Omaha, Nebraska J - Southwest Power Pool

Southwest Power Pool BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Embassy Suites Omaha-Downtown/Old Market – Omaha, Nebraska July 29, 2014

- Summary of Action Items -

1. Approved Consent Agenda Items:

a. Approved April 29 and June 9 Minutes (as amended)

b. Markets and Operations Policy Committee i. MWG

1. MPRR173 2. MPRR178 3. MPRR183 4. MPRR190

ii. RTWG 1. TRR125 2. TRR126 3. TRR127 4. TRR133

iii. TWG 1. CRR-013

iv. SPCWG 1. Relay Misoperations Paper

v. Staff 1. Cost Tracking Recommendation 2. Legacy Project Baseline Cost Estimates 3. RE-evaluation of Chamber Springs-Farmington 4. Modification of Cowskin Hoover NTC

c. Strategic Planning Committee Recommendation Aggregate Study Competition Component Compliance

2. Approved to: 1. Suspend all work on current ECC initiative. 2. Staff directed for ECC, by October Meetings, to provide:

a. Best back of envelope cost benefit analysis b. Scoping a detailed cost benefit analysis

3. Work with Alstom and other Alstom customers for this functionality to be included in future Market Clearing Engine software.

4. Continue working with Alstom to understand the impact of ECC functionality on existing MCEs.

3. Approved the adoption of the Strategic Plan.

4. Approved the revised recommendation of the SPCTF on Order 1000 to extend the RFP response time window associated with Competitive Bidding Cost Estimation proposals from 90 to 180 days, unless the SPP Staff uses its discretion to reduce the response time window to no less than 90 days based on collaboration with Stakeholders.

5. Approved the Markets and Operations Policy Committee recommendation regarding CRR-012, Criteria Recommendation for Capacity Accreditation of Wind and Solar Resources.

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6. Approved the Benefit Metrics: • Approve all five of the recommended metrics based on the MOPC recommendations as

augmented by the ESWG recommendations for the two that the MOPC did not approve. The recommendations for treatment of Public Policy projects would be applied from here forward.

• Acknowledge that the R Plan is a project that provides economic and reliability benefits and not label it as a Public Policy project.

• These ten metrics be provided to the RARTF to be used as effectively as possible in the RCAR process to drive equitable solutions for those zones with deficient benefits.

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MINUTES NO. 159


Embassy Suites Omaha-Downtown/Old Market – Omaha, Nebraska July 29, 2014

Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 8:02 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. Mike Deggendorf, Kansas City Power and Light Mr. Mo Doghman, Omaha Public Power District Mr. Jim Eckelberger, director Mr. Kelly Harrison, Westar Energy 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. Jake Langthorn, proxy for Phil Crissup, Oklahoma Gas and Electric Mr. Josh Martin, director Mr. Dave Osburn, Oklahoma Municipal Power Authority 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 119 persons in attendance either in person or via phone representing 29 members (Attendance List - Attachment 1). Mr. Nick Brown reported proxies and a quorum was declared (Proxies – Attachment #2) Mr. Eckelberger introduced Paul Sukut the new CEO and General Manager of Basin Electric; Manager of the Upper Great Plains Region of WAPA, Bob Harrison; and the NPPD Board Members attending the meeting, Ken Kunze, Tom Hoff, Jerry Chlopek, Fred Christensen, and Virg Froehlich. Agenda Item 2 – Board Reports

President’s Report Mr. Nick Brown provided the President’s Report (President’s Report – Attachment 3 and 4). He began by thanking everyone for all their thoughts, kind words, and support during his illness and recovery. Mr. Brown started by discussing the metrics and the importance of providing the information so that it is part of the corporate record. He asked Mr. Carl Monroe to discuss the Metrics in a bit more detail. When the

