could not be accommodated with an expansion or rebuild at the existing Hays Plant site. As such, the NPE includes the construction of a six-position ring bus at a location adjacent to Hays Plant. This was noted by MIDW as the main driver in the increase in cost estimates. Preliminary analysis by SPP Staff indicates that a lower MVA rating than the one specified in the NTC could potentially satisfy the reliability need identified in the ITPNT.
Recommendation MOPC recommends the BOD approve the reliability need for project Hays Plant - South Hays 115 kV Rebuild be re-evaluated expeditiously, and issue a modified NTC for the project, if necessary.
APPROVED: MOPC July 16-17, 2013
Approved unanimously
1 Adjusted for inflation
Page 1 of 3
Southwest Power Pool, Inc.
FINANCE COMMITTEE
Recommendation to the Board of Directors
July 11, 2013
External Audit Engagements
Organizational Roster The following persons are members of the Finance Committee:
Harry Skilton SPP Director Larry Altenbaumer SPP Director Sandra Bennett Kelly Harrison Coleen Wells Michael Wise
American Electric Power Westar Energy, Inc. Kansas Electric Power Cooperative, Inc. Golden Spread Electric Cooperative, Inc.
Background SPP annually engages Certified Public Accounting (CPA) firms to perform audits of it’s: 1) financial statements; 2) employee benefit plans (401(k) Savings Plan, Retirement Plan and Medical Plan); and 3) control activities (Statement on Standards for Attestation Engagements [SSAE] No. 16) placed in operation and tests of operating effectiveness pertaining to the settlements processes and supporting IT systems.
In March 2013, recognizing that “bundling” external audits with one firm might produce cost savings, SPP distributed a request for proposal (RFP) for all of the regularly scheduled external audit engagements referenced above. Responding parties were allowed to bid on the proposals individually, in any combination, or in entirety.
The RFP was distributed by SPP’s Manager of Purchasing to 10 CPA firms. Listed below are the firms and proposals submitted:
Firm Financial Statement Audit
Employee Benefit Audits Controls Audit
BKD, LLC X X X Brightline X Deloitte X X X Ernst & Young Did not respond Did not respond Did not respond Frost, PLLC X X IS Partners X JPMS Cox (with McGladrey Alliance) X X X KPMG X PwC X Thomas and Thomas X X
The responses were reviewed and evaluated by SPP’s Controller, Director of Internal Audit and Manager of Purchasing according to the deliverables (see below for specifics) set forth in the
Page 2 of 3
RFP. Results were also provided to the Vice President of Finance/CFO and the Vice President of Process Integrity.
Deliverables:
1. Value added to the engagement through the expertise of the individuals assigned to the reviews
2. Reasonableness of the cost of the Respondent’s proposal relative to the services provided
3. Capabilities consistent with specified requirements and expectations for the RFP 4. Ability to provide the applicable report in a timely manner 5. Demonstrated ability and willingness to work with SPP to achieve their objectives, within
their constraints, and in a creative and flexible fashion 6. Completeness of the Respondent’s proposal in addressing all aspects of the RFP
Each deliverable was assigned a weighting and each company was then ranked by each deliverable (the ranking and evaluation spreadsheets are available for review).
After completing the evaluation, it was determined that “bundling” the audits would not produce meaningful cost savings for SPP. As detailed above, only three of the responding firms presented proposals to bundle the audits. Of those, only one firm was deemed to be “acceptable” to perform all of the audits and the proposed pricing would be greater than the un-bundled alternatives.
Below is a summary of the individual analyses and recommendations for the external audit engagements.
Financial Statement Audit
Analysis
See attached summary.
Recommendation #1
Based on the preceding explanation, staff proposes that BKD be retained as SPP’s financial auditors.
Employee Benefit Plan Audits
Analysis
See attached summary.
Recommendation #2
Given their proven track record for meeting our reporting deliverables and their high level of staffing continuity maintained over the years, it is staff’s recommendation to retain Thomas & Thomas as our auditors of the respective employee benefit plans.
Page 3 of 3
Controls Audit (SSAE 16)
Transition from SPP Energy Imbalance Service (EIS) Market to Integrated Marketplace
Analysis
With the transition from the EIS Market to the Integrated Marketplace in March 2014, a gap period (November 1, 2013 to February 28, 2014) will occur that SPP must address for the benefit of the SPP’s market participants. Due to the nature and number of changes in SPP’s market, the control objectives and activities pertaining to the EIS and Transmission Settlement Markets for the gap period will require special arrangements. SPP considered the following options to address this gap period:
1. Include the period in the normal audit cycle, recognizing that this option will complicate the report for the reader and will result in higher audit fees
2. Hire an external firm to perform “Agreed Upon Procedures” for the EIS and Transmission Settlement Market controls for the period
3. Utilize SPP’s Internal Audit department to perform a review of the EIS and Transmission Settlement Market controls for the period
4. “Orphan” the period (no external/internal review of controls for the four month period)
Recommendation #3
After soliciting the advice/guidance regarding these options from our SEC jurisdictional members regarding the gap period, Staff proposes that SPP’s Internal Audit department be utilized to perform a review of the EIS and Transmission Settlement Market controls for the period November 1, 2013 to February 28, 2014. This will be a cost savings measure. SPP Internal Audit will summarize findings in a report addressed to the SPP Finance Committee. The report will be made available to market participants upon request.
Integrated Marketplace
Analysis
See attached summary.
Recommendation #4
Based on the preceding explanation, and SPP’s desire that the audit be a “value add” to SPP and SPP’s members and not just a report, staff proposes KPMG be engaged as SPP’s SSAE 16 auditors for the period 2014 to 2016. See attached summary for the proposed annual fees associated with the SSAE 16 Type 2 audit for subsequent years.
Approved: Finance Committee July 11, 2013 Action Requested: Approve Recommendations
2
FERC Order on SPP Order 1000 Compliance
• Order Timelines
• Order Findings
• SPCTF Recommendations
• Next Steps
3
Order Timelines
• FERC issued Order on July 18
• Compliance Filing due November 15, 2013
• Tariff to be effective March 30, 2014
• SPP Pre-Qualification Process to begin April 2014
• NTCs approved by the Board in January 2015 required to submit to competitive solicitation selection process
4
3
Order Findings
• Rejected SPP’s Mobile-Sierra arguments
• Denied SPP’s request to retain a right of first refusal for “Byway” projects
• Directed SPP to broaden the definition of “Competitive Upgrades”, to include
– Byway projects
– Projects receiving Highway/Byway funding identified in the SPP Ag Study process
5
Order Findings (continued)
• Required SPP to remove language addressing
– State right of first refusal laws
– Exemptions for projects constructed along existing rights-of-way
• Conditionally accepted proposal to exempt certain reliability projects that are needed within a short timeframe, subject to adopting 5 additional requirements
6
4
Order Findings (continued)
• Found SPP partially compliant
– Transmission owner qualification requirements
– RFP proposal evaluation and selection processes
• Found SPP partially compliant with the Order No. 1000 cost allocation principles, subject to a further compliance filing addressing impacts on neighboring transmission systems
7
Order Findings (continued)
• Directed SPP to modify the Tariff to provide further clarity regarding SPP’s process for considering transmission needs driven by public policy requirements
• Found SPP compliant with the regional planning aspects of Order No. 1000
8
5
SPCTF Recommendations
• Seek rehearing and clarification (Due August 18)
• Issues to rehear
– Mobile-Sierra
– Byway funding
– Removal of exemption on existing rights-of-way
– Inclusion of Ag Study projects
– State ROFRs
• Issue for clarification
– Approved Ag Study NTCs prior to January 2015
9
Next Steps
• SPCTF scheduling meetings for dual track process
– Develop policy guidance for compliance filing
– Begin dialogue with RSC, CAWG on cost allocation and state ROFRs
• Understand Implications for the ITP10 already in progress that will yield NTC’s in January 2015
10
1
Integrated Marketplace System Update
Board of Directors Meeting
July 2013
Bruce Rew, PE
Integrated Marketplace Update
• Market Trials: the first 7 weeks…
• Parallel Operations preparation: what is needed between now and November 1?
• Final steps to Go-Live
• Looking ahead at post Go-Live
2
2
• Base scenarios tested
– Day Ahead, DA Reliability Unit Commitment, Real-Time Balancing Market, Real-Time Generation dispatch (RTGEN)
• Results:
– All scenarios operated with no significant issues
– 38/50 Market Participants engaged
• Analysis:
– Some data quality issues, RTBM missed 2 intervals
– External transactions not reflected corrected
– RTGEN data quality is impacted by SPP 1st tier BA tielines 3
Market Trials: Week 1 (June 3-7)
• Base scenarios plus failure modes
– Day Ahead, DA RUC, RTBM, RTGEN, Failure modes
• Results:
– All scenarios operated with no significant issues
– Failure modes successful and improvement identified
• Analysis:
– Some data quality issues still exist, MP obligations weren’t posted by 7 am, EIS tool inadvertently committed a resource not online in the EIS Market
– Generation values off in the IM system because of new unit and SCADA modeling/mapping issues
4
Market Trials: Week 2 (June 10-14)
3
• Base scenarios plus two others
– Base plus Operating Reserve and Commitment mismatch
• Results:
– Commitment mismatch failed with CROW outage
– Other scenarios passed but Operating Reserve MP participation light
• Analysis:
– Software problem in Commitment mismatch identified
– Communication issue between RTGEN and RTBM and preventive measures implemented
– Market User Interface (MUI) concerns 5
Market Trials: Week 3 (June 17-21)
• Base scenarios plus OOME and Reserve Cap
– Base plus Out of Merit Energy Dispatch and Reserve Cap
• Results:
– Delayed DA market due to test data issue
– OOME incomplete as MP’s did not have ICCP connection
– Reserve Cap tested with couple of minor defects
• Analysis:
– Several corrections identified during the week
– RTBM had some time out issues, LMP price split due to generation dispatch around constraints
6
Market Trials: Week 4 (June 24-28)
4
• Base scenarios scheduled, ran two Operating Days
• Results:
– MP intentionally submitted high demand bid that caused invalid solution, software to correct situation being tested and will be installed
• Analysis:
– MP participation continues to be light with 27/50
– LMP price reached $1812.01 due to high demand bid causing the system to be Operating Reserve and Regulation Up short.
– Continue to work on improving modeling
7
Market Trials: Week 5 (June 29-July 5)
• Base and Demand Response scenarios tested
• Results:
– Demand Response passed with issues
• Analysis:
– Some ICCP and XML issues were identified but overall it was considered successful
– High # virtual bids submitted caused higher clearing of MW than normal because of limited constraints
– RTGEN receiving schedules from RTOSS
8
Market Trials: Week 6 (July 6-12)
5
• Base with Spring and Fall load profile scenarios tested
• Results:
– Spring rescheduled due to invalid execution. Solution appeared solved when it wasn’t. Units not properly dispatched.
– Fall scenario passed
• Analysis:
– Spring scenario rescheduled and software enhancement identified. Additional Operator training identified
9
Market Trials: Week 7 (July 13-19)
Issues Discovered/Addressed during Market Trials
• Increased understanding of bids and offer parameters by MPs
• Day Ahead processes for validating cases
• Improving functionality and performance for Markets user interface and API
• System performance and stability improvements
• Improving telemetry and resultant calculation of balancing authority functions
10
6
11
Updated Functional Roadmap for MT
Months May June July August Sept October November
Load Forecasts, Scheduling, Outage
Settlements–Bid to BIll, Emerg. Logic, TLR Events
Integration with Wind Resource Forecasting
Integration with Credit, Op Displays
Mitigation
MP Bids/Offers, DA, RUC, RTBM, Notifications, Integration with EMS
6/3
8/5
11/3 Ready for Parallel Ops
Overall SPP FIT
Markets FIT for SMT
Overall SPP SAT
Markets SAT for SMT
Includes internal SPP systems as well
Parallel Operations Preparation
• Complete Market Trials testing with Settlements bid-to-bill beginning in August (Risk Area)
• Market System testing on remaining software and patching on-going (Risk Area)
• TCR trials
– Software fix in place and trials restarted
– Complete trials and prepare for October start
• Market Participant connectivity and testing completed
– Target Mass met but concerned on MP engagement
12
7
Final Steps to Go-Live
• Successful Parallel Operations
– Market Systems completed and running daily
– Successful deployment testing: SPP engine will control generation and dispatch during scheduled periods of Parallel Operations
– SPP and MP Staffs prepared and fully trained
• TCR Auction successful
• Paperwork completed: filings made with FERC on our readiness
13
Post Go-Live Look Ahead
• Summary of Major Projects
– Regulation Compensation (FERC Order 755)
– Market to Market
– Enhanced Combined Cycle
– GFA Carve-outs
• Some of the design work begins before Go-Live to meet the required and target schedules
14
8
Southwest Power Pool, Inc.
FINANCE COMMITTEE Report to the Board of Directors
July 30, 2013
Tariff Schedule 1-A Administrative Fee Cap
Organizational Roster The following persons are members of the Finance Committee:
Harry Skilton Larry Altenbaumer Coleen Wells Mike Wise Sandra Bennett Kelly Harrison
Director Director Kansas Electric Power Coop Golden Spread Electric Coop Southwestern Electric Power Company Westar Energy
Background Schedule 1-A of the SPP regional tariff provides the mechanism for SPP to recover its costs from its transmission customers by applying a rate (“admin fee”) against the load served under the tariff. The admin fee is set annually by the SPP Board of Directors based on a recommendation from the SPP Finance Committee. The SPP Finance Committee establishes its recommendation based on its review of numerous inputs, primarily SPP’s year to date financial reports, SPP’s current fiscal year financial forecast, and SPP’s next year’s budget. The admin fee is allowed to recover up to 100% of SPP’s cash operating and debt service costs, adjusting for any over or under collections in the prior fiscal year. SPP’s Board of Directors may currently set the admin fee at any level up to and including 35¢/MWh. SPP charges the admin fee to all transmission service sold under the tariff, either based upon the prior year’s average monthly coincident peak for network transmission service, or based on the current reserved capacity for point to point transmission service.
SPP has forecast its future costs eligible for recovery via the admin fee. This forecast indicates SPP’s eligible costs will exceed the current rate cap of 35¢/MWh in fiscal year 2014 and beyond.
Analysis SPP’s transmission tariff was implemented in 1998. The tariff initially allowed SPP to recover up to 80% of its costs through application of the tariff rate against the reserved capacity sold under point to point service or the prior year’s 12 month average coincident peak demand for network service sold. SPP amended the tariff to allow for recovery of up to 100% of its costs through the tariff rate in 2004. The schedule 1-A administrative fee cap was set at 15¢/MWh when the tariff was implemented. This cap was raised to 20¢/MWh in April 2000, to 22.5¢/MWh in 2007, and to 35¢/MWh in 2011.
SPP has implemented several customer services over the past several years which have served to escalate SPP’s costs. These services have also resulted in significant and meaningful benefits to the SPP region.
Service Benefit Energy Imbalance Market $100,000,000 net annual production cost savings
Est. Compliance Department High touch assistance and training to members on compliance and changing regulatory requirements
Incr. Transmission Planning & Regulatory Creation and implementation of several cost
allocation plans to spur transmission development, improvement in transmission interconnection and reliability study processes
Focus on processes and controls Reduce opportunities for production errors,
assist members with Sarbanes Oxley certifications
SPP is scheduled to implement its Integrated Marketplace and Consolidated Balancing Area functionality on March 1, 2014. These services are expected to bring another $100,000,000 in net annual production costs savings to the SPP region while also providing the tools necessary to ensure the reliable operation of the transmission grid in an environment consisting of higher levels of intermittent resources and increased complexity. These projects will cost $115MM which SPP will fund via retirement of debt from 2014 through 2024. The chart below illustrates SPP’s historical admin fee, admin fee cap, and forecast costs/MWh.
SPP’s forecast indicates its costs/MWh will level off and slightly decline in the foreseeable future, assuming no new services are added to SPP’s products. The forecast admin fee utilizes data from SPP’s 2013 budget through 2015; thereafter costs (except debt retirement) escalate at 1%-2%. SPP’s load forecast assumes 3% load growth through 2015 then 2%/year thereafter with no new load joining SPP. The table below illustrates several load assumption sensitivities:
$0.000
$0.100
$0.200
$0.300
$0.400
$0.500
2004 2007 2010 2013 2016 2019 2022
$/M
Wh
Admin Fee Forecast Costs/MWh Admin Fee Cap Forecast Admin Fee Cap
Admin Fee Base 0.315$ 0.370$ 0.375$ 0.380$ 0.377$ 0.381$ 0.376$ 0.372$ 0.366$ 0.363$ Admin Fee 0% Load Growth 0.315$ 0.381$ 0.398$ 0.412$ 0.416$ 0.429$ 0.432$ 0.435$ 0.438$ 0.443$ Admin Fee 1% Load Growth 0.315$ 0.377$ 0.390$ 0.400$ 0.400$ 0.408$ 0.407$ 0.406$ 0.404$ 0.405$ Admin Fee -1% Load Growth 0.315$ 0.385$ 0.406$ 0.424$ 0.433$ 0.451$ 0.459$ 0.467$ 0.474$ 0.484$ Admin Fee New Member 0.315$ 0.370$ 0.375$ 0.353$ 0.350$ 0.353$ 0.349$ 0.345$ 0.340$ 0.337$ Admin Fee Debt ↑ $10MM 0.315$ 0.370$ 0.375$ 0.408$ 0.403$ 0.405$ 0.375$ 0.370$ 0.365$ 0.362$
Based on the sensitivity analysis, SPP would need to revisit the admin fee cap for 2015 under a negative load growth scenario, and would need to revisit the cap for 2016 under a low load growth scenario. A new member in 2016 may result in a meaningful reduction in admin fee levels beginning in 2016. The costs to operate an RTO vary based on services provided, scope of region served, local/regional economic environment, etc. SPP’s recommended tariff cap rate compares favorably to its RTO peers in terms of recoverable expenses per MWh1.