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SPP Board of Directors/Members Committee Minutes July 29, 2014 Integrated Marketplace (IM) was implemented it changed the way we will look at the market activity. With these changes there will be new and additional statistics that will be collected. The staff would like to propose a new set of metrics and have a draft to present to the Board and Members Committee (MC) at the October meeting. Ms. Phyllis Bernard had a question about how much money is moving through the market and wondered if that could be added to the metrics. Mr. Brown followed up by saying the markets are performing in an extraordinary fashion. At the April Board meeting the Board and Members Committee recognized the success of the staff for bringing the Integrated Marketplace in on budget and on time and on behalf of the entire staff thanked all for the additional financial recognition. The staff level was discussed and it is forecasted that we will be below by 15 at the end of the year. There have been numerous retirements in several senior level positions. Mr. Jim Eckelberger reported that the Strategic Planning Committee (SPC) is building a task force to develop enhancements and improvements necessary to ensure a structured and transparent process under which the impact of adding prospective new members will be disclosed to existing stakeholders prior to agreements being finalized. The task force is expected to conclude its work by October in time for a recommendation to the SPC and ultimately the Board and Members Committee. Mr. Eckelberger shared that he received a letter from the Chairman of MISO stating they would like to work with SPP on seams. It speaks to well-intended efforts to try to do something better than where we have been in the past. Regional Entity Trustees Report Mr. John Meyer provided the Regional Entity (RE) Trustees Report (RE Trustees Report - Attachment 5). He provided an update on the Bulk Electric System Definition:

• New BES definition went into effect on 7/1/14 • BESNet tool open for submitting Self-Determinations and Exception Requests • Through July 15, SPP RE has processed four requests • Exception Requests submitted between July 1 and September 1 will be considered for

Compliance purposes as received on July 1

SPP RE Regional Events for the second quarter, there were three Category 1 (least severe) events analyzed. There were a total of 16 events all rated Category 0 and Category 1. At the stakeholder’s request the Trustees voted to extend the RE Trustee meetings into the afternoon on Mondays to try to accommodate the ability to have more reports from our NERC representatives and longer outreach discussion on important topics. Decision making and voting items will be completed before noon to accommodate the individuals that will need to attend the RSC meeting in the afternoon. Regional State Committee Report Commissioner Donna Nelson reported on the Regional State Committee (RSC) and the annual retreat that was held in Omaha on Sunday through Monday morning. The agenda items covered at the retreat included:

• The proposed EPA 111(d) rule • SPP capacity margin requirements • An explanation of how a transmission project’s costs are recovered through rates • An update on Order 1000 implementation in SPP • A history of the highway/byway cost allocation method • An overview of the transmission planning process • Benefit metrics and planning

It was an intense and informative retreat with a lot of good information. The RSC voted to modify the make-up of the Regional Allocation Review Task Force (RARTF). It was also voted to add an additional RSC member and an additional company member to the RARTF in order to ensure diversity in the group.

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SPP Board of Directors/Members Committee Minutes July 29, 2014 The RSC also discussed:

• Process for integrating new members into SPP • Plans for Cost Allocation Working Group (CAWG) and Capacity Margin Task Force • An update on seams dockets at FERC and an update from the Seams Project Task Force • A discussion about sub-synchronous resonance • Frequency and effectiveness of the RSC meetings

It was decided that the RSC will have monthly meetings beginning in August on the last Monday of the month. Federal Energy Regulatory Commission Report Mr. Patrick Clarey provided an update on recent FERC activities. In May, the DC Circuit Court of Appeals vacated FERC's final rule on demand response compensation in organized wholesale energy markets. Last month, FERC announced that it will ask the full Court to rehear the May 23 order, but will only seek review of the ruling that FERC lacked jurisdiction over demand response and not its decision to vacate FERC policies on compensation for demand response.

In June FERC conditionally accepted the CAISO proposal to implement an Energy Imbalance Market that will allow neighboring balancing authorities to participate in its real-time market for imbalance energy. Finally, in June FERC initiated a proceeding including a series of workshops to evaluate issues regarding price formation in the energy and ancillary services markets operated by RTOs/ISOs. The first workshop will be held on September 8 at the Commission. On July 15, the Senate voted to confirm Cheryl LaFleur and Norman Bay as Commissioners. Both are expected to be sworn in within the next few weeks. FERC Commissioners and Mr. Norman Bay will testify before the House Energy and Commerce Subcommittee regarding FERC's perspectives on EPA Rule 111(d). Oversight Committee Report Mr. Josh Martin presented the Oversight Committee (OC) Report. The Committee met in Little Rock in June. The Committee heard quarterly reports from Internal Audit, Compliance, and Market Monitoring staff.