Recommendation The Finance Committee recommends the SPP Board of Directors approve an increase the Schedule 1-A admin fee cap to 39¢/MWh and authorize SPP staff to make the appropriate filings with FERC for approval.
Approved: Finance Committee July 11, 2013
Action Requested: Approve Recommendation
1 RTO cost based on 2012 annual reports, FERC filings, and other public information
2012 ISO Expense Comparison (per MWh)PJM MISO ERCOT CAISO NYISO ISO NE
0.34$ 0.45$ 0.80$ 0.81$ 0.85$ 1.10$
1
Finance Committee Report
July 30, 2013
Harry Skilton – Chair
SPP Finance Committee Roster
Harry Skilton, Chair Director
Larry Altenbaumer, Vice Chair Director
Mike Wise Golden Spread
Coleen Wells KEPCo
Sandra Bennett AEP
Kelly Harrison Westar
2
2
SPP Finance Committee
ACTIVITIES
• Pension Fund Management
• Auditor Engagements
• Schedule 1A Administrative Fee Cap
• CFTC Exemption
• Aviation Strategy
3
SPP Finance Committee
Pension Fund Management
• Pension fund assets now total approx. $35 million
• Interviewed 3 firms to serve as manager/advisor
– Provide greater diversity of investments – Generate returns with higher predictability – Provide expert guidance to Committee enhancing ability
to meet fiduciary requirements
• Met with evaluated performance of existing investment managers
4
3
SPP Finance Committee
Auditor Engagements
• Reviewed engagements for financial, benefit plan, and controls audits
• Recommend change in controls audit engagement
– Lower costs – Fresh look at evolving controls – New insights on Integrated Marketplace controls
• Recommend continued engagement of incumbent financial and benefit plan auditors
• Implement requirement for audit partner rotation
5
SPP Finance Committee
Schedule 1A Administrative Fee Cap
• Current cap of 35¢/MWh
• Expect required rates to recover costs in next several years to be 37¢ - 38¢/MWh
• Increase in required recovery largely result of retirement of debt which funded Integrated Marketplace development
• Staff and Finance Committee continue to focus on efficiency and effectiveness initiatives to reduce fee in the future.
6
4
SPP Finance Committee
Schedule 1A Administrative Fee Cap
7
$0.000
$0.100
$0.200
$0.300
$0.400
$0.500
2004 2007 2010 2013 2016 2019 2022
$/M
Wh
Admin Fee Forecast Costs/MWh Admin Fee Cap Forecast Admin Fee Cap
SPP Finance Committee
Schedule 1A Administrative Fee Cap
• Current cap of 35¢/MWh
• Expect required rates to recover costs in next several years to be 37¢ - 38¢/MWh
• Increase in required recovery largely result of retirement of debt which funded Integrated Marketplace development
• Staff and Finance Committee continue to focus on efficiency and effectiveness initiatives to reduce fee in the future.
8
5
SPP Finance Committee
Schedule 1A Administrative Fee Cap
9
$0.0
$5.0
$10.0
$15.0
$20.0
$25.0
$30.0
$35.0
2012 2013 2014 2015 2016 2017 2018
De
bt
Re
tire
me
nt
($ m
illio
ns)
SPP DEBT RETIREMENTS 2012-2018
$23.0M$24.3M
$27.6M $28.0M
$31.3M
$12.7M$11.2M
Pmt/MWh 3.1¢ 3.5¢ 6.2¢ 6.3¢ 7.1¢ 7.0¢ 7.7¢O/S ($M) $271 $255 $232 $215 $197 $179 $158
SPP Finance Committee
CFTC Exemption
• Dodd Frank Act potentially subjected energy markets to CFTC jurisdiction
• RTOs collaboratively met with CFTC to understand energy market products that may fall under CFTC regulation
• Reached agreement on minimum participation criteria in RTO markets which would allow RTO markets to be exempt from CFTC regulation
• Approved addition of language to Attachment X of tariff incorporating acceptable minimum criteria requirements. 10
6
SPP Finance Committee
Aviation Strategy
• Reviewed analysis from SPP staff to acquire 6 seat prop airplane for corporate travel.
• Analysis indicated slightly positive to break-even economics when including soft cost savings
• Concerns raised included economic climate, regulatory standpoint, size of aircraft, safety, and corporate oversight
• Encouraged use of charter for select travel needs, continue review of corporate aircraft in future.
11
RTWG TRR 091 Recommendations to MOPC 7 16-17 2013.docx Page 1 of 2
Southwest Power Pool, Inc.
MARKETS AND OPERATIONS POLICY COMMITEE Recommendation to the Board of Directors
TRR 091
July 29-30, 2013
Organizational Roster The following persons are members of the Regional Tariff Working Group:
Dennis Reed, WR (Chair) Charles Locke, KCPL (Vice-Chair) Richard Andrysik, LES Bill Dowling, Midwest Energy Luke Haner, OPPD Tom Hestermann, Sunflower Rob Janssen, Dogwood David Kays, OGE Lloyd Kolb, Golden Spread David Linton, ITC Great Plains Tom Littleton, OMPA Bernie Liu, Xcel
Paul Malone, NPPD Adam McKinnie, MoPSC Robert Pennybaker, AEP Neil Rowland, KMEA Robert Shields, AECC Keith Tynes, ETEC John Varnell, Tenaska Bary Warren, EDE Mitch Williams, WFEC Brenda Fricano, SPP (Staff Secretary)
Background Please see the TRR Recommendation Report for TRR 091 that was included in the MOPC July 16-17, 2013 background materials.
Analysis Please see the TRR Recommendation Report for TRRs 091 that was included in the MOPC July 16-17, 2013 background materials.
Recommendation The MOPC recommends that the BOD approve its request regarding TRRs 091.
Action Requested: Approval of RTWG’s request on TRR 091.
APPROVED: MOPC July 16-17, 2013
Passed with five opposed-Cargill Power, City of Indep MO, ETEC, NTEC, TexLa and two abstentions-Entergy Asset and Golden Spread
RTWG TRR 091 Recommendations to MOPC 7 16-17 2013.docx Page 2 of 2
TRR Number
Description RTWG Meeting Vote
091
Proposed changes to the Aggregate Transmission Service Study process to allow SPP to close out the backlog of transmission service studies in conjunction with the implementation of the ATSS improvements that have been approved for MOPC’s review at its April 2013 meeting.
June 27, 2013
Approved unanimously
096
1. Bilateral Settlement Schedules: Revisions are suggested for provisions of Attachment AE regarding Bilateral Settlement Schedules. The addition of language to Section 8.2 is recommended to clarify that the Bilateral Settlement Schedules are tied to the physical capabilities of the system (i.e., are directly connected to the physical transfer of electricity and involve transactions in which title changes hands). 2. Notice Requirements for Information Requests: Revisions are suggested to Section 1.1 of Attachment AE to add a definition for the CFTC and to Section 11 (including subsections) of Attachment AE to remove requirements that SPP notify members if it provides their information to the CFTC and to clarify that SPP may provide member’s confidential information to the CFTC without prior consent. Research is ongoing regarding the FERC's requirements in the same context, and some additional revisions may be required to confirm terminology and whether some existing provisions are intended to include references to the FERC. 3. Minimum Financial Eligibility: Potential revisions to the SPP Tariff are described to address the minimum capitalization requirements for market participants as imposed by the Dodd-Frank legislation and the CFTC's April 2013 Order. While discussions with the CFTC are ongoing and may result in additional changes, revisions are suggested to Attachment X, Section 3.1.1.8 “Minimum Criteria for Participation” to move most of the current contents of the section to a new section 3.1.1.8.1 “Minimum Capitalization Requirements” and to add a new section 3.1.1.8.2 “Eligibility Requirements” that states the eligibility requirements set forth by the CFTC. Some corresponding revisions in other portions of Attachment X are described for consistency and to ensure that SPP is adequately protected and would be found in compliance with the exemption requirements.
July 3, 2013
Approved with one abstention (OPPD)
Southwest Power Pool, Inc.
MARKETS AND OPERATIONS POLICY COMMITTEE
Recommendation to the Board of Directors
January 29-30, 2013
2013 ITP20
Organizational Roster The following members represent the Economic Studies Working Group (ESWG): Alan Myers (Chairman), ITC Great Plains Kip Fox (Vice-Chairman), AEP Paul Dietz, Westar Energy Leon Howell, OG&E Kurt Stradley, LES Mike Swearingen, Tri-County Electric Al Tamimi, Sunflower Bruce Walkup, AECC Greg Sweet, Empire District Electric Randy Collier, CUS Michael Watt, OMPA Bennie Weeks, SPS The following members represent the Transmission Working Group (TWG): Noman Williams (Chairman), Sunflower Travis Hyde (Vice-Chairman), OG&E Mo Awad, Westar Energy Scott Benson, LES John Boshears, CUS Michael Mueller, AECC John Fulton, SPS Joe Fultz, GRDA Dan Lenihan, OPPD Randy Lindstrom, NPPD Jim McAvoy, OMPA Matt McGee, AEP Nathan McNeil, Midwest Energy Nate Morris, Empire District Electric Alan Myers, ITC Great Plains John Payne, KEPCo Jason Shook, GDS Associates Tim Smith, WFEC Mike Swearingen, Tri-County Electric Harold Wyble, KCPL
Background The Integrated Transmission Planning (ITP) process is an iterative three-year cycle that includes 20-Year, 10-Year, and Near-Term Assessments and targets a reasonable balance between long-term transmission investment and customer congestion costs (as well as many other benefits).
The ITP process is performed in accordance with SPP OATT Attachment O Section III and the ITP Manual, which is referenced in Attachment O Section III. The ITP Manual provides specifics on the three ITP processes including the ITP 20-Year Assessment (ITP20).
The ESWG and TWG approved the scope for the 2013 ITP20 study in April of 2012. The 2013 ITP20 assessment is an 18-month process that was performed throughout 2012 and the first half of 2013. SPP Staff collaborated with stakeholders through multiple ITP Summits and working group meetings held throughout the course of the study. The TWG reviewed and endorsed the 2013 ITP20 report and plan on June 26, 2013. The ESWG reviewed and endorsed the 2013 ITP20 report and plan on June 27, 2013.
Projects in the 2013 ITP20 plan do not fall within the four-year financial commitment window, and would not receive Notifications to Construct (NTC) as part of the 2013 ITP20 process. The project plan is to be used as a roadmap for the development of appropriate EHV projects in the coming years that would provide increased flexibility and value to SPP’s members as those needs become better known through the performance of other planning assessments.
Recommendation MOPC recommends the BOD to approve the 2013 ITP20 Report as documentation of completion of the 20-Year Assessment of the ITP planning process specified in SPP OATT Attachment O Section III. ESWG/TWG further recommends the MOPC endorse the 2013 ITP20 plan as outlined in the 2013 ITP20 report.
APPROVED: MOPC July 16-17, 2013
Passed with four opposed-City Utilities of Springfield MO, Midwest Energy, Empire District, Xcel Energy and four abstentions-Entergy Asset Mgmt, Flat Ridge 2 Wind Energy, City of Indep MO, and NextEra
Approved: TWG 06/26/2013
Passed
ESWG 06/27/2013
Passed
Action Requested: Approve Recommendation
Southwest Power Pool, Inc.
ECONOMIC STUDIES WORKING GROUP TRANSMISSION WORKING GROUP
Recommendation to the MOPC
July 16-17, 2013
2015 ITP10 Futures and Key Assumptions Recommendation
Organizational Roster The following persons are members of the Transmission Working Group (TWG):
Noman Williams (Chairman), Sunflower Travis Hyde (Vice-Chairman), OG&E Mo Awad, Westar Energy Scott Benson, LES John Boshears, CUS John Fulton, SPS Joe Fultz, GRDA Dan Lenihan, OPPD Randy Lindstrom, NPPD Jim McAvoy, OMPA
Matt McGee, AEP Nathan McNeil, Midwest Energy Nate Morris, Empire District Electric Michael Mueller, AECC Alan Myers, ITC Great Plains John Payne, KEPCo Jason Shook, ETEC (GDS Associates) Tim Smith, WFEC Mike Swearingen, Tri-County Electric Harold Wyble, KCP&L
The following persons are members of the Economic Studies Working Group (ESWG):
Alan Myers, ITC Great Plains Kip Fox, AEP Randy Collier, CUS Paul Dietz, Westar Energy Leon Howell, OG&E David Ried, OPPD Kurt Stradley, LES
Mike Swearingen, Tri-County Electric Greg Sweet, Empire District Electric Al Tamimi, Sunflower Bruce Walkup, AECC Michael Watt, OMPA Bennie Weeks, Xcel Energy Mike Proctor, Liaison Member
Background As part of the Integrated Transmission Planning (ITP) process, SPP Staff will conduct the 2015 ITP Year 10 Assessment (ITP10). The assessment is conducted in accordance with the SPP Open Access Transmission Tariff (OATT) Attachment O and the approved ITP Manual. The objective of the ITP10 is to develop a 100 kV and above transmission plan for a tenth year to incorporate such needs as the following: a) resolving criteria violations; b) the mitigating known or foreseen congestion; c) meeting policy mandates and goals; d) improve access to markets; e) the staging of transmission expansion; and f) improving interconnections. The 2015 ITP10 study horizon will include modeling of the transmission system for ten years out (i.e. 2024). The ESWG and TWG will oversee the 2015 ITP10. To begin the process for the 2015 ITP10, staff has been coordinating with the ESWG and TWG to develop the study scope. While the 2015 ITP10 scope is still under development, the ESWG and TWG have discussed and each agreed to key concepts to help the 2015 ITP10 move forward. The key concepts include the futures for the study, the load forecasts for the study, and the new DC facilities connecting in SPP’s footprint. ESWG and TWG seek MOPC approval on these concepts at this time and will bring the full scope to the MOPC for approval in October.
Analysis The first concept for approval is the futures. ESWG developed three futures for the 2015 ITP10: Business as Usual, Decreased Base Load Capacity, and Increased Input Prices. One concern was brought up pertaining to these futures—SPP staff budgeted for two futures as part of the 2015 ITP10; staff estimates the impact of having one additional future is approximately $625,000 additional cost to the members. In June and July respectively, ESWG and TWG unanimously approved the three proposed futures.
The second concept that was discussed and approved by TWG and ESWG is the use of the 2013 High Priority Incremental Load Study (HPILS) loads and results in the 2015 ITP10. While there are varying load levels being studied in the 2013 HPILS, staff recommended to include the 2013 HPILS load forecasts for 50/50 probability (See the 2013 HPILS scope under the TWG agenda item for more details). Staff also recommended adding the HPILS NTCs, if issued, into the study upon HPILS completion in April 2014. There was much discussion on whether the loads or NTCs from the 2013 HPILS should be included in the 2015 ITP10. Both ESWG and TWG approved using the 50/50 HPILS loads and including HPILS NTCs in the 2015 ITP10. See the Minority Opinions section for differing views.
The last concept the working groups debated is the treatment of new DC facilities in the 2015 ITP10. While the Tres Amigas and Clean Line’s Plains & Eastern facilities are not in-service, the ESWG and TWG recognized they may need to be modeled in the 2015 ITP10. ESWG agreed to modeling both Tres Amigas and Plains & Eastern without voting on the whether flows will move across the facilities. TWG varied from ESWG by agreeing that the new facilities need to have a signed interconnection agreement on both sides of the new facilities and that flows across these DC facilities should be based on long-term firm transmission service (i.e. Tres Amigas has IAs and would be modeled with no flow across the tie and Clean Line’s Plains & Eastern facility does not have IAs but may be modeled with no flow across the facility at a later date if IAs are obtained). Both groups unanimously approved their own ideas. TWG and ESWG bring their views to MOPC to make a decision.
Minority Opinion A few TWG and ESWG members were concerned with the second concept—the inclusion of the 2013 HPILS loads and NTCs in the 2015 ITP10. They were uncertain of the results that will come from 2013 HPILS and wanted to wait until the conclusion of the 2013 HPILS to determine treatment of its loads and NTCs in the 2015 ITP10. Empire District Electric’s reasons to not include this load and NTCs are the following: “The results of the HPILS study are total unknowns, including these types of speculative loads/results seems to counter previous and present planning efforts; NTC’s to be issued for projects that are weighted towards near-term in-service dates will most likely be unable to be recalled due to the pressing timeline inherent to these types of loads, and the types of loads to be considered will most likely not have equal concentration at the 10-year horizon. Empire as well as other members voiced support for conducting the HPILS study apart from the 2015 ITP10, reviewing the initial results, and then making the determination of whether such results should be included in the 2015 ITP10.”
Recommendation The MOPC recommend the BOD approve the following recommendations for the 2015 ITP10:
1) Approve the Two proposed futures: Business as Usual, Decreased Base Load Capacity
2) Approve the 50/50 HPILS loads and Board Approved HPILS NTCs are included in the 2015 ITP10 study
3) MOPC recommends BOD approve new HVDC facilities be included in the 2015 ITP10 study if they have executed Transmission-Transmission Interconnection Agreement (both ends) and flows across the facilities be based on firm transmission service.
APPROVED: MOPC July 16-17, 2013
Recommendation #1 Passed with one abstention-Flat Ridge 2 Wind Energy
Recommendation #1 Passed as modified with one abstention-Flat Ridge WE
Recommendation #3 Passed with four opposed-Golden Spread, KGE Westar, Midwest Energy, Westar Energy and three abstentions-Plains and Eastern Clean Line, Grain Belt Express Clean Line and Flat Ridge WE.