• Internal Audit continues its regular audits. The staff has been working with our new controls auditors, KPMG, as they initiate their work at SPP.

• A Compliance Forum was held in June in Little Rock. These events continue to be well-attended. The next Forum will be in Oklahoma City in October. The department is developing metrics specifically focused on cyber security – these will be reported to the Oversight Committee on a regular basis, but in executive session.

• The Market Monitoring Unit staff remains engaged in the Integrated Marketplace, reviewing and further refining the various new metrics that have been developed to monitor the new markets. FERC engagement has increased, but is more focused on education for the new markets than concerns at this point.

In addition, each group provided an overview of its strategic focus/budget plans for 2015. All three groups were asked and reported that current staffing levels are adequate for moving forward. The Committee received an updated review of its role in the Order 1000 process. There will be another report in September, and before so if needed. We do ask that if anyone has suggestions for applicants for the Industry Expert Pool, please refer them to the SPP website for the details and paperwork. Industry Expert Pool candidates shall have documented expertise on file with the Transmission Provider in one or more of the following areas:

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SPP Board of Directors/Members Committee Minutes July 29, 2014

1. Electric transmission engineering design 2. Electric transmission project management and construction 3. Electric transmission operations 4. Electric transmission rate design and analysis 5. Electric transmission finance

The Oversight Committee’s next scheduled meeting is September 25 in Chicago. Human Resources Committee Report Mr. Julian Brix provided the Human Resources Committee (HRC) Report (Human Resource Committee Report - Attachment 6). The 2013 Performance Compensation Plan Process was reviewed. The 401(k) investment manager review process was discussed. The committee voted to issue an RFP for investment manager services, the committee will conduct interviews and select a manager at the September 10 meeting. The current 2014 headcount was discussed along with turnover. It was noted that 6% of the SPP workforce is within five years of retirement age. The average length of service for SPP employees is 6.5 years, the average age of employees is 42, and 55% of the employees have five years or less of service with SPP. SPP employees are taking advantage of the training provided and the new wellness program that was started in January. Human Resources staff conducted a Strengths, Weaknesses, Opportunities, and Threats analysis (SWOT) of its department and programs. The staff identified solutions and strategies and how those align with SPP corporate goals. The next two meetings will take place on September 10 in Little Rock and October 22 in Chicago. Corporate Governance Committee Report Ms. Stacy Duckett provided the Corporate Governance Committee (CGC) Report. The notice for candidates for the Members Committee positions has been distributed; several candidates have been submitted, but we will continue to take nominations until August 11. They should be directed to Stacy Duckett. The committee will set the slate at the end of August for the October elections at the Annual Meeting of Members. FERC recently approved some revisions to the Standards of Conduct rules on investments. We have considered these in the past, but FERC has now approved them on a single RTO basis, so we will discuss whether SPP will make another filing. Finance Committee Report Mr. Harry Skilton presented the Finance Committee Report (FC Report – Attachment 7). Items discussed at the last meeting were a review of the Director and Officer insurance and Gap Period Controls Audit. The Internal Audit conducted the gap period audit and did a thorough job. They did not indicate any gaps were found. A summary of the 2015 budget indicated an administrative fee forecast of 43.1 cents/MWh in 2015 and 36.5 cents/MWh in 2016. SPP management is addressing expense levels through the remainder of 2014 in an effort to return to budget levels and the FC is evaluating opportunities to smooth forecast rates going forward. After much discussion Mr. Eckelberger expressed that we cannot exceed the current .39 cents cap in the Tariff. He provided the following challenges:

1) How is the FC and the staff going to do their best to make the budget come in under so we are not carrying forward costs

2) To set goals in future years that are specific about how we are going to manage manpower and resources to get the best value with the least costs

3) Find a way for the Lean program to become standard thinking throughout the organization 4) Look at the forecasted projects and put them on hold

Management is considering these and other options. Agenda Item 3 – Consent Agenda Mr. Eckelberger presented the following Consent Agenda items for approval (Consent Agenda – Attachment 8). Before taking a vote of the Consent Agenda Mr. Eckelberger requested that item

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SPP Board of Directors/Members Committee Minutes July 29, 2014 Strategic Planning Committee recommendation concerning the RFP Response Time Extension be pulled from the voting and said he had some questions concerning some others. He would like to see the list for the original cost estimates back in the file. Ms. Terri Gallup said that SPP does maintain a list of the costs for historical purposes and they can be added.