Approved: TWG July 3, 2013
1) Passed Unopposed 2) Passed with 13 for, 3 against, and 1 abstention 3) Passed Unopposed
ESWG June 6, 2013
1) Passed Unopposed 2) Passed with 6 for and 3 against (July 3, 2013) 3) Passed with 8 for and 1 against
Action Requested: Approved Recommendation
1
2015 ITP10 Update
July 29, 2013
Alan Myers
Chairman, ESWG
ITC Great Plains, LLC
Overview
2
• 2015 ITP10 Objectives
• Strategic Planning Committee’s Strategic Planning Scenarios and Drivers
– Link to ITP planning
• Discussion of proposed 2015 ITP10 futures
– Working group proposal
– MOPC/SPC direction
• Additional 2015 ITP10 key assumptions
2
2015 ITP10 OVERVIEW
Integrated Transmission Planning (ITP)
• Reducing Uncertainty
• Increasing Refinement
• Narrowing Focus
4
ITP20
ITP10
Near Term
Implementation
Conceptual
3
2015 ITP10 Expectations
• Value-based planning using multiple futures
• Integrates ITPNT and ITP20
• Objectives
– Resolve criteria violations
– Mitigate foreseen congestion
– Fulfill Policy Requirements
– Improve access to markets
– Improve interconnections
5
6
MOPC
Scope
Approval
2015 ITP10
Futures
Discussion
TODAY’S BOD
Next Steps
Resource Plan
Load and Generation Review
Model Development
Scope Approval
TWG/ESWG
Scope
Approval
Aug./Sept. Octob
er
4
STRATEGIC PLANNING SCENARIOS AND DRIVERS
Strategic Planning Scenarios and Drivers
8
• SPC recently completed development of four scenarios for use in long-range strategic planning. These scenarios are:
– Expected Case
– Gas Supply Bust
– Water Shortage
– Infrastructure Attack
• SPC also adopted a set of five critical drivers (commodity prices, regulation, economy, technological innovation, and consumer perception)
5
Strategic Planning Scenarios and Drivers
9
• Use of Scenarios and Drivers in ITP
– The SPC has recommended that the ESWG consider the scenarios in longer-term planning efforts.
– Due to timing, this information could not be included in the development of the ITP20.
– ESWG has attempted include this information in the 2015 ITP10 study => starting with scenarios.
PROPOSED 2015 ITP10 FUTURES
6
Future 1 Business as Usual
Future 2 EPA Rules with
Additional Wind
2012 ITP10 Futures
11
2013 ITP20 Futures
12
Business as Usual
Additional Wind
Additional Wind plus Exports
Combined Policy
Joint Future with MISO
7
Futures* • Futures Proposed by ESWG
– Business as Usual => Expected Case
– Decreased Base Load Capacity => Water Shortage, Infrastructure Attack, etc.
– Increased Input Prices => Gas Supply Bust
• Futures approved/endorsed by both ESWG and TWG unanimously
– TWG motion: TWG endorses the 3 different futures as described by ESWG with a 50% weighting on Future 1
– ESWG did not include weighting in futures approval
*A 3rd future was not originally budgeted
Business as Usual
14
• Primary Features
– Present EPA Rules, retirements as identified by members.
– Existing wind/renewable energy (Approx. 8 GW) plus new renewable energy per renewable energy survey.
– Expected load growth, i.e. extrapolation of recent load growth patterns and historical norms
– Gas curve based on 2013 Ventyx forecast (particulars still under discussion).
• Expected Impact
– Transmission plan based primarily around existing resources and modest increase in renewable energy.
8
Decreased Baseload Capacity
15
• Primary Features
– Reduction in baseload capacity due to a variety of potential strategic factors including water restrictions, environmental pressure, cyber-security, etc
– Capacity replacements likely to come primarily from gas with economic addition of renewable energy as well => economics of renewables improve relative to natural gas
• Expected Impact
– Resource plan built around significant increase in gas generation with significant amount of increase at location of retired coal units with/near major gas lines
– Additional renewable generation
Increases Input Prices
16
• Primary Features
– Natural gas supply curtailed as a result of regulation brought on by external influence (e.g. water table flooding, earthquakes, etc.).
– Potential for increased cost of building materials.
– Environmental pressures on coal continue.
– Increase in usage of renewables.
• Expected Outcome
– Targeted generation location could become more common.
– Increase in transmission to deliver additional renewables possible.
9
MOPC VOTE/SPC DIRECTION
MOPC Vote
18
• July 16-17 MOPC
– ESWG and TWG recommended approval of three futures.
– Key item of discussion was additional $500-750k to perform studies required by third future.
– MOPC ultimately decided it did not have sufficient information or justification for additional expenditure.
– MOPC approved a motion to direct ESWG and TWG to perform 2105 ITP10 study with two futures: Business as Usual and Decreased Baseload Capacity.
– A proposal was made (and voted down) to direct staff to continue developing a third future for October MOPC consideration.
10
SPC Direction
19
• July 18 SPC
– Original proposal for three futures and subsequent MOPC direction for two was presented to SPC for input.
– SPC espoused the view that a third future should be considered but it should be more “holistic”.
– Ultimately, SPC directed that a better description of each proposed future be developed and presented at the July BOD/members committee meeting for discussion.
– SPC also directed staff to be prepared to share workload prioritization should direction be given to study a third future.
ADDITIONAL 2015 ITP10 KEY ASSUMPTIONS
11
HPILS* Loads and NTC Modeling
• Base Case Modeling Assumptions
– Include HPILS loads and HPILS NTCs
– Load forecast assumes 50/50 probability
• Approved by both ESWG and TWG
– Neither unanimously approved
– Discussion topics
Uncertainty of load in HPILS
Rate of incremental load growth unequal throughout SPP region
Impact on 2015 ITP10 integrity
21 *2013 High Priority Incremental Load Study
HVDC Ties and Lines
• ESWG Approval (June 6, 2013)
– Approved Tres Amigas and Clean Line Plains & Eastern be included in the base case
• TWG Approval (July 3, 2013)
– TWG approved including HVDC ties and lines with a executed Transmission-Transmission Interconnection Agreement (both ends) in the base case and flows across these DC facilities would be based on long-term firm transmission service
Include Tres Amigas
Include Plains & Eastern if IAs executed
22
12
MOPC Direction
• HPILS Load and NTC’s
– MOPC approved inclusion of 50/50 incremental HPILS loads in the 2015 ITP10 study.
– MOPC approved inclusion of BOD-approved NTC’s that result from the HPILS study in the 2015 ITP10 base case.
• HVDC Ties and Lines
– MOPC approved including HVDC ties and lines with executed Transmission-Transmission Interconnection Agreements (both ends) in the base case and with flows across these DC facilities based on long-term firm transmission service. MOPC motion also directed SPP staff to develop sufficient modeling to allow economic interchange across the Tres Amigas tie.
23
MWG MPRR 133 Recommendations to MOPC_071613.docx Page 1 of 2
Southwest Power Pool, Inc.
MARKET AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors
MPPR 133 July 29-30, 2013
Organizational Roster
The following members represent the Market Working Group:
Richard Ross, AEP, Chairman Gene Anderson, OMPA, Vice Chairman Will Amos, OGE Lee Anderson, Lincoln Electric System Amber Metzker, Xcel Energy Neal Daney, KMEA Jim Flucke, KCPL Clifford Franklin, Westar Energy, Inc. Matt Johnson, City Utilities, Springfield, MO Chris Lyons, Constellation Energy Commodities Group Rick McCord, EDE Matt Moore, Golden Spread Electric Cooperative Aaron Rome, Midwest Energy, Inc. Ann Scott, Tenaska Power Services Co. Mike Swearingen, Tri-County Electric Cooperative, Inc. Ron Thompson, NPPD Bruce Walkup, AECC Rick Yanovich, OPPD Debbie James, SPP, Secretary
Background
Please see the MPRR Recommendation Report for MPRR 133 that was included in the MOPC July 16-17, 2013 background materials.
Analysis
Please see the MPRR Recommendation Report for MPPR 133 that was included in the MOPC July16-17, 2013 background materials.
Recommendation
The MOPC recommends that the BOD approve MPRR 133 giving Staff, working with the RTWG Chair, latitude to update language to allow Staff the flexibility to decline nominating ARRs. The implementation of the appropriate software for the distribution of the net of the “carve-out” would trigger a resettlement from the default distribution through RNU back to the start of the Market.
Action Requested: Approval of MWG’s request on MPPR 133 as modified.
MWG MPRR 133 Recommendations to MOPC_071613.docx Page 2 of 2
APPROVED: MOPC July 16-17, 2013 Passed as modified with four opposed-OPPD, LES, Dogwood Energy, NPPD and
thirteen abstentions-Calpine Energy, Cty Utilities Springfield MO, Exelon Power, OMPA, Sunflower Elec, ITC Great Plains, Tenaska Power, NextEra, Sunflower Elec Mid-KS, Prairie Wind Transmission, BPU KS, Cty of Independence MO, Cty of Coffeyville
MPRR Number
Description
MWG Meeting Vote
RTWG Meeting Vote
ORWG Meeting Vote
133 GFA Carve Out
6/19/2013 Approved
6/28/2013 Approved
6/27/2013 Approved
6/28/2013 Approved with no Reliability Impact
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 1 of 33
PRR Recommendation Report PRR No. Marketplace-PRR133 PRR
Title GFA Carve Out
Timeline Normal Expedited Urgent Action
Provide explanation if Expedited and/or Urgent Action is selected: This MPRR is in response to the October 18, 2012 conditional acceptance filing from FERC.
Recommendation Action
Approve Reject
Require additional information
Defer Refer
Impact Analysis Required Yes – If yes, estimated cost: No
SPP Staff will complete this section.
Protocol Section(s) Requiring Revision
Section No.: 1; 4.2.1.1; 4.5.3; 4.5.3.1; 4.5.3.2 (new); 4.5.3.3 (new); 4.5.8.19; 4.5.12; 5.1.1; 5.2.3; 5.3.2; 5.4; 5.5 Title: Glossary; Day-Ahead Market; Bilateral Settlement Schedules; Transition Mechanism for Pre-Existing Bilateral Contracts; GFA Carve Out Schedules-Internal (new); GFA Carve Out Schedule-External (new); Day-Ahead Over-Collected Losses Distribution Amount; Revenue Neutrality Uplift Distribution Amount; Transmission Service Verification; Simultaneous Feasibility; Annual TCR Auction Process; Monthly ARR Allocation Process; Monthly TCR Auction Processes Protocol Version: 14.0a
Type of Revision Correction/Clean-Up Clarification
Design Enhancement Design Change
Timeline Go-Live Post Go-Live
Revision Description
This MPRR adds GFA Carve Out language that removes congestion and marginal loss charges for the amount of energy actually transacted associated with GFAs that are carved out. Market Participants that have GFA Carve Outs will not receive candidate ARRs for the transmission service associated with the GFAs. The candidate ARR along with any corresponding TCRs will be included in the TCR Market using a GFA Carve Out account.
Market Participants will use DA Market GFA Carve Out Schedules to offset DA Market LMP charges associated with the GFA transaction. These offsets will transfer any charges/credits to the GFA Carve Out account. Any net charges/credits associated with the GFA Carve Out account will then be allocated via a load ratio share uplift charge to the transmission Zone where the GFA is located.
Tariff Implications or Changes
Yes – Section No.: (Include a summary of impact and/or specific changes) Attachment AE 1.1 Definitions G; 2.2 Application and Asset Registration; 2.16 Grandfathered Agreements (new); 7.0 Transmission Congestion Rights Markets; 8.2 Bilateral Settlement Schedules and GFA Carve Outs; 8.2.1 Bilateral Settlement Schedules; 8.2.1.1 Default Procedures for Pre-Existing Bilateral Contracts Transitioning to Integrated Marketplace; 8.2.2 GFA Carve Out (new); 8.2.2.1 GFA carve Out Schedules (new); 8.8 Revenue Neutrality Uplift Distribution Amount; 10.1 Settlement Statements; Attachment AG Market Monitoring Plan 4.2 Market Monitoring Scope
EIS Market
Integrated Marketplace
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 2 of 33
No
MWG Review PRR Recommendation
Date of Vote: 6/19/2013 - Approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: Opposed – LES, OPPD, NPPD Abstained – Xcel, TNSK, KMEA, CUS Date of Vote: 6/28/2013 - Approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: Opposed – LES, NPPD Abstained –TNSK, GSEC, KMEA, OPPD Date of Vote: 7/24/2013 - Approved All Segments present for the vote: Yes No Segment of Parties that voted No or Abstained: Opposed – LES, OPPD, NPPD Abstained – GSEC
RTWG Review 6/27/2013 – Approved Opposed – LES, NPPD Abstain – ETEC
ORWG Review 6/28/2013 – Unanimously Approved with no Reliability Impact
MOPC Recommendation 7/17/2013 – Approved
Board Review
Date 6/19/2013
SponsorName Nick Parker E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.614.3574
Comments ReceivedComment Author Westar Date 6/19/2013
Comment Description Westar submitted comments on MPRR133. MWG rejected the three year sunset clause recommended by Westar because the MWG said FERC would not agree to the sunset of GFAs. All other comments were taken under consideration.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Comments Received
Comment Author Micha Bailey on behalf of MWG Date 6/19/2013 Comment Description MWG changed “Bilateral Settlement Schedule” to “GFA Carve Out Schedule”.
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MWG added more language to further define the GFA Carve Out process. The MWG added language to the Tariff to further define the GFA Carve Out process.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report.
Comments Received
Comment Author Brenda Fricano on behalf of RTWG Date 6/28/2013
Comment Description
RTWG made modifications to the Tariff language for clarity and to make the language conform to existing Tariff language. Section 2.2(13) of AE was changed to better reflect the definition of “GFA Responsible Entity”. Section 2.16(a) of AE was modified to contrast (b). Section 2.16 was also changed to add “or NITS” since “Transmission Service” only refers to Point To Point. Section 8.2.2 of AE was modified to clarify that the congestion and losses being referred to are in the Day-Ahead Market.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report
Comments Received
Comment Author Ronald Thompson (NPPD) Date 6/21/2013
Comment Description See proposed language changes in “MPRR 133 NPPD Comments 6-21-2013.docx” on spp.org
Comment Status Comment proposing treatment of GFA Carve Out losses was discussed. The GFA Carve Out loss language was not included in this recommendation report. Further work is needed, and if GFA Carve Losses are to be accounted for, a separate MPRR should be submitted.
Reasons for Opposing Dissenter NPPD Date 6/21/13
Reason
Significant changes to the document were made during the meeting, and SPP was directed to make additional changes “ to conform the protocols with the tariff”. Members were not allowed to review the document with all changes prior to the vote. In addition even after the vote there was confusion if the motion was for regional allocation or sub regional allocation. Some members thought that both would be presented to the MOPC not just Sub Regional.
NPPD agrees with the SPP attorney that FERC pointed to the MISO method which used regional allocation of costs associated with carve out. The allocation of the costs to the same entities that received the carve out would essentially eliminate the carve out treatment, and FERC would probably not look favorably on this deviation from the FERC directive. If allocated sub-regionally the net effect is put the GFA carve out customer back in a position as if there had been no carve out of the GFA in the first place.
The method of sub regional allocation was not clearly defined. If I understand it correctly the cost of the carve out would go the Transmission Pricing Zone of the entities involved in the carve out. In some cases some entities are not in a Transmission pricing zone
What would the impact to SPP to be to develop the process to manage the proposed Sub-Regional language for Carve outs. This has not been determined however is a issue.
The proposal still provides 100% return of losses. This increases the RNU. Carved Out paths will not have to pay Marginal Losses however they should have to at least pay System Losses
The treatment of the Carve out GFA as a DNR was contradictory to what
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 4 of 33
was stated in previous communications with NPPD and not defined in the tariff.
The failure to charge GFA customers with losses would constitute an unlawful modification of the contractual loss provisions of the GFAs
Reasons for Opposing
Dissenter LES Date 6/21/13
Reason
The only precedent we are aware for uplift of "net GFA carve out account deficiency/surplus" is MISO filing and approval by FERC and that is a regional allocation.
If allocated sub-regionally the net effect is put the GFA carve out customer back in a position as if there had been no carve out of the GFA in the first place. Thus in effect, the sub-regional allocation is a collateral attack on FERC's order to provide for carve out GFA's in the SPP market.
Sub-regional--- was it ever defined by MWG? If not too nebulous a term to utilize.
Comments Received
Comment Author Micha Bailey on behalf of MWG Date 7/24/2013
Comment Description
The motion at MOPC was that MOPC approve MPRR 133 giving staff, working with the RTWG chair, latitude to update language to allow staff the flexibility to decline nominating ARRs. MOPC approved MPRR133 at the July 16, meeting. Based on the approved motion, MWG made language changes accordingly. Protocols 4.5.3.4 (GFA Carve Out Uplift) language was changed to add further details on how the Candidate ARRs are handled for GFA Carve Outs. MWG changed language to Protocols 4.5.12 and Attachment AE 8.9 (GFA Carve Out Uplift Distribution Amount) to explain how the GFA Carve Out will be uplifted to the Market. MWG changes are highlighted in yellow.
Comment Status MWG approved the MPRR as modified. The approved language is reflected in this recommendation report. This language will be reviewed at the July 30th Board of Directors meeting as approved by RTWG.
Proposed Protocol Language Revision 1. Glossary
GFA Carve Out As defined in the SPP Tariff. GFA Carve Out Schedule As defined in the SPP Tariff. GFA Responsible Entity
As defined in the SPP Tariff.
4.2.1.1 Day-Ahead Market
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Each Market Participant must offer sufficient Resources to the Day-Ahead Market to cover load plus Operating Reserve obligation to the extent the Resources are available (e.g. not on forced outage, planned outage or Reserve Shutdown).
(1) A Market Participant’s load for purposes of this section shall be equal to the Market Participant’s maximum hourly Reported Load excluding any GFA Carve Out Schedules for the Operating Day.
(2) A Market Participant’s daily Operating Reserve obligation shall be equal to the sum of that Market Participant’s maximum daily Regulation-Up, Regulation-Down and Contingency Reserve obligation as calculated by SPP as described in Section 4.1.2.3(3).
(3) Only Resources submitted with a Commitment Status of Market or Self may be used to satisfy this requirement.
(4) A Market Participant’s net resource capacity, for purposes of this section shall include:
(a) Offered capacity by Resources identified in 4.2.1.1(3) less the Operating Reserve obligation identified in 4.2.1.1(2); and
(b) Firm Power purchases less the Firm Power sales.
(5) Market Participants with net resource capacity, as determined in Section 4.2.1.1(4), less than 90% of the Market Participant’s maximum hourly Reported Load excluding any GFA Carve Out Schedules for the Operating Day shall be deemed resource deficient and may be subject to sanctions as determined in Section 8.2.7.1.
(6) Resources used as the source of a GFA Carve Out must be offered, if available, with a sufficient capacity to cover the GFA Carve Out Schedule. GFA Carve Out treatment is only available to the extent that the Resources are offered into the DA Market using a commit treatment of “Market” or “Self.” To the extent the source is external, an Import Interchange Transaction must be submitted in the DA Market with a sufficient capacity to cover the GFA Carve Out Schedule.
4.5.3 Bilateral Settlement Schedules
Market Participants may create Bilateral Settlement Schedules for Energy and Operating Reserve obligation by registering and confirming the parameters of the agreement between buyer and seller such as the Schedule ID, Settlement Location, Reserve Zone, maximum allowable hourly quantity, market product, submitting party, auto-confirmation option and the effective & termination dates. Once this “header” information is validated and entered into the system by SPP, hourly quantities submitted reference the Schedule ID in order to be associated with all the parameters required for settlement calculations. In the event that either party no longer consents to participate in the Bilateral Settlement Schedule, or if SPP staff encounter recurring settlement dispute activity related to its usage the “header” information may be ended in advance of the original termination date effectively preventing further
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submittal of hourly quantities. In addition, if SPP encounters recurring settlement dispute activity relating to the use of the auto-confirmation option, SPP may remove that option from the header information for that Bilateral Settlement Schedule.
Market Participants may submit Bilateral Settlement Schedule quantities for Energy and Operating Reserve obligation up to four (4) days following the applicable Operating Day for the Initial settlement. New submittals and revisions to previously submitted values may be submitted up to 44 days following the applicable Operating Day to be included in the Final settlement. The submittal timeline is subject to acceleration around holidays (see Section 4.5.14). Auto-confirmation applies to only the first submittal per Operating Day and must occur prior to the cutoff for the Initial settlement. Submittals 1) for agreements not using the auto-confirmation option, 2) beyond the cutoff date for the Initial settlement or 3) which update previous submittals must all be explicitly confirmed by the submitting party and counterparty. Submittals not confirmed by both parties will not be included in any settlement execution.
Transactions related to Bilateral Settlement Schedules for Energy must specify the Settlement Location, the MW amount, the buyer, the seller and which market it applies to (DA Market or RTBM). The seller receives an increase in load obligation equal to the specified MW amount and the buyer receives a reduction in load obligation equal to the specified MW amount (the equivalent of a Resource settlement) at the specified Settlement Location.
Transactions related to Bilateral Settlement Schedules for Operating Reserve obligation must specify the buyer, the seller, the Operating Reserve product, the MW obligation transfer and the Reserve Zone within which the obligation transfer applies (Operating Reserve Bilateral Settlement Schedules only apply to Day-Ahead Market cost allocation). The seller receives an increase in Operating Reserve obligation equal to the specified MW and the buyer receives a corresponding decrease in Operating Reserve obligation within the specified Reserve Zone.
4.5.3.1 Transition Mechanism for Pre-Existing Bilateral Contracts
To the extent that Market Participants are parties to bilateral contracts entered into prior to October 18, 2012, the rules specified under Section 8.2.1 of Attachment AE to the Tariff shall apply regarding submittal of Bilateral Settlement Schedules that are associated with such bilateral contracts.
4.5.3.2 GFA Carve Out Schedules - Internal
The GFA Responsible Entity must submit GFA Carve Out Schedules for all of the energy actually
transacted under the GFA. These GFA Carve Out Schedules must be submitted in accordance with the
requirements of Section 4.5.3, as specifically modified in section 4.5.3.2. If no energy is transacted
under the GFA, then no schedule is required and no GFA Carve Out treatment will be provided. Up to
four (4) DA Market GFA Carve Out Schedules for energy may be required for each GFA Carve Out
transaction:
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(1) GFA Carve Out Schedule #1 (a) Seller: MP responsible for the source (b) Buyer: GFA Responsible Entity (c) Settlement Location: Source Settlement Location of the GFA transmission service
(2) GFA Carve Out Schedule #2 (a) Seller: GFA Responsible Entity (b) Buyer: GFA Carve Out account (c) Settlement Location: Source Settlement Location of the GFA transmission service
(3) GFA Carve Out Schedule #3 (a) Seller: GFA Carve Out account (b) Buyer: GFA Responsible Entity (c) Settlement Location: Sink Settlement Location of the GFA transmission service
(4) GFA Carve Out Schedule #4 (a) Seller: GFA Responsible Entity (b) Buyer: MP responsible for the sink (c) Settlement Location: Sink Settlement Location of the GFA transmission service
If the Market Participant that is responsible for the source is the same as the GFA Responsible Entity, then #1 above does not apply. If the Market Participant that is responsible for the sink is the same as the GFA Responsible Entity, then #4 above does not apply. The seller receives an increase in load obligation equal to the specified MW amount and the buyer receives a reduction in load obligation equal to the transacted MW amount at the specified Settlement Location. These Schedules will be settled at DA Market prices.
The GFA Responsible Entity is responsible to ensure the consistency of the GFA Carve Out Schedules,
and shall submit monthly GFA invoices and hourly details of all energy actually transacted under the
GFA to the Transmission Provider for auditing purposes. The Transmission Provider will compare all
GFA Carve Out Schedules to the actual hourly energy transactions and may request the GFA
Responsible Entity to explain any deviations. Deviations may be reported to the Commission’s Office of
Enforcement, or its successor organization.
The Transmission Provider shall publish a quarterly report listing the costs allocated to the market caused by the associated GFA Carve Outs. The report should also provide hourly and monthly deviations associated with the GFA Carve Out Schedules.
4.5.3.3 GFA Carve Out Schedules - External
In addition to 4.5.3.2, if the source or sink of the energy receiving GFA Carve Out treatment is external to the SPP BA, a Fixed Interchange Transaction must be submitted and confirmed in the DA Market with sufficient capacity to cover the GFA Carve Out Schedule. The GFA Responsible Entity will ensure the values of the GFA Carve Out Schedules are equal to the lesser of the Day-Ahead cleared MW
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 8 of 33
volume, energy actually transacted under the GFA or the Real-Time hourly Interchange Transaction MW volume.
4.5.3.4 GFA Carve Out Uplift
GFA Carve Out Schedules result in removal of the energy, congestion, and marginal losses for the transaction from settlement statements. SPP will capture the congestion charges and marginal loss charges related to the GFA Carve Outs. These charges will be offset by the ARR/TCR settlement that would have been claimed for the GFA Carve Out under the normal ARR/TCR process and the distribution of the Marginal Loss Overcollection funds. Candidate ARRs associated with the GFA Carve Out service shall not be nominated for a product period if, based upon the twelve preceding months for which congestion data is available, such ARR, had it been converted to a TCR, would have resulted in a TcrFundHrlyAmt net charge to the holder of the TCR over that product period. However, until twelve months of Integrated Marketplace data is available, SPP will use relevant data from both the EIS Market and the Integrated Marketplace to estimate whether the result is a net charge. The congestion and marginal loss charges also will be offset by the distribution of the Marginal Loss Overcollection funds. The net resulting amount will be included in GFA Carve Out Uplift Distribution Amount under Section 4.5.12.
4.5.8.19 Day-Ahead Over-Collected Losses Distribution Amount
(1) The Marginal Losses Component of the DA Market LMP that results from the economic market solution which considers the cost of marginal losses, congestion costs and incremental Energy costs creates an over collection related to payment for losses (“DA Market Over-Collected Losses”) that must be refunded. A DA Market credit or charge1 is calculated for each hour at each Settlement Location for which an Asset Owner has a DA Market Energy withdrawal that contributed positively to the over collection. Each Asset Owner’s contribution to the DA Market Over-Collected Losses is calculated based upon a Loss Pool that is dynamically defined by the Asset Owner’s transactional activity. A loss rebate factor is calculated for each Asset Owner and withdrawal Settlement Location as the difference between the Marginal Loss Component at a withdrawal Settlement Location in the Asset Owner’s Loss Pool and the injection weighted average Marginal Loss Component for the Asset Owner’s Loss Pool, multiplied by the Asset Owner’s share of the net withdrawal (calculated excluding cleared Virtual Bids and cleared Virtual Offers) at that Settlement Location. The injection weighted average MLC for the Asset Owner’s Loss Pool is calculated assuming that injection in the Loss Pool first serves withdrawal in the Loss Pool and then goes to meet the withdrawal in Loss Pools which do not have sufficient injections to meet all withdrawals. The loss rebate factor (positive value only, negative values are ignored) is a measure of the Asset Owner’s payment for losses on a marginal basis at each Settlement Location.
1 Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
Comment [dtj21]: MWG and RTWG changes to reflect the 7-17-13 MOPC decision on treatment of ARRs.
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The loss rebate factors are then normalized to allocate a pro-rata portion of the total over collection in the hour to Asset Owners by Settlement Location. Asset Owners with GFA Carve Out energy transactions are not qualified to receive loss rebates associated with the GFA Carve Out transactions. The amount is calculated as follows:
4.5.12 GFA Carve Out Uplift Distribution Amount
The Transmission Provider shall perform the following calculation for each hour of the Operating Day for each Asset Owner and Settlement Location to ensure that the Transmission Provider is revenue neutral in each operating hour for the expense or credit attributed to GFA Carve Out(s) as calculated in accordance with Section 4.5.3.4. For each GFA Carve Out, the Transmission Provider shall calculate an hourly uplift charge or credit on a load ratio share basis to each Market Participant for all load Asset Owners it represents within the transmission Zone(s) associated with the GFA. However, prior to the time that the Transmission Provider has a system in place to perform these hourly transmission Zone uplift charges or credits, the GFA Carve-Out Uplift Distribution Amount shall be added to and included in the Daily RNU Distribution Amount determined under Section 4.5.13. When the Transmission Provider has such systems in place, any such charges or credits shall be resettled on a zonal basis from the start of the Integrated Marketplace. [** SPP to develop SETTLEMENT EQUATION TO INSERT INTO THE PROTOCOLS **]
4.5.12 13 Revenue Neutrality Uplift Distribution Amount
(1) A charge or credit will be calculated at each Settlement Location for each Asset Owner for each hour in order for SPP to remain revenue neutral. Contributors to revenue non-neutrality include:
(a) Rounding errors;
(b) Inadvertent Interchange (as calculated as shown in equation b.3 below);
(c) Joint Operating Agreement Charges/Credits;
(d) RTBM congestion (as calculated as shown in equation b.4 below);
(e) RTBM Regulation Deployment Adjustment;
(f) Make-Whole payments for Out-of-Merit Energy; and
(g) Miscellaneous Charges/Credits.
The amount will be determined by multiplying the Asset Owner hourly determinant by a daily Revenue Neutrality Uplift (RNU) rate. The Asset Owner hourly determinant is equal to the sum that Asset Owner’s actual generation MWh, actual load MWh, actual Interchange Transaction MWh, DA Market cleared Virtual Offer MWh and DA Market cleared Virtual Bid MWh for the Hour, where all of these values are assumed to be positive values.
5.1.1 Transmission Service Verification
Comment [dtj22]: MWG changes to reflect the 7-17-13 MOPC decision on the resettlement of charges after the software modifications are implemented.
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In order for Eligible Entities to obtain candidate ARRs, SPP must first verify existing transmission service entitlements, including transmission service entitlements which have been renewed in accordance with rollover rights since their initial term. In order to qualify for candidate ARRs in a particular month and/or season, an Eligible Entity’s transmission service must span the entire monthly or seasonal period within the applicable year. SPP will verify Eligible Entity existing transmission service entitlements as follows:
(1) For Eligible Entities taking Network Integration Transmission Service (NITS) and/or Firm Point-To-Point Transmission Service (FPTP) under the SPP Tariff:
(a) SPP will obtain source, sink and Reserved Capacity information from the SPP OASIS for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period;
(b) For a TSR with a source inside the SPP Market that is not a specific Resource or Resource Hub, the load Settlement Location that most closely corresponds to the source on the reservation will be utilized as the source for candidate ARRs;
(c) For a TSR with a source outside of the SPP Market, the interface associated with the Balancing Authority of the source will be utilized as the source;
(d) For a TSR with a sink outside of the SPP Market, the interface associated with the Balancing Authority of the sink will be utilized as the sink;
(e) SPP will provide this information to each Eligible Entity for verification;
(f) Eligible Entities will notify SPP within two (2) weeks following receipt of this information identifying and correcting inaccurate data. Otherwise, the SPP provided data will be considered verified.
(2) For Eligible Entities taking GFA service without Carve Out treatment:
(a) If the transmission customer under the GFA desires to nominate ARRs associated with the GFA source and sink identified in the Grandfathered Agreement, the GFA Parties must register such GFA with SPP and provide source, sink and Rreserved Ccapacity information. SPP will obtain source, sink and Rreservation Ccapacity information from the GFA registration for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period;
(b) For a GFA with a source inside the SPP Market that is not a specific Resource or Resource Hub, the load Settlement Location that most closely corresponds to the source on the reservation will be utilized as the source for candidate ARRs;
(c) For a GFA with a source outside of the SPP Market, the interface associated with the Balancing Authority of the source will be utilized as the source for candidate ARRs;
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(d) For a GFA with a sink outside of the SPP Market, the interface associated with the Balancing Authority of the sink will be utilized as the sink;
(e) In addition, the parties to the GFA must agree that the transmission customer under the GFA is eligible to nominate the ARRs associated with the GFA and both parties must confirm such with SPP. To the extent that the transmission service specified in the GFA is identified as the equivalent of SPP NITS, the transmission customer under the GFA must provide the historical non-coincident annual peak loads (“GFA Annual Peak Load”) being served under the GFA for the previous three years since February 1, 2007.
(3) For entities that have been granted GFA Carve Out treatment:
(a) GFAs with GFA Carve Out treatment are not eligible for candidate ARRs;
(b) The parties to the GFA must register the GFA with SPP, identify the GFA Responsible Entity, and provide source, sink and reserved capacity information. SPP will obtain source, sink and reserved capacity information from the GFA registration for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period;
(c) To the extent that the transmission service specified in the GFA Carve Out is identified as the equivalent of SPP NITS, the transmission customer under the GFA must provide the historical non-coincident annual peak loads (“GFA Annual Peak Load”) being served under the GFA for the previous three years.
5.2.3 Simultaneous Feasibility
A Simultaneous Feasibility Test (SFT) analysis is performed in each round to ensure that the nominated candidate ARRs, with nominated candidate ARR MW modeled as generation injection at the source and a corresponding load withdrawal at the sink, do not violate any normal transmission line thermal ratings under normal system conditions and do not violate short-term Emergency transmission line thermal ratings following a single contingency (N-1 contingency analysis). The SFT is performed consistent with the transmission system loading analysis that is performed as part the Security Constrained Economic Dispatch process in the DA Market and includes consideration of the impact of Parallel Flow.
(1) The SPP Transmission System topology used in the SFT is the most up-to-date Network Model for all allocation periods, updated for forecasted transmission topology changes including planned maintenance outages.
(a) For withdrawals at sink Settlement Locations containing more than one PNode, SPP will distribute the Settlement Location withdrawal down to the PNode level using load distribution percentages from the peak hour of the corresponding most recent historical period (i.e. June, July, August, September, Fall, Winter and Spring). These load distribution percentages are calculated using the methodology described under Section 4.1.2.1.6.
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(b) For injections at Market Hubs, SPP will distribute the hub injection down to the PNode level on a pro-rata basis using the weighting factors defined when the hub is created.
(c) For GFA Carve Outs, an injection at the source and a corresponding withdrawal at the sink will be included in the Annual ARR Allocation Process and will be subject to SFT. The capacity used in the allocation will be the maximum allowable nomination as defined in section 5.2.2.
5.3.2 Annual TCR Auction Process
TCRs are auctioned in a single-round process for each month and season using the SPP Residual Transmission System Capability as defined under Section 5.2.3 as follows:
(1) 100% of the SPP Residual Transmission System Capability is made available for the month of June, 90% of the SPP Residual Transmission System Capability is made available for the July-September period and 60% of the SPP Residual Transmission System Capability is made available for the Fall, Winter and Spring seasons;
(a) TCR Bids of the Self-Convert Type may be submitted for each source to sink pair that the Market Participant desires to convert the associated ARRs into TCRs. The Self-Convert Type option will convert ARRs associated with the specified source to sink pair into the TCR MW specified subject to simultaneous feasibility.
(b) Only Eligible Entities holding ARRs may submit a Self-Convert TCR Bid.
(c) All awarded ARRs from section 5.2.3(1)(c) that resulted from GFA Carve Outs will be automatically submitted to the TCR auction as self-convert TCR Bids.
(c)(d) The Self-Convert TCR Bid must specify the same source and sink as the associated ARR and the TCR MW must be less than or equal to the associated ARR MW.
5.4 Monthly ARR Allocation Process
Eligible Entities with remaining candidate ARR capacities from the Annual ARR Allocation Process along with firm transmission service that has been confirmed following completion of the Annual TCR Auction Process and prior to the next Annual ARR Verification Process or with firm transmission service confirmed prior to the Annual ARR Verification Process that includes a partial season or transmission service that is made available due to upgrades are eligible to nominate candidate ARRs associated with such services. Any remaining candidate ARR capacities from the Annual ARR Allocation Process related to GFA Carve Outs will be included in the Monthly ARR Allocation Process. To the extent that the Eligible Entity’s firm transmission service term extends beyond the current Annual ARR Allocation Process period, such remaining service will be included in the next Annual ARR Verification Process. The following rules apply to verification of transmission service for conversion to incremental candidate ARRs.