Jeff Knottek noted for the June meeting minutes that City Utilities of Springfield abstained on Action Item 2. Mr. Eckelberger said the minutes will be corrected to show this. Mr. Larry Altenbaumer made a motion to approve the updated consent agenda and Mr. Josh Martin seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Agenda Item 4 – Staff Reports

Integrated Marketplace Mr. Bruce Rew provided an update on the Integrated Marketplace (Integrated Marketplace – Attachment 9). The Integrated Marketplace continues to perform well and there is high market participant engagement. The systems are performing well and we have gotten through some challenges. There are three improvements:

• Project Pinnacle • Operational review of data • SPP working on improvements

In summary the overall market has worked well, financial savings is being achieved, and there is continuous improvement. Project Pinnacle Ms. Barbara Sugg reported on the Project Pinnacle (Project Pinnacle – Attachment 10). A quick rundown of what is ahead.

• Market-to-Market (on schedule to launch March 1, 2015) • Regulation Compensation (on schedule to launch on 3/1/15 • Long-Term Congestion Rights (Compliance filing to be filed by 7/30/14) • Pseudo-Tie Out (Launched 6/12/14) • Environment Build-Out (On schedule to begin MP connectivity testing with MTE on 6/2/14) • Live Track (Post-Launch Efforts)

o Ongoing support and development efforts o Deployed over 150 releases into PROD since launch o Minimal impact to customers o No unplanned service outages

• Enhanced Combined Cycle (Target go-live on 11/1/15) There was considerable discussion concerning the issue of the budget increase with the EEC project. Mr. Rob Janssen made the following points:

• ECC Project was agreed-upon as part of the approval of Integrated Marketplace by SPP Membership

• As Staff has indicated previously, ECC Project is taking longer and costing more than originally anticipated

• Anticipated completion date is now Fall 2015 rather than Spring 2015 • Costs are expected to be approximately $9.2 million rather than $4.6 million. Roughly $1million

has been spent to date. Number of analyzed configurations will be less than previously planned • Significant benefits are expected, but have not been specifically calculated

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SPP Board of Directors/Members Committee Minutes July 29, 2014 Mr. Brown made the following motion:

1. Suspend all work on current ECC initiative. 2. Staff directed for ECC, by October Meetings, to provide:

a. Best back of envelope cost benefit analysis b. Scoping a detailed cost benefit analysis

3. Work with Alstom and other Alstom customers for this functionality to be included in future Market Clearing Engine software.

4. Continue working with Alstom to understand the impact of ECC functionality on existing MCEs.

Mr. Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Agenda Item 5 - Strategic Planning Committee Report Mr. Ricky Bittle provided the Strategic Planning Committee (SPC) Report (Strategic Planning Committee Report – Attachment 11). Mr. Bittle began his report by thanking Mr. Michael Desselle for all of his hard work in putting the 2014 Strategic Plan together. Mr. Eckelberger echoed the comments by Mr. Bittle. Input was received from all committees and Working Groups, the RSC and other stakeholders. There was an SPC retreat and a draft plan was put together. The vision for the future is to:

• Optimize Interdependent Systems • Enhance Member Value and Affordability • Reliability Assurance • Maintain an Economical, Optimized Transmission System

Mr. Skilton moved to approve the adoption of the Strategic Plan. Mr. Brown seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Mr. Bittle returned to the recommendation that was pulled from the consent agenda, the RFP Response Time Extension. Mr. Eckelberger’s question for this recommendation is the proviso as to why the 90 days can be used instead of the 180 days, specifically take that proviso off and just let the staff have the discretion to use the 90 days instead of 180 days. Mr. Altenbaumer made the following motion: The Strategic Planning Committee revised the recommendation of SPCTF on Order 1000 to extend the RFP response time window associated with Competitive Bidding Cost Estimation proposals from 90 days to 180 days, unless