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5.5 Monthly TCR Auction Processes
The Monthly TCR Auction Process is the mechanism through which Market Participants may obtain TCRs over and above those obtained in the Annual TCR Auction Process through submission of TCR Bids to purchase TCRs and/or through conversion of remaining ARRs awarded in the Annual ARR Allocation Process and/or ARRs awarded in the Monthly ARR Allocation Process into TCRs through Self-Conversion. All awarded monthly ARRs that resulted from GFA Carve Outs will be automatically submitted to the TCR auction as self-convert TCR Bids for the maximum capacity allowable consistent with section 5.5.2. Market Participants may also offer for sale TCRs awarded in the Annual TCR Auction Process. 100% of the SPP Transmission System capability is made available during the Monthly TCR Auction Process. The remaining TCRs for the months of July through September are auctioned in a single-round process. The remaining TCRs for the months of October through May are auctioned in a two-round process. No later than three (3) Business Days prior the start of the Monthly TCR Auction Process, SPP will post the transmission system network topology data, along with corresponding Parallel Flow and transmission line outage assumptions, that SPP will use in the upcoming Monthly TCR Auction Process for use by Market Participants in developing their TCR Bid, TCR Offer and/or TCR self-conversion strategies. Exhibit 5-6 provides a representative timeline of the single-round and two-round Monthly TCR Auction Processes.
Proposed Tariff Language Revision Attachment AE
1.1 Definitions G
Good Utility Practice
As defined in Section 1 of the Tariff.
Grandfathered Agreement (“GFA”)
As defined in Section 1 of the Tariff.
GFA Carve Out
Removal of the congestion and marginal loss charges for the amount of energy (MWh) actually transacted associated with GFAs. GFA Carve Out Schedule A schedule entered by the GFA Responsible Entity for administering the GFA Carve Out.
GFA Responsible Entity
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An entity designated by the Transmission Owner that is registered or shall register as a Market
Participant and is financially responsible for all Day-Ahead and transactional costs pursuant to a GFA
Carve Out under this Tariff.
Grandfathered Agreement Firm Point-To-Point Auction Revenue Right Nomination Cap
The maximum amount of Grandfathered Agreement Firm Point-To-Point Candidate Auction Revenue
Rights that an Eligible Entity may nominate in each month and season in the annual Auction Revenue
Right allocation process or the monthly Auction Revenue Right allocation process.
Grandfathered Agreement Firm Point-To-Point Candidate Auction Revenue Right
All or a portion of the Megawatt quantity of the transmission service component of a Grandfathered
Agreement providing service equivalent to Firm Point-To-Point Transmission Service, as defined in the
Tariff which the applicable Eligible Entity can nominate for conversion into an Auction Revenue Right
in the annual Auction Revenue Right allocation process.
Grandfathered Agreement Network Integration Transmission Service Auction Revenue Right
Nomination Cap
The maximum amount of Grandfathered Agreement Network Integration Transmission Service
Candidate Auction Revenue Rights that an Eligible Entity may nominate in each month and season in
the annual Auction Revenue Right allocation process and the monthly Auction Revenue Right allocation
process.
Grandfathered Agreement Network Integration Transmission Service Candidate Auction
Revenue Right
All or a portion of the Megawatt quantity of the transmission service component of a Grandfathered
Agreement providing service equivalent to Network Integration Transmission Service, as defined in the
Tariff.
2.2 Application and Asset Registration
(1) Applications for a Market Participant to provide services in the Integrated Marketplace
must be submitted to the Transmission Provider prior to the expected date of participation
consistent with Section 6.4 of the Market Protocols. Applications must conform to the
procedures specified in the Market Protocols and may be rejected if not complete. New
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Market Participants will follow the timeframe as specified in Section 6.4 of the Market
Protocols in addition to the detailed model update timing requirements in Appendix E of
the Market Protocols.
(2) As part of the application process, Market Participants must register all Resources and
load, including applicable load associated with Grandfathered Agreements (“GFAs”),
Non-Conforming Load and Demand Response Load with the Transmission Provider in
accordance with the registration process specified in the Market Protocols. As part of
Resource registration, Market Participants must specify whether settlement meter data
will be submitted on a gross basis or net basis, where gross meter data does not include
reductions for auxiliary load and net meter data is gross meter data reduced by auxiliary
load. Both Non-Conforming Load and Demand Response Load may only be associated
with a single Price Node except that Non-Conforming Load and Demand Response Load
may be associated with an aggregated Price Node that contains multiple electrically
equivalent Price Nodes. Non-participating embedded load and/or generation must
either: (i) register its load and/or generation in the Integrated Marketplace; or (ii)
transfer its load and/or generation to an external Balancing Authority.
(3) Market Participants may elect to define a single Settlement Location that aggregates
multiple Meter Data Submittal Locations associated with their load assets. Market
Participants may not aggregate multiple Resource Meter Data Submittal Locations into a
single Resource Settlement Location unless the Resources are at the same physical and
electrically equivalent injection point to the Transmission System.
(4) In addition to the responsibilities described in Section 4.1.2 of this Attachment AE and
under the Market Protocols, Market Participants wishing to model each participant’s
share of a Jointly Owned Unit as a separate Resource must choose one of the two options
described below and provide the specified additional information. A Resource registered
as a combined cycle Resource may not register as a Jointly Owned Unit.
(a) Individual Resource Option
Under the individual Resource option, each participant’s share is modeled
as a separate Resource for the purposes of commitment and dispatch and each
Resource may be committed independent of the other Resource shares. In order
to qualify for this option, each Market Participant must register its share and
certify that it is greater than or equal to the minimum physical capacity operating
limit of the physical Jointly Owned Unit.
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The operating owner’s Meter Agent will be the Meter Agent for that
Jointly Owned Unit unless each individual Jointly Owned Unit participant
registers a Meter Agent for its share of the Resource.
Unless otherwise agreed to by the Jointly Owned Unit participants, the
operating owner will be responsible for submitting the following data:
Jointly Owned Unit maximum physical capacity operating limit;
Jointly Owned Unit minimum physical capacity operating limit; and
Maximum physical ten (10) minute response from an off-line state. (b) Combined Resource Option
Under the combined Resource option each participant’s share is modeled
and must be registered as a separate Resource. Under this option, the
commitment decision is made assuming that all Resource shares must be
committed or none at all. Once committed, each share is dispatched
independently. This option must be selected if the eligibility criteria stated under
the individual Resource option cannot be met.
The operating owner’s Meter Agent will be the Meter Agent for that
Jointly Owned Unit unless each individual Jointly Owned Unit participant
registers a Meter Agent for its share of the Resource.
Unless otherwise agreed to by the Jointly Owned Unit participants, the
operating owner will be responsible for submitting the following data:
Jointly Owned Unit maximum physical capacity operating limit;
Jointly Owned Unit minimum physical capacity operating limit;
Maximum physical ten (10) minute response from an off-line state;
and
Participant share percentage by Market Participant.
(5) Market Participants may modify their registered assets in accordance with the asset
registration procedures specified in the Market Protocols.
(6) All loads and all Resources, excluding Behind-The-Meter Generation less than 10
Megawatts (“MWs”), must register. Failure or refusal to register a Resource will result in
the Transmission Provider filing an unexecuted version of the service agreement as
specified in Attachment AH of this Tariff for that Resource with the Commission under
the name of the generation interconnection customer under an interconnection agreement
with the Transmission Provider or the applicable Transmission Owner. In the case of a
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Qualifying Facility exercising its rights under PURPA to deliver all of its net output to its
host utility, such registration will not require the Qualifying Facility to participate in the
Energy and Operating Reserve Markets or subject the Qualifying Facility to any charges
or payments related to the Energy and Operating Reserve Markets.
(7) A Market Participant wishing to Offer an External Resource in the Energy and Operating
Reserve Markets will utilize an External Resource Pseudo-Tie in accordance with
Attachment AO. In addition to the responsibilities outlined in Attachment AO, the
Market Participant registering the External Resource will be responsible for registering
and performing all responsibilities that are required of Resources in the Energy and
Operating Reserve Markets.
(8) A Market Participant wishing to offer Demand Response Load as a Demand Response
Resource in the Energy and Operating Reserve Markets must include in its application
and registration a certification that participation in the Energy and Operating Reserve
Markets by its Demand Response Resource is not precluded under the laws or regulations
of the relevant electric retail regulatory authority. Consistent with Section 2.8 of this
Attachment, an aggregator of retail customers wishing to offer Demand Response Load
in the form of a Demand Response Resource on behalf of one or more retail customers
must also include in its application and registration a certification that participation of
each retail customer is either: (1) not precluded by the laws or regulations of the relevant
electric retail regulatory authority if the customer is served by a utility that distributed
more than 4 million MWh in the previous fiscal year; or (2) affirmatively permitted by the
laws or regulations of the relevant electric retail regulatory authority if the customer is
served by a utility that distributed 4 million MWh or less in the previous fiscal year.
Demand Response Resources must meet all application, registration and technical
requirements applicable to the Energy and Operating Reserve Markets. The
Transmission Provider is not responsible for interpreting the laws or regulations of a
relevant electric retail regulatory authority and shall be required only to verify that the
Market Participant has included such a certification in its application materials. The
Transmission Provider is not liable or responsible for Market Participants participating in
the Energy and Operating Reserve Markets in violation of any law or regulation of a
relevant electric retail regulatory authority including state-approved retail tariff(s).
(9) An aggregator of retail customers offering Demand Response Load of one or more end-
use retail customers as a Demand Response Resource in the Energy and Operating
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Reserve Markets must be a Market Participant, satisfying all registration and certification
requirements applicable to Market Participants as well as certification consistent with
Section 2.8 of this Attachment.
(10) A wind-powered Variable Energy Resource (1) with an interconnection agreement
executed after May 21, 2011 or (2) an interconnection agreement executed on or prior to
May 21, 2011 and that commenced Commercial Operation on or after October, 15, 2012
must register as a Dispatchable Variable Energy Resource. A wind-powered Variable
Energy Resource with an interconnection agreement executed on or prior to May 21,
2011 may register as a Dispatchable Variable Energy Resource if it is capable of being
incrementally dispatched by the Transmission Provider. Variable Energy Resources with
fuel sources other than wind may optionally register as a Dispatchable Variable Energy
Resource. Otherwise, Variable Energy Resources must register as Non-Dispatchable
Variable Energy Resources. Any Resource that has previously registered as a
Dispatchable Variable Energy Resource shall not subsequently register as a Non-
Dispatchable Variable Energy Resource.
(11) A Market Participant that is selling firm power to the load asset under a bilateral
contract may, with the agreement of the buyer, register all or a portion of the buyer’s
load as its load asset. For purposes of this Section 2.2(11) of this Attachment AE, the
sale of firm power shall refer to power sales deliverable with firm transmission service,
where the capacity and energy is supplied under standards of reliability and availability
equivalent to supply of native load customers with the supplier assuming the obligation to
provide both capacity and energy.
(12) A Transmission Owner providing firm transmission service under a GFA eligible for
GFA Carve Out must request removal of congestion and marginal loss charges and
designate the GFA Responsible Entity within the timeframe set forth in Section 2.2 (1) of
Attachment AE.
(13) A GFA Responsible Entity shall provide to the Transmission Provider the information
necessary to administer the GFA Carve Out. The required information shall include the
following:
(a) Resource Settlement Location;
(b) Load Settlement Location;
(c) The maximum MW capacity contracted under the GFA Carve Out;
(d) The identification of the GFA in Attachment W; and
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(e) Any other information reasonably required by the Transmission Provider.
2.16 Grandfathered Agreement Carve Out
(a) Transmission Owners that are a party to GFA(s) eligible for GFA Carve Out 30 days prior to the
start of the initial transmission service verification as described in 7.1.1. of Attachment AE shall:
1. Elect GFA Carve Out;
2. Elect such GFA(s) be treated comparably to other firm transmission reservations eligible
for ARR and TCR in accordance with Attachment AE of this Tariff; or
3. Convert such GFA to Transmission Service or Network Integration Transmission Service
under this Tariff.
(b) A GFA added to Attachment W of the Tariff after October 18, 2012 shall be subject to the
following treatment:
(1) ARR and TCR eligibility under Attachment AE of this Tariff; or
(2) Full conversion to Transmission Service or Network Integration Transmission Service
under this Tariff.
7.0 Transmission Congestion Rights Markets (a) The TCR Markets process includes an annual ARR allocation, annual and monthly TCR
auctions and a monthly ARR allocation in accordance with the timelines specified in the Market
Protocols. The TCR Markets process is subject to review by the Market Monitor. ARRs are
obtained by Eligible Entities during the annual ARR allocation or the monthly ARR allocation.
TCRs are obtained by Market Participants through the annual and monthly TCR auctions.
There are seven (7) key processes associated with ARRs and TCRs:
(1) Annual ARR verification;
(2) Annual ARR allocation;
(3) Annual TCR auction;
(4) Monthly ARR allocation;
(5) Monthly TCR auction;
(6) ARR allocation and TCR auction settlements; and
(7) TCR secondary markets.
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Table 7-1 in Section 7.3.2 of this Attachment AE provides additional details related to
auction timing and Transmission System capability available for the TCR auctions.
(b) Except as otherwise provided in this Section 7.0.b (ii), an entity taking firm transmission
service under a GFA Carve Out will not be eligible to participate in the TCR Markets for the
MW capacity associated with the GFA Carve Out.
(i) The MW capacity associated with each GFA Carve Out shall be included in the
Transmission Provider’s ARR allocation, unless such ARR would be expected to
increase the GFA Carve-out Uplift Distribution Amount, as determined in
accordance with rules specified in the Market Protocols, and TCR auction
processes in a manner that reflects the transmission service pursuant to the GFA
Carve Out. Except as otherwise provided in Attachment AE, the GFA
Responsible Entity shall be financially responsible for any administrative costs by
the Transmission Provider associated with accounting for the ARR allocations
and TCR auctions associated with the GFA Carve Out.
(i)(ii) On an annual basis, the GFA Responsible Entity may elect, in writing, to cancel
the GFA Carve Out treatment and will be eligible to participate in the TCR
Markets pursuant to Section 7.0 of Attachment AE. The conversion of GFA Carve
Out to the TCR Market is irrevocable.
8.2 Bilateral Settlement Schedules and GFA Carve Outs
8.2.1 Bilateral Settlement Schedules
Market Participants may create Bilateral Settlement Schedules for Energy and Operating
Reserve obligations by registering and confirming the parameters of the agreement between
buyer and seller as described in the Market Protocols. Both the buyer and seller must confirm
the Bilateral Settlement Schedule. Either the buyer or seller may terminate the Bilateral
Settlement Schedule at any time. In addition, the Transmission Provider may terminate the
Bilateral Settlement Schedule if either party is in Default and the Transmission Provider will
resettle with Market Participants as if the Bilateral Settlement Schedule did not exist.
Market Participants may submit Bilateral Settlement Schedule quantities for Energy and
Operating Reserve obligation for use in the Day-Ahead Market and may submit Bilateral
Settlement Schedule quantities for Energy for use in the Real-Time Balancing Market up to four
(4) days following the applicable Operating Day for the initial settlement. New submittals and
revisions to previously submitted values may be submitted up to forty-four (44) days following
Comment [dtj3]: MWG and RTWG modification to reflect 7-17-13 MOPC decision on treatment of ARRs.
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the applicable Operating Day to be included in the final settlement. Submittals not confirmed by
both parties will not be included in any settlement execution.
Transactions related to Bilateral Settlement Schedules for Energy must specify the
Settlement Location, the MW amount, the buyer, the seller and which market it applies to (Day-
Ahead Market or RTBM). The seller receives an increase in load obligation equal to the
specified MW amount and the buyer receives a reduction in load obligation equal to the specified
MW amount (the equivalent of a Resource settlement) at the specified Settlement Location.
Transactions related to Bilateral Settlement Schedules for Operating Reserve obligation
must specify the buyer, the seller, the Operating Reserve product, the MW obligation transfer
and the Reserve Zone within which the obligation transfer applies. The seller receives an
increase in Operating Reserve obligation equal to the specified MW and the buyer receives a
corresponding decrease in Operating Reserve obligation within the specified Reserve Zone.
8.2.1.1 Default Procedures for Pre-Existing Bilateral Contracts Transitioning to Integrated
Marketplace
The procedures established under this Section 8.2.1 of Attachment AE shall apply to
bilateral contracts entered into prior to October 18, 2012, where the buyer and seller have not
agreed to the terms in the Bilateral Settlement Schedules corresponding to such pre-existing
bilateral contracts:
(1) Upon request of the buyer, the Transmission Provider shall review and confirm that a
particular bilateral contract exists between the buyer and seller. The Transmission
Provider shall schedule a meeting between a designated senior representative of the
buyer and seller within 30 days of such a request. The Transmission Provider shall
conduct these discussions in accordance with Section 12 of the Tariff. Following
confirmation, the buyer may register and confirm a Bilateral Settlement Schedule
representing the parameters of the agreement. The Transmission Provider shall confirm
that the buyer has submitted Bilateral Settlement Schedule parameters that are consistent
with those specified in the bilateral contract;
(2) Subsequent submission by either the buyer or the seller of Bilateral Settlement Schedules
for Energy and/or Operating Reserve associated with the registered Bilateral Settlement
Schedule in either the Day-Ahead Market and/or RTBM must be consistent with the
quantities specified in the bilateral contract. Only the buyer is required to confirm;
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(3) Only the buyer may terminate the Bilateral Settlement Schedule;
(4) The Settlement Location for Bilateral Settlement Schedules for Energy shall be the source
Settlement Location of the associated transmission service reservation as described
under Section 7.1.1(1)(a)(i) or 7.1.1(2)(a)(i) of this Attachment AE, as applicable;
(5) The Transmission Provider shall not be a party to Bilateral Settlement Schedules and
nothing in this Section 8.2.1 of Attachment AE shall impose on the Transmission Provider
any obligation regarding the settlement of financial rights and obligations between the
parties to Bilateral Settlement Schedules; and
(6) Nothing in this Section 8.2.1 of Attachment AE shall alter the parties’ rights and
obligations under preexisting bilateral contracts, limit the right of either party to seek
enforcement of such rights and obligations, and/or limit a party’s right to obtain
appropriate relief, pursuant to Section 206 of the FPA or as otherwise in accordance
with the law.
8.2.2 GFA Carve Out
A Market Participant receiving GFA Carve Out shall not be charged for the cost of congestion and cost
of marginal losses in the Day-Ahead Market for the amount of actual energy (MWh) transacted as
specified in the GFA Carve Out Schedule.
(a) GFA Carve Out is only available to the extent that the Resources are offered into the Day-Ahead Market using a commit status as described in Section 4.1(10) (a) or (b) of this Attachment AE. To the extent the source is external, an Import Interchange Transaction must be submitted in the Day-Ahead Market with sufficient capacity to cover the GFA Carve Out Schedule.
(b) The Transmission Provider will remove charges for cost of congestion and cost of marginal
losses from the Settlement Statement as provided in Section 10.1(5) of Attachment AE, only if
the GFA Responsible Entity submits a GFA Carve Out Schedule and E-Tag (as applicable)
according to the procedures specified in Section 8.2.2.1 of Attachment AE for the Day-Ahead
Market for the GFA Carve Out transaction, consistent with the GFA Settlement Locations, and
within the maximum MW Capacity permissible under the GFA Carve Out. The GFA
Responsible Entity must update the GFA Carve Out Schedule after the close of the Day-Ahead
Market with the actual energy transacted that corresponds to the GFA Carve Out.
(c) The Transmission Provider shall account for the GFA Carve Out in the TCR Markets, but shall
not allocate ARR or assign TCR to the GFA Responsible Entity for a GFA Carve Out.
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(d) The GFA Responsible Entity is responsible to coordinate the GFA Carve Out Schedule data and
to ensure the consistency of the GFA Carve Out Schedules, and shall submit monthly GFA
invoices and hourly details of all energy actually transacted under the GFA to the Transmission
Provider for auditing purposes. The Transmission Provider will compare all GFA Carve Out
Schedules to the actual hourly energy transactions and may request the GFA Responsible Entity
to explain any deviations. Deviations may be reported to the Commission’s Office of
Enforcement, or its successor organization.
8.2.2.1 GFA Carve Out Schedules
The GFA Responsible Entity shall create GFA Carve Out Schedules for all energy transacted
under the GFA, as described in the Market Protocols. The GFA Responsible Entity shall submit:
(i) GFA Carve Out Schedules for both the Resource Settlement Location and Load Settlement
Location within the SPP BA; and (ii) an E-Tag for GFA Carve Out transactions with Resource
Settlement Location or Load Settlement Location external to the SPP BA. Such submittal of the
GFA Carve Out Schedule and E-Tag (as applicable) shall be consistent with the provisions set
forth herein for any sales and purchases of Energy pursuant to a GFA Carve Out.
8.8 Revenue Neutrality Uplift Distribution Amount
The Transmission Provider shall perform the following calculation for each hour of the
Operating Day for each Asset Owner and Settlement Location to ensure that the Transmission
Provider is revenue neutral in each hour of the Operating Day. The Transmission Provider shall
calculate hourly summations to each Market Participant for all Asset Owners it represents and
shall calculate daily summations as specified in the Market Protocols.
Revenue Neutrality Uplift Distribution Amount =
Daily RNU Distribution Rate * RNU Distribution Volume * (-1)
(1) The Daily RNU Distribution Rate is equal to the Daily RNU Distribution Amount
divided by the Daily RNU Distribution Volume.
(a) The Daily RNU Distribution Amount is equal to:
(i) The sum of all Asset Owners’ charges and payments calculated under
Section 8.5, excluding payments under Sections 8.5.13, 8.5.14 and 8.5.15,
for the Operating Day; plus
(ii) The sum of all Asset Owners’ charges and payments calculated under
Section 8.6 for the Operating Day; plus
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(iii) The sum of all Asset Owners’ charges and payments calculated under
Section 8.7, excluding payments under Sections 8.7.4, 8.7.5 and 8.7.6;
plus
(iv) The sum of all charges and payments for emergency purchases and sales
entered into by the Transmission Provider in its Balancing Authority role
in order to alleviate a capacity shortage inside the SPP Balancing
Authority Area or to assist an external Balancing Authority in alleviating a
capacity shortage; plus
(v) Any other charges and credits not accounted for in subsections (i) through
(iv) above; minus
(vi) The Excess Congestion Fund Daily Amount calculated under Section
8.5.13(3)(a) for the Operating Day; minus
(vii) The Excess TCR Revenue Fund Daily Amount calculated under Section
8.7.4(3)(a) for the Operating Day.
(b) The Daily RNU Distribution Volume is equal to the sum of all Asset Owners’
RNU Distribution Volumes for the Operating Day.
(2) An Asset Owner’s RNU Distribution Volume at a Settlement Location for an hour is
equal to the sum of:
(a) The absolute value of actual metered generation or load in the hour; and
(b) The absolute value of scheduled Interchange Transactions in the hour; and
(c) The absolute value of cleared Virtual Energy Offers and Bids in the hour.
8.9 GFA Carve Out Uplift Distribution Amount The Transmission Provider shall perform the following calculation for each hour of the
Operating Day for each Asset Owner and Settlement Location to ensure that the Transmission
Provider is revenue neutral in each operating hour for the expense or credit attributed to GFA
Carve Out(s) as calculated in accordance with the Market Protocols. For each GFA Carve Out,
the Transmission Provider shall calculate an hourly uplift charge or credit on a load ratio share
basis to each Market Participant for all load Asset Owners it represents within the transmission
Zone(s) associated with the GFA. However, prior to the time that the Transmission Provider has
made the appropriate software modifications to calculate the hourly transmission zonal uplift
charges or credits, the GFA Carve-Out Uplift Distribution Amount shall be added to and
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 25 of 33
included in the Daily RNU Distribution Amount determined under Section 8.8(1)(a). When the
Transmission Provider has such software systems in place, any such charges or credits shall be
resettled on a zonal basis from the start of the Integrated Marketplace.
10.0 Billing The Transmission Provider shall prepare a billing statement each billing cycle in
accordance with this section of Attachment AE. Such billing statements shall be prepared for
each Market Participant in accordance with the charges and payments specified in Section 8 of
this Attachment AE, and showing the net amount to be paid or received by the Market
Participant. Billing statements shall provide sufficient detail, as specified in the Market
Protocols, to allow verification of the billing amounts and completion of the Market Participant’s
internal accounting. Unresolved billing disputes shall be settled in accordance with procedures
specified in Section 12 of the Tariff.
10.1 Settlement Statements
(1) The Transmission Provider shall issue a preliminary Settlement Statement for an
Operating Day no later than seven (7) calendar days following the applicable Operating
Day unless the seventh (7) day following the applicable Operating Day is not a business
day, in which case, the preliminary Settlement Statement shall be issued on the first
business day thereafter.
(2) The Transmission Provider shall issue a final Settlement Statement for an Operating Day
no later than forty-seven (47) calendar days following the applicable Operating Day
unless the forty-seventh (47) calendar day following the applicable Operating Day is not
a business day, in which case, the final Settlement Statement shall be issued on the first
(1) business day thereafter.
(3) The Transmission Provider shall make corrections to the preliminary and final Settlement
Statements for an Operating Day for data errors and Settlement Statement disputes that
have been resolved. Settlement associated with a specific Operating Day shall be
considered final at the end of the three hundred sixty-fifth (365) calendar day following
the applicable Operating Day.
(4) To the extent that a Market Participant, or its designated meter agent, does not submit
meter data representing that Market Participant’s actual Resource output and load
Comment [dtj4]: MWG and RTWG changes to reflect 7-17-13 MOPC decision on resettlement of charges after software modifications are implemented.
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 26 of 33
consumption, either on a five (5) minute basis or an hourly basis in accordance with the
timelines specified in the Market Protocols, the Transmission Provider shall use
estimated data for that Market Participant that is equal to that Market Participant’s
telemetered generation and load for the applicable intervals or State Estimator values if
telemetered values are not available for the purposes of calculating the preliminary
statements specified under Sections 10.1(1). To the extent a Meter Agent does not
submit data representing the metering of each interconnecting tie-line between Settlement
Areas, the Transmission Provider will substitute State Estimator values. In the event that
actual meter data is not submitted prior to the issuance of a final Settlement Statement,
the Transmission Provider shall use the best available data, which may include estimated
meter data as developed by the Transmission Provider, for the purposes of calculating
final Settlement Statements.
(5) The Transmission Provider shall remove from the GFA Responsible Entity’s Settlement
Statement all charges associated with the cost of congestion and the cost of losses for
GFA Carve Out transactions based on the Day-Ahead Market for the designated
Settlement Locations, as set forth in Section 8.2.2 of Attachment AE. The Transmission
Provider removal of all charges associated with the cost of congestion and the cost of
losses for GFA Carve Out is subject to the GFA Responsible Entity’s compliance with
the requirements of Section 8.2.2.1 of Attachment AE
ATTACHMENT AG MARKET MONITORING PLAN
4. Market Monitoring
4.1 Markets to be Monitored
The Market Monitor will monitor Markets and Services. The Market Monitor will not
monitor bilateral energy, transmission or capacity markets and services not administered,
coordinated or facilitated by SPP, except to assess the effect of these markets and
services on Markets and Services, or the effects of Markets and Services on these
unmonitored markets. Similarly, the Market Monitor will not monitor the energy,
transmission or capacity markets and services in regions adjacent to the SPP Region
except to assess the effect of these markets and services on Markets and Services, or the
effects of Markets and Services on these adjacent markets.
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 27 of 33
4.2 Market Monitoring Scope
The Market Monitor will implement the Plan. The markets will require continuous
monitoring by the Market Monitor. The Market Monitor will monitor Markets and
Services by reviewing and analyzing market data and information including, but not
limited to:
(a) Resource registration data;
(b) Resource Offer data including non-price related offer parameters required for use
in either the Day-Ahead Market, Reliability Unit Commitment process and/or
Real-Time Balancing Market;
(c) Demand Bids for the purchase of Energy in the Day-Ahead Market;
(d) Virtual Energy Bids for the purchase of Energy in the Day-Ahead Market and
Virtual Energy Offers for the sale of Energy in the Day-Ahead Energy Market;
(e) Export Interchange Transaction Bids and Import Interchange Transaction Offers
for the purchase and sale of Energy in the Day-Ahead Market and the Real-Time
Balancing Market;
(f) Actual commitment and dispatch of Resources, including but not limited to
Resource MW capability and output, MVAR capability and output, status, and
outages;
(g) Locational Marginal Prices and zonal Market Clearing Prices at all Settlement
Locations in or affecting any of Markets and Services;
(h) SPP Balancing Authority Area data, including but not limited to demand, area
control error, Net Scheduled Interchange, actual total net interchange, and
forecasts of operating reserves and peak demand;
(i) Conditions or events both inside and outside the SPP Balancing Authority Area
affecting the supply and demand for, and the quantity and price of, products or
services sold or to be sold in Markets and Services;
(j) Information regarding transmission services and rights, including the estimating
and posting of Available Transfer Capability (“ATC”) or Available Flowgate
Capability (“AFC”), administration of this Tariff, the operation and maintenance
of the transmission system, any auctions or other markets for transmission rights,
and the reservation and scheduling of transmission service;
(k) Information regarding the nature and extent of transmission congestion in the
region and, to the extent practicable, transmission congestion on any other system
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 28 of 33
that affects Markets and Services, including but not limited to causes of, costs of
and charges for transmission congestion, transmission facility loading, MVA
capability, line status and outages;
(l) Settlement data for the Markets and Services;
(m) Any information regarding collusive or other anticompetitive or inefficient
behavior in or affecting any of Markets and Services; and
(n) Generation resource operating cost data for estimating resource incremental cost,
including fuel input costs, heat rates where applicable, start-up fuel requirements,
environmental costs and variable operating and maintenance expenses.
(o) Logs of transmission service requests and Generation Interconnection Requests
along with the disposition of each request and the explanation of any refused
requests: and
(p) Any additional Resource and transmission facility outage data not otherwise
provided for in this Section 4.2.
(q) GFA Carve Out Schedules.
FORM OF SERVICE AGREEMENT FOR MARKET PARTICIPANTS IN THE INTEGRATED MARKETPLACE
1. This Service Agreement dated as of _______________ is entered into by and between
__________________ (Transmission Provider) and ______________________ (Customer).
2. The Customer has submitted an application for participation in the Integrated Marketplace and
desires to register as a Market Participant in accordance with the market application and asset
registration procedures specified in the Market Protocols and has provided the information
specified in Appendix 1 to this Service Agreement.
3. The Customer represents and warrants that it has met all applicable requirements set forth in the
Transmission Provider's Tariff and has complied with all applicable procedures under the Tariff.
4. The Transmission Provider agrees to provide and the Customer agrees to take and pay for, or to
supply to the Transmission Provider, any or all of the products defined in the Integrated
Marketplace in accordance with the provisions of the Transmission Provider's Tariff and to
satisfy all obligations under the terms and conditions of the Transmission Provider's Tariff, as
may be amended from time-to-time, filed with the Commission.
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5. The Transmission Provider and the Customer agree that this Service Agreement shall be subject
to, and shall incorporate by reference, all of the terms and conditions of the Transmission
Provider's Tariff.
6. It is understood that, in accordance with the Transmission Provider's Tariff, the Transmission
Provider may amend the terms and conditions of this Service Agreement by notifying the
Customer in writing and making the appropriate filing with the Commission.
7. The Customer represents and warrants that:
(a) At any time it has registered one or more Resources that the Customer intends to offer for
sale into the Energy and Operating Reserve Markets in accordance with procedures
specified in the Market Protocols, the participation of its Resource(s) in the Energy and
Operating Reserve Markets is not precluded under the laws or regulations of the relevant
electric retail regulatory authority, including state-approved retail tariff(s), and it either
(a) has on file with the Commission for each of such Resources market-based rate
authority and/or other Commission-approved basis for setting prices in the Energy and
Operating Reserve Markets, or (b) is exempt from the requirement to have rates for
services on file with the Commission;
(b) This Service Agreement, or any Transaction entered into pursuant to the Service
Agreement, as applicable, has been duly authorized;
(c) This Service Agreement is the legal, valid, and binding obligation of the Customer
enforceable in accordance with its terms, except as it may be rendered unenforceable by
reason of bankruptcy or other similar laws affecting creditors' rights, or general principles
of equity.
8. The Customer warrants and covenants that, during the term of the Service Agreement, the
Customer shall be in compliance with all federal, state, and local laws, rules, and regulations
related to the Customer's performance under the agreement.
9. Service under this Service Agreement shall commence on the later of the date of execution of the
Service Agreement, or such other date as it is permitted to become effective by the Commission.
Service under this Service Agreement shall terminate in accordance with Section 12 below.
10. Any notice or request made to or by either Party regarding this Service Agreement shall be made
to the representative of the other Party as indicated below:
Transmission Provider: ________________________________
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 30 of 33
Customer: ______________________________________________
11. Cancellation Rights:
If the Commission or any regulatory agency having authority over this Service Agreement
determines that any part of this Service Agreement must be changed, the Transmission Provider
shall offer to the Customer within fifteen (15) days of such determination an amended Service
Agreement reflecting such changes. In the event that the Customer does not execute such an
amendment within thirty (30) days, or longer if the Parties mutually agree to an extension, after
the Commission's action, this Service Agreement and the amended Service Agreement shall be
void.
12. Termination:
(a) The Customer may terminate service under this Service Agreement no earlier than ninety
(90) days after providing the Transmission Provider with written notice of the Customer's
intention to terminate. The Customer's provision of notice to terminate service under this
Service Agreement shall not relieve the Customer of its obligation to pay any rates,
charges, or fees due under this Service Agreement, and which are owed as of the date of
termination.
(b) The Transmission Provider may terminate service under this Service Agreement if the
Customer is in default, such default condition as defined under Section 8.1 of the SPP
Credit Policy, in accordance with the procedures specified under Section 7.4 of the
Transmission Provider’s Tariff or Section 10.5 of Attachment AE to the Transmission
Provider’s Tariff, as applicable.
13. The Customer hereby appoints the Transmission Provider as its agent for the limited purpose of
effectively transacting on the Customer's behalf in accordance with the terms and conditions of
the Transmission Provider's Tariff. The Customer agrees to pay all amounts due and chargeable
to the Customer and the Transmission Provider agrees to pay all amounts creditable to the
Customer in accordance with the terms of the Transmission Provider's Tariff.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their
respective authorized officials.
Transmission Provider: Customer: By: ______________________ By: _____________________
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 31 of 33
Dated: ______________________ Dated: _____________________ Title: _______________________ Title: _____________________
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 32 of 33
Appendix 1 to Attachment AH
MARKET PARTICIPANT INFORMATION: Requested
Change Type 1 (Add,
Modify, Terminate)
Market Participant Name 2
Market Participant Acronym 3
(4 characters)
Registered in EIR? 4 (yes/no)
Credit Customer
Name5
ASSET OWNER AND TC INFORMATION: Requested
Change Type 1 (Add,
Modify, Terminate)
Asset Owner Name 6
Asset Owner Acronym 7
(4 characters)
Registered in EIR? 8 (yes/no)
Resource Owner 9 (yes/no)
Load Serving
Entity 10(yes/no)
TRANSMISSION CUSTOMER TO ASSET OWNER RELATIONSHIPS: Requested
Change Type 1
(Add, Modify, Terminate)
Transmission Customer
(TC) Acronym 11
(4 characters)
Asset Owner
Acronym 7 (4
characters)
METER AGENT INFORMATION: Requested
Change Type 1
(Add, Modify,
Meter Agent Name 12 Meter Agent Acronym 13
(4 characters)
Registered in EIR? 14
(yes/no)
MPRR 133 Recommendation Report (ARR and RNU Edits)_MWG_RTWG_ 7/25/2013 Page 33 of 33
Terminate)
CONTACT INFORMATION: Contact Last Name Contact First
Name Contact Type15 (A,B,C)
Phone Number
(nnn) nnn-nnnn
Email Address
PROPOSED EFFECTIVE DATE16: ____________________________________
Proposed Criteria Language Revision N/A
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MWG MPRR 133 Impact Analysis.doc Page 1 of 5
PRR Number
Marketplace-PRR133
PRR Title GFA Carve Out
Impact Analysis Date 7/3/2013
Estimated Cost Impact
Approach 1 – $50,000 Approach 2 - $570,000 Cost impacts include estimated vendor and SPP costs, and are a Rough Order of Magnitude (ROM) estimate equal to +/- 50%. Vendor costs were estimated by SPP staff (If Approach 2 is approved, vendor impact assessments will be required).
Estimated Project Time Requirements
Approach 1 – 27 FTE days’ effort. The start day is TBD. The schedule depends on resource availability, environment availability, and testing dependencies. Approach 2 – 216 FTE days’ effort. The start date is TBD. The schedule depends on resource availability, environment availability, and testing dependencies. Start and completion dates are also dependent upon the vendor’s availability, and because Approach 2 uses the same resources as the three FERC-mandated post go-live projects (Regulation Compensation, Market-to-Market, and Long-Term Congestion Rights), the work on Approach 2 must be prioritized along with these FERC-mandated projects. (In order to meet the one-year post go-live FERC mandate, the work on these three projects is scheduled to begin in August of 2013.)
PRR Impact Analysis Report
MWG MPRR 133 Impact Analysis.doc Page 2 of 5
SPP Applications Impacted
EMS MOS MUI eDNA RTNET MOS MOI COS RFCALC SPD Market Portal RTLODF RTO_SS ICCP RTGEN RSS DSS RTSMGR NLS OPS1 SCADA OASIS Other MOS DB X Alstom Settlements X Accenture System
Integration XML X Centralized Modeling
Tool X Staging Database
Check off the systems that are (or may be) impacted. Include a short explanation as to why each application is (or might be) affected in this area. Approach 1 (Moderate System Impacts): Staging Database – Create one new staging database structure for the registration of GFA Asset Owners and create one new Bill Determinant to identify the GFA Carve Out transactions. Alstom Settlements System – Create software to import the new Bill Determinant into the Settlements System. Modify the Revenue Neutrality Uplift (RNU) equations to exclude the settlement of the GFA Carve Out transactions. Approach 2 (Major System Impacts): Centralized Modeling Tool - A relationship between each GFA Asset Owner and a transmission Zone, and a relationship between each Meter Data Submittal Location (MDSL) and a transmission Zone must be added to the Commercial Model. Accenture System Integration – Three new interfaces to move data from the Centralized Modeling Tool to the Settlements system must be developed. Staging Database – Develop software to move data between pre-staging and staging database tables. Create validations for transmission Zones and two new relationships. Create Bill Determinant tables for the new data.
PRR Impact Analysis Report
MWG MPRR 133 Impact Analysis.doc Page 3 of 5
Alstom Settlements System – Develop data import for two new Bill Determinants; add two new intermediate calculations (transmission Zone total charges and transmission Zone total load; add two new Settlement line calculations (GFAHrlyAmt and GFAHrlyDistAmt; make modifications to three existing Charge Types (RNU, Balance Check, Invoice Total). Other Settlement Internal Development – Change graphical user interface screens; develop Enterprise System Bus (ESB) call and replicate ESB call; modify the report control table; and change the post validation software to include the GFA Carve Out changes.
SPP Long-Term Staffing Impacts
IT Settlements Other Operations
Additional staff required: Yes No Detail each group separately: Add 1 FTE to the Congestion Hedging Group to manage the ARRs and TCRs associated with the GFA Carve Out Account.
Members Software Systems/ Processes Impacted
ICCP MUI XML OPS1 Reports RTO_SS Other
Check off the software systems that are (or may be) impacted. N/A Include a short explanation as to why each application is (or might be) affected in this area. N/A Member Processes Impacted (Under Approach 1 and 2):
PRR Impact Analysis Report
MWG MPRR 133 Impact Analysis.doc Page 4 of 5
Transmission Owners that are a party to GFA(s) eligible for GFA Carve Out must elect GFA Carve Out treatment if they want the eligible GFA(s) to be exempt from congestion and marginal losses charges. They must identify a GFA Responsible Entity for the GFA(s) eligible for GFA Carve Out. Market Participants identified as a GFA Responsible Entity must provide the Transmission Provider the information necessary to administer the GFA Carve Out. They must coordinate the GFA Carve Out Schedule data to ensure the consistency of the GFA Carve Out Schedule and must submit monthly GFA invoices and hourly details of all energy transacted under the GFA to the Transmission Provider for auditing purposes. They must also create GFA Carve Out Schedules and E-Tags (as applicable) for all energy transacted under the GFA. An entity taking firm transmission service under a GFA Carve Out will not be eligible to participate in the TCR Markets for the MW capacity associated with the GFA Carve Out.
Evaluation of Interim Solutions (e.g., manual workarounds) N/A
Comments Approach 1 Description: Market Participants will use Day-Ahead Market GFA Carve Out Schedules to offset Day-Ahead Market congestion and marginal losses charges associated with the GFA transaction. These offsets will transfer any charges/credits to the GFA Carve Out account. Any net charges/credits associated with the GFA Carve Out account will then be allocated via Revenue Neutrality Uplift. Market Participants that have GFA Carve Outs will not receive candidate ARRs for the transmission service associated with the GFAs. The candidate ARRs along with any corresponding TCRs will be included in the TCR Market using a GFA Carve Out account. Approach 2 Description: Market Participants will use Day-Ahead Market GFA Carve Out Schedules to offset Day-Ahead Market
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MWG MPRR 133 Impact Analysis.doc Page 5 of 5
congestion and marginal losses charges associated with the GFA transaction. These offsets will transfer any charges/credits to the GFA Carve Out account. Any net charges/credits associated with the GFA Carve Out account will then be allocated on a load ratio share basis to each Market Participant for all load Asset Owners it represents within the transmission Zones associated with the GFA. Market Participants that have GFA Carve Outs will not receive candidate ARRs for the transmission service associated with the GFAs. The candidate ARRs along with any corresponding TCRs will be included in the TCR Market using a GFA Carve Out account.
PRR Comments
PRR No. Marketplace-PRR133 PRR
Title GFA Carve Out
Date 6/21/2013
Submitter Name Ronald Thompson E-mail Address [email protected] Company NPPD Phone Number 402.845.5202
Comments NPPD comments are highlighted in blue. No proposed Tariff changes are included. RTWG will need to develop conforming Tariff changes to match the Protocol language.
Revised Proposed Protocol Language Revision 1. Glossary
GFA Carve Out Removal of the congestion and marginal loss charges for the amount of energy (MWh) actually transacted associated with GFAs. As defined in the SPP Tariff. GFA Carve Out Schedule As defined in the SPP Tariff. GFA Responsible Entity
As defined in the SPP Tariff.
4.2.1.1 Day-Ahead Market
Each Market Participant must offer sufficient Resources to the Day-Ahead Market to cover load plus Operating Reserve obligation to the extent the Resources are available (e.g. not on forced outage, planned outage or Reserve Shutdown).
EIS Market
Integrated Marketplace
MWG MPRR 133 NPPD Comments 6-21-2013_revised 7-8-13.docx Page 2 of 11
(1) A Market Participant’s load for purposes of this section shall be equal to the Market Participant’s maximum hourly Reported Load excluding any GFA Carve Out Bilateral Settlement Schedules for the Operating Day.
(2) A Market Participant’s daily Operating Reserve obligation shall be equal to the sum of that Market Participant’s maximum daily Regulation-Up, Regulation-Down and Contingency Reserve obligation as calculated by SPP as described in Section 4.1.2.3(3).
(3) Only Resources submitted with a Commitment Status of Market or Self may be used to satisfy this requirement.
(4) A Market Participant’s net resource capacity, for purposes of this section shall include:
(a) Offered capacity by Resources identified in 4.2.1.1(3) less the Operating Reserve obligation identified in 4.2.1.1(2); and
(b) Firm Power purchases less the Firm Power sales.
(5) Market Participants with net resource capacity, as determined in Section 4.2.1.1(4), less than 90% of the Market Participant’s maximum hourly Reported Load excluding any GFA Carve Out Bilateral Settlement Schedules for the Operating Day shall be deemed resource deficient and may be subject to sanctions as determined in Section 8.2.7.1.
(6) Resources used as the source of a GFA Carve Out must be offered, if available, with a sufficient capacity to cover the GFA Carve Out Bilateral Settlement Schedule. GFA Carve Out status is only available to the extent that the Resources are offered into the DA Market using a commit status of “Market” or “Self.” To the extent the source is external, an Import Interchange Transaction must be submitted in the DA Market with a sufficient capacity to cover the GFA Carve Out Bilateral Settlement Schedule.
4.5.3 Bilateral Settlement Schedules
Market Participants may create Bilateral Settlement Schedules for Energy and Operating Reserve obligation by registering and confirming the parameters of the agreement between buyer and seller such as the Schedule ID, Settlement Location, Reserve Zone, maximum allowable hourly quantity, market product, submitting party, auto-confirmation option and the effective & termination dates. Once this “header” information is validated and entered into the system by SPP, hourly quantities submitted reference the Schedule ID in order to be associated with all the parameters required for settlement calculations. In the event that either party no longer consents to participate in the Bilateral Settlement Schedule, or if SPP staff encounter recurring settlement dispute activity related to its usage the “header” information may be ended in advance of the original termination date effectively preventing further submittal of hourly quantities. In addition, if SPP encounters recurring settlement dispute activity relating to the use of the auto-
MWG MPRR 133 NPPD Comments 6-21-2013_revised 7-8-13.docx Page 3 of 11
confirmation option, SPP may remove that option from the header information for that Bilateral Settlement Schedule.
Market Participants may submit Bilateral Settlement Schedule quantities for Energy and Operating Reserve obligation up to four (4) days following the applicable Operating Day for the Initial settlement. New submittals and revisions to previously submitted values may be submitted up to 44 days following the applicable Operating Day to be included in the Final settlement. The submittal timeline is subject to acceleration around holidays (see Section 4.5.14). Auto-confirmation applies to only the first submittal per Operating Day and must occur prior to the cutoff for the Initial settlement. Submittals 1) for agreements not using the auto-confirmation option, 2) beyond the cutoff date for the Initial settlement or 3) which update previous submittals must all be explicitly confirmed by the submitting party and counterparty. Submittals not confirmed by both parties will not be included in any settlement execution.
Transactions related to Bilateral Settlement Schedules for Energy must specify the Settlement Location, the MW amount, the buyer, the seller and which market it applies to (DA Market or RTBM). The seller receives an increase in load obligation equal to the specified MW amount and the buyer receives a reduction in load obligation equal to the specified MW amount (the equivalent of a Resource settlement) at the specified Settlement Location.
Transactions related to Bilateral Settlement Schedules for Operating Reserve obligation must specify the buyer, the seller, the Operating Reserve product, the MW obligation transfer and the Reserve Zone within which the obligation transfer applies (Operating Reserve Bilateral Settlement Schedules only apply to Day-Ahead Market cost allocation). The seller receives an increase in Operating Reserve obligation equal to the specified MW and the buyer receives a corresponding decrease in Operating Reserve obligation within the specified Reserve Zone.
4.5.3.1 Transition Mechanism for Pre-Existing Bilateral Contracts
To the extent that Market Participants are parties to bilateral contracts entered into prior to October 18, 2012, the rules specified under Section 8.2.1 of Attachment AE to the Tariff shall apply regarding submittal of Bilateral Settlement Schedules that are associated with such bilateral contracts.
4.5.3.2 GFA Carve Out Schedules - Internal
Market Participants that have been granted GFA Carve Out must assign a GFA Responsible
Entity. TThe GFA Responsible Entity must submit GFA Carve Out sSchedules for all of the
actual energy actually transacted under the GFA in order to receive a GFA Carve Out. These
GFA Carve Out Bilateral Settlement Schedules must be submitted in accordance with the
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requirements of Section 4.5.3, as specifically modified in section 4.5.3.2. If no energy is
transacted under the GFA, then no schedule is required and no GFA Carve Out treatment will be
provided. Up to four (4) DA Market Bilateral Settlement GFA Carve Out Schedules for energy
may be required for each GFA Carve Out transaction:
1. GFA Carve Out Bilateral Settlement Schedule #1 a. Seller: MP responsible for the source b. Buyer: GFA Responsible Entity c. Settlement Location: Source Settlement Location of the GFA transmission service
2. GFA Carve Out Bilateral Settlement Schedule #2 a. Seller: GFA Responsible Entity b. Buyer: GFA Carve Out account c. Settlement Location: Source Settlement Location of the GFA transmission service
3. GFA Carve Out Bilateral Settlement Schedule #3 a. Seller: GFA Carve Out account b. Buyer: GFA Responsible Entity c. Settlement Location: Sink Settlement Location of the GFA transmission service
4. GFA Carve Out Bilateral Settlement Schedule #4 a. Seller: GFA Responsible Entity b. Buyer: MP responsible for the sink c. Settlement Location: Sink Settlement Location of the GFA transmission service
If the Market Participant that is responsible for the source is the same as the GFA Responsible Entity, then #1 above does not apply. If the Market Participant that is responsible for the sink is the same as the GFA Responsible Entity, then #4 above does not apply. The seller receives an increase in load obligation equal to the specified MW amount and the buyer receives a reduction in load obligation equal to the transacted MW amount at the specified Settlement Location. These Bilateral Settlement Schedules will be settled at DA Market prices.
The GFA Responsible Entity is responsible to ensure the consistency of the GFA Carve Out
Bilateral Settlement Schedules, and shall submit monthly GFA invoices and hourly details of all
energy actually transacted under the GFA to the Transmission Provider for auditing purposes.
The Transmission Provider will compare all GFA Carve Out Schedules to the actual hourly
energy transactions and may request the GFA Responsible Entity to explain any deviations.
Deviations may be reported to the Commission’s Office of Enforcement, or its successor
organization.
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The Transmission Provider shall publish a quarterly report listing the costs allocated to the market caused by the associated GFA Carve Outs. The report should also provide hourly and monthly deviations associated with the GFA Carve Out schedules.
4.5.3.3 GFA Carve Out Schedules - External
In addition to 4.5.3.2, if the source or sink of the energy receiving GFA Carve Out treatment is external to the SPP BA, a Fixed Interchange Transaction must be submitted and confirmed in the DA Market with sufficient capacity to cover the GFA Carve Out Bilateral Settlement Schedule. The GFA Responsible Entity will ensure the values of the GFA Carve Out Schedules are equal to the lesser of the Day-Ahead cleared, energy actually transacted under the GFA or the Real-Time hourly Interchange Transaction MW volume.
4.5.3.4 GFA Carve Out Uplift
GFA Carve Out Schedules result in removal of the energy, congestion, and marginal losses for the transaction from settlement statements. SPP will capture the congestion charge and marginal loss related to the GFA Carve Outs. These charges will be offset by the ARR/TCR settlement that would have been claimed under the normal ARR/TCR process and the distribution of the Marginal Loss Overcollection funds. The net resulting amount will be included in the GFA Carve Out Uplift Distribution Amount under Section 4.5.12. The net resulting amount will be included in Revenue Neutrality Uplift under Section 4.5.13.
4.5.8.19 Day-Ahead Over-Collected Losses Distribution Amount
(1) The Marginal Losses Component of the DA Market LMP that results from the economic market solution which considers the cost of marginal losses, congestion costs and incremental Energy costs creates an over collection related to payment for losses (“DA Market Over-Collected Losses”) that must be refunded. A DA Market credit or charge1 is calculated for each hour at each Settlement Location for which an Asset Owner has a DA Market Energy withdrawal that contributed positively to the over collection. Each Asset Owner’s contribution to the DA Market Over-Collected Losses is calculated based upon a Loss Pool that is dynamically defined by the Asset Owner’s transactional activity. A loss rebate factor is calculated for each Asset Owner and withdrawal Settlement Location as the
1 Note that this charge type will almost always produce a credit. The charge is included here for the rare occasion when a charge may be produced as a result of a data error and/or a resettlement.
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difference between the Marginal Loss Component at a withdrawal Settlement Location in the Asset Owner’s Loss Pool and the injection weighted average Marginal Loss Component for the Asset Owner’s Loss Pool, multiplied by the Asset Owner’s share of the net withdrawal (calculated excluding cleared Virtual Bids and cleared Virtual Offers) at that Settlement Location. The injection weighted average MLC for the Asset Owner’s Loss Pool is calculated assuming that injection in the Loss Pool first serves withdrawal in the Loss Pool and then goes to meet the withdrawal in Loss Pools which do not have sufficient injections to meet all withdrawals. The loss rebate factor (positive value only, negative values are ignored) is a measure of the Asset Owner’s payment for losses on a marginal basis at each Settlement Location. The loss rebate factors are then normalized to allocate a pro-rata portion of the total over collection in the hour to Asset Owners by Settlement Location. Asset Owners with GFA Carve Out energy transactions are not qualified to receive these loss rebates associated with the GFA Carve Out transactions. The amount is calculated as follows:
4.5.12 Contract Loss Amount
The GFA Transmission Owner will, in writing, inform SPP of the loss factor identified under the terms of any contracts being accorded GFA Carve Out treatment when the GFA is registered. SPP will use the loss factor multiplied by the quantity delivered each hour as identified in the Carve Out GFA Schedule, multiplied by the DA LMP at the source of the GFA. These monies will be included as a charge on the market Settlement Statement to the GFA Responsible Entity within five business days. The monies collected through this charge will reduce the amount of monies to be included in the Revenue Neutrality Uplift calculation for the Operating Day related to the SPP invoicing of the costs.
4.5.132 Revenue Neutrality Uplift Distribution Amount
(1) A charge or credit will be calculated at each Settlement Location for each Asset Owner for each hour in order for SPP to remain revenue neutral. Contributors to revenue non-neutrality include:
(a) Rounding errors;
(b) Inadvertent Interchange (as calculated as shown in equation b.3 below);
(c) Joint Operating Agreement Charges/Credits;
(d) RTBM congestion (as calculated as shown in equation b.4 below);
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(e) RTBM Regulation Deployment Adjustment;
(f) GFA Carve Out account balance; GFA Carve Out Schedules from both the source and load Market Participants result in removal of the energy, congestion, and marginal losses for the transaction from their respective settlement statements. SPP will capture the congestion charge and marginal loss charge related to the GFA with the GFA Carve Out actual transaction. These charges will be offset by the ARR/TCR settlement that would have been claimed under the normal ARR/TCR process and the distribution of the Marginal Loss Overcollection funds.
(g) GFA Carve Out Contract Loss Amount Schedule Losses charges as described under Section 4.5.12.
(f)(h) Make-Whole payments for Out-of-Merit Energy; and
(g)(i) Miscellaneous Charges/Credits.
The amount will be determined by multiplying the Asset Owner hourly determinant by a daily Revenue Neutrality Uplift (RNU) rate. The Asset Owner hourly determinant is equal to the sum that Asset Owner’s actual generation MWh, actual load MWh, actual Interchange Transaction MWh, DA Market cleared Virtual Offer MWh and DA Market cleared Virtual Bid MWh for the Hour, where all of these values are assumed to be positive values.
5.1.1 Transmission Service Verification
In order for Eligible Entities to obtain candidate ARRs, SPP must first verify existing transmission service entitlements, including transmission service entitlements which have been renewed in accordance with rollover rights since their initial term. In order to qualify for candidate ARRs in a particular month and/or season, an Eligible Entity’s transmission service must span the entire monthly or seasonal period within the applicable year. SPP will verify Eligible Entity existing transmission service entitlements as follows:
(1) For Eligible Entities taking Network Integration Transmission Service (NITS) and/or Firm Point-To-Point Transmission Service (FPTP) under the SPP Tariff:
(a) SPP will obtain source, sink and Reservation Reserved Capacity information from the SPP OASIS for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period;
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(b) For a TSR with a source inside the SPP Market that is not a specific Resource or Resource Hub, the load Settlement Location that most closely corresponds to the source on the reservation will be utilized as the source for candidate ARRs;
(c) For a TSR with a source outside of the SPP Market, the interface associated with the Balancing Authority of the source will be utilized as the source;
(d) For a TSR with a sink outside of the SPP Market, the interface associated with the Balancing Authority of the sink will be utilized as the sink;
(e) SPP will provide this information to each Eligible Entity for verification;
(f) Eligible Entities will notify SPP within two (2) weeks following receipt of this information identifying and correcting inaccurate data. Otherwise, the SPP provided data will be considered verified.
(2) For Eligible Entities taking GFA service without Carve Out status:
(a) If the transmission customer under the GFA desires to nominate ARRs associated with the GFA sources and sinks identified in the Grandfathered Agreement, the GFA Parties must register such GFA with SPP and provide sources, sinks and Reservation Reserved Capacity reserved capacity information. SPP will obtain source, sink and Reservation Capacityreserved capacity information from the GFA registration for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period;
(b) For a GFA with a source inside the SPP Market that is not a specific Resource or Resource Hub, the load Settlement Location that most closely corresponds to the source on the reservation will be utilized as the source for candidate ARRs;
(c) For a GFA with a source outside of the SPP Market, the interface associated with the Balancing Authority of the source will be utilized as the source for candidate ARRs;
(d) For a GFA with a sink outside of the SPP Market, the interface associated with the Balancing Authority of the sink will be utilized as the sink;
(e) In addition, the parties to the GFA must agree that the transmission customer under the GFA is eligible to nominate the ARRs associated with the GFA and both parties must confirm such with SPP. To the extent that the transmission service specified in the GFA is identified as the equivalent of SPP NITS, the transmission customer under the GFA must provide the historical non-coincident
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annual peak loads (“GFA Annual Peak Load”) being served under the GFA for the previous three years since February 1, 2007.
(3) For Eligible Eentities taking GFA service that haves been granted GFA Carve Out statustreatment:
Market Participants that have been granted GFAs with GFA Carve Out status willare not eligible not receivefor candidate ARRs for the transmission service associated with the GFA, nor will any other Market Participant associated with the GFA Carve Out;
(a) If the Transmission Owner under the GFA desires GFA Carve Out status associated with the source and sink identified in the GFA, The parties to the GFA must register suchthe GFA with SPP, identify the GFA Responsible Entity, and provide source, sink and Reservation Capacityreserved capacity information. SPP will obtain source, sink and Reservation Capacityreserved capacity information from the GFA registration for each monthly and seasonal period for the applicable year in which the transmission service spans the entire period;
(b) To the extent that the transmission service specified in the GFA Carve Out is identified as the equivalent of SPP NITS, the transmission customer under the GFA must provide the historical non-coincident annual peak loads (“GFA Annual Peak Load”) being served under the GFA for the previous three years since February 1, 2007.
5.2.3 Simultaneous Feasibility
A Simultaneous Feasibility Test (SFT) analysis is performed in each round to ensure that the nominated candidate ARRs, with nominated candidate ARR MW modeled as generation injection at the source and a corresponding load withdrawal at the sink, do not violate any normal transmission line thermal ratings under normal system conditions and do not violate short-term Emergency transmission line thermal ratings following a single contingency (N-1 contingency analysis). The SFT is performed consistent with the transmission system loading analysis that is performed as part the Security Constrained Economic Dispatch process in the DA Market and includes consideration of the impact of Parallel Flow.
(1) The SPP Transmission System topology used in the SFT is the most up-to-date Network Model for all allocation periods, updated for forecasted transmission topology changes including planned maintenance outages.
(a) For withdrawals at sink Settlement Locations containing more than one PNode, SPP will distribute the Settlement Location withdrawal down to the PNode level
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using load distribution percentages from the peak hour of the corresponding most recent historical period (i.e. June, July, August, September, Fall, Winter and Spring). These load distribution percentages are calculated using the methodology described under Section 4.1.2.1.6.
(b) For injections at Market Hubs, SPP will distribute the hub injection down to the PNode level on a pro-rata basis using the weighting factors defined when the hub is created.
(c) For GFA Carve Outs, an injection at the source and a corresponding load withdrawal at the sink will be included in the Annual ARR Allocation Process and will be subject to SFT. The capacity used in the allocation will be the maximum allowable nomination as defined in section 5.2.2.
5.3.2 Annual TCR Auction Process
TCRs are auctioned in a single-round process for each month and season using the SPP Residual Transmission System Capability as defined under Section 5.2.3 as follows:
(1) 100% of the SPP Residual Transmission System Capability is made available for the month of June, 90% of the SPP Residual Transmission System Capability is made available for the July-September period and 60% of the SPP Residual Transmission System Capability is made available for the Fall, Winter and Spring seasons;
(a) TCR Bids of the Self-Convert Type may be submitted for each source to sink pair that the Market Participant desires to convert the associated ARRs into TCRs. The Self-Convert Type option will convert ARRs associated with the specified source to sink pair into the TCR MW specified subject to simultaneous feasibility.
(b) Only Eligible Entities holding ARRs may submit a Self-Convert TCR Bid.
(c) All awarded ARRs from section 5.2.3(1)(c) that resulted from GFA Carve Outs will be automatically submitted to the TCR auction as self-convert TCR Bids.
(c)(d) The Self-Convert TCR Bid must specify the same source and sink as the associated ARR and the TCR MW must be less than or equal to the associated ARR MW.
5.4 Monthly ARR Allocation Process
Eligible Entities with remaining candidate ARR capacities from the Annual ARR Allocation Process along with firm transmission service that has been confirmed following completion of the Annual TCR Auction Process and prior to the next Annual ARR Verification Process or with
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firm transmission service confirmed prior to the Annual ARR Verification Process that includes a partial season or transmission service that is made available due to upgrades are eligible to nominate candidate ARRs associated with such services. Any remaining candidate ARR capacities from the Annual ARR Allocation Process related to GFA Carve Outs will be included in the Monthly ARR Allocation Process. To the extent that the Eligible Entity’s firm transmission service term extends beyond the current Annual ARR Allocation Process period, such remaining service will be included in the next Annual ARR Verification Process. The following rules apply to verification of transmission service for conversion to incremental candidate ARRs.
5.5 Monthly TCR Auction Processes
The Monthly TCR Auction Process is the mechanism through which Market Participants may obtain TCRs over and above those obtained in the Annual TCR Auction Process through submission of TCR Bids to purchase TCRs and/or through conversion of remaining ARRs awarded in the Annual ARR Allocation Process and/or ARRs awarded in the Monthly ARR Allocation Process into TCRs through Self-Conversion. All awarded monthly ARRs that resulted from GFA Carve Outs will be automatically submitted to the TCR auction as self-convert TCR Bids for the maximum capacity allowable consistent with section 5.5.2. Market Participants may also offer for sale TCRs awarded in the Annual TCR Auction Process. 100% of the SPP Transmission System capability is made available during the Monthly TCR Auction Process. The remaining TCRs for the months of July through September are auctioned in a single-round process. The remaining TCRs for the months of October through May are auctioned in a two-round process. No later than three (3) Business Days prior the start of the Monthly TCR Auction Process, SPP will post the transmission system network topology data, along with corresponding Parallel Flow and transmission line outage assumptions, that SPP will use in the upcoming Monthly TCR Auction Process for use by Market Participants in developing their TCR Bid, TCR Offer and/or TCR self-conversion strategies. Exhibit 5-6 provides a representative timeline of the single-round and two-round Monthly TCR Auction Processes.
Proposed Tariff Language Revision RTWG will need to develop conforming Tariff changes to match the Protocols.
1
Kaye McCarty
From: Carl MonroeSent: Wednesday, July 17, 2013 2:43 PMTo: Kaye McCartySubject: FW: No Vote on Allocation of Carve-Out Uplift
For the recommendation ‐‐‐‐‐Original Message‐‐‐‐‐ From: COLLINS, DOUGLAS L [mailto:[email protected]] Sent: Wednesday, July 17, 2013 2:37 PM To: Carl Monroe Cc: Yanovich, Rick Subject: No Vote on Allocation of Carve‐Out Uplift Carl, OPPD's no vote on the Zonal Allocation of Carve‐Out uplift is mainly because we don't feel FERC will approve the plan and it will cause further last minute filings. I also think that it is fair for small customers with fixed price contracts to be exempted from the market model. From what I've seen so far, it doesn't seem like the carve‐outs represent many small customers. Doug ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ This e‐mail contains Omaha Public Power District's confidential and proprietary information and is for use only by the intended recipient. Unless explicitly stated otherwise, this e‐mail is not a contract offer, amendment, or acceptance. If you are not the intended recipient you are notified that disclosing, copying, distributing or taking any action in reliance on the contents of this information is strictly prohibited.
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Southwest Power Pool, Inc.
MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors
July 29-30, 2013
Withdrawal of PRC-006-SPP-1
Organizational Roster The following members represent the System Protection and Control Working Group:
Rick Gurley (Chairman), AEP Lynn Schroeder, Westar Shawn Jacobs, OG&E Heidt Melson, SPS Louis Guidry, CLECO Ken Zellefrow, CUS
Matthew Thykkuttathil, Sunflower Brent Carr, AECC Bud Averill, GRDA Tom Miller, ITC Holdings Steve Wadas, NPPD
The following members represent the Regional Compliance Working Group:
Jennifer Flandermeyer (Chairman), KCP&L Tony Eddleman, NPPD John Allen (Vice-Chairman), CUS Greg Froehling, Rayburn Country Louis Guidry, CLECO Bo Jones, Westar Bryan Kauffman, SPS Chris Lang, GSEC Robert McClanahan, AECC Fred Meyer, EDE Caleb Muckala, WFEC Mike Murray, INDN Thad Ness, AEP Doug Peterchuck, OPPD John Rhea, OG&E Eric Ruskamp, LES Lindsay Shepard, Sunflower
Background Considering that PRC-024-1 has been approved by NERC (May 2013) and has been filed with FERC, the SPP Under-Frequency Load Shedding Standard Drafting Team (UFLS SDT) has reconsidered the benefit of the SPP Regional Standard (PRC-006-SPP-1).
One of the major benefits of the SPP Regional Standard was to involve the Generator Owners in the UFLS plan. PRC-024-1 requires the Generator Owners to coordinate their trip settings with SPP and it requires them to follow the underfrequency and overfrequency graphs that are attached to the Standard or provide evidence of equipment limitations. The SPP UFLS SDT has always understood the importance of including the Generator Owners in the UFLS plan, considering that the UFLS program is designed to activate when there is a generation-load mismatch. The enforcement of PRC-024-1 will require the Generator Owners to participate in the UFLS program and to not negatively impact a UFLS event by tripping offline during a frequency excursion.
The current draft of the SPP Regional Standard was approved by the SPP stakeholders in October, 2011. Since then, the drafts of PRC-024-1 have changed throughout the stakeholder process. Because of this, there is a difference between the generator trip zones that are required in the SPP Regional Standard versus PRC-024-1. If the SPP Regional Standard is not withdrawn, a modification will need to be made so that the generator trip zone in PRC-006-SPP-1 does not conflict with the NERC Standard.
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All of the requirements that are included in the SPP Regional Standard have been included in the UFLS plan that will be adopted by SPP as the Planning Coordinator, which will be enforced by NERC through Regional Entities (SPP, MRO and SERC) through NERC PRC-006-1. Therefore, withdrawal of the SPP Regional Standard will not affect the reliability to the SPP system.
Working Group Reviews The System Protection and Control Working Group met and discussed the removal of PRC-006-SPP-1. The SPCWG approved the withdrawal unanimously. The Regional Compliance Working Group has also reviewed the NERC standards, SPP Regional Standard and UFLS Plan recommending that the regional standard will not be necessary to achieve the desired outcome. The diligence and work from the SPCWG will not be lost and is representative in the compliance response to the NERC standard effective 10-1-13. The RCWG voted by majority to withdraw the request for approval of the regional standard from FERC.
Recommendation Recommend that the BOD provide an advisory vote to the SPP RE that PRC-006-SPP-1 be withdrawn from FERC consideration as a Regional Standard due to the fact that NERC PRC-024-1 has been approved by NERC and is waiting on FERC approval.
Approved: MOPC July 16-17, 2013
Passed with modifications with one abstention-ITC Great Plains
SPCWG 6/12/13
Approved unanimously
RCWG 6/25/13
Majority approval
Action Requested: Provide advisory vote.
1
Kaye McCarty
From: Carl MonroeSent: Wednesday, July 17, 2013 2:24 PMTo: Kaye McCartySubject: FW: My abstention on the last vote
FYI
From: Brett Kruse [mailto:[email protected]] Sent: Wednesday, July 17, 2013 2:23 PM To: Carl Monroe; Janssen, Rob Subject: My abstention on the last vote Was just for Calpine, not for Hunt (I had forgotten about carrying Bill’s proxy). Hunt will vote “for”.
Brett Kruse Vice President, Market Design Calpine Corporation (NYSE: CPN) Office (713) 830‐8732 Cell (713) 825‐3418 [email protected]
CONFIDENTIALITY NOTICE:The information in this e-mail may be confidential and/or privileged and protected by work product immunity or other legal rules. No confidentiality or privilege is waived or lost by mistransmission. If you are not the intended recipient or an authorized representative of the intended recipient, you are hereby notified that any review, dissemination, or copying of this e-mail and its attachments, if any, or the information contained herein is prohibited. If you have received this e-mail in error, please immediately notify the sender by return e-mail and delete this e-mail from your computer system. Thank you.
1
Kaye McCarty
From: Carl MonroeSent: Wednesday, July 17, 2013 2:44 PMTo: Kaye McCartySubject: FW: UFLS Plan No Vote
For the recommendation report... Carl ‐‐‐‐‐Original Message‐‐‐‐‐ From: COLLINS, DOUGLAS L [mailto:[email protected]] Sent: Wednesday, July 17, 2013 2:27 PM To: Carl Monroe Cc: Yanovich, Rick; Peterchuck, Douglas Subject: UFLS Plan No Vote Carl, OPPD is afraid that SPP won't change anything about the plan now that it has been approved by MOPC. The RCWG, SPCWG or TWG will feel handcuffed if they want to change the plan when they do their reviews. Doug OPPD 402‐514‐1028 ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ This e‐mail contains Omaha Public Power District's confidential and proprietary information and is for use only by the intended recipient. Unless explicitly stated otherwise, this e‐mail is not a contract offer, amendment, or acceptance. If you are not the intended recipient you are notified that disclosing, copying, distributing or taking any action in reliance on the contents of this information is strictly prohibited.
Southwest Power Pool Regional State Committee, Board of Directors/Members Committee &
Regional Entity Trustees Future Meeting Dates & Locations
2013
RET/RSC/BOD October 28-29 Little Rock (Annual Meeting of Members) ** BOD December 10 Dallas
2014
RET/RSC/BOD January 27-28 Austin RET/RSC/BOD April 28-29 Oklahoma City *BOD June 9-10 Little Rock RET/RSC/BOD July 28-29 Omaha RET/RSC/BOD October 27-28 Little Rock (Annual Meeting of Members) ** BOD December 9 Dallas
2015
RET/RSC/BOD January 26-27 Dallas RET/RSC/BOD April 27-28 Tulsa *BOD June 8-9 Little Rock RET/RSC/BOD July 27-28 Kansas City RET/RSC/BOD October 26-27 Little Rock (Annual Meeting of Members) **BOD December 8 Dallas
The RET/RSC/BOD meetings are Mon/Tues with the RET meeting on Monday morning, the RSC meeting on Monday afternoon, the BOD/Members Committee meeting on Tuesday. * The June BOD meeting is for educational purposes. There will be no RSC of RET meetings in conjunction with this meeting. ** The December BOD meeting is intended to be a one day in and out meeting for administrative purposes. There will be no RSC or RET meetings in conjunction with this meeting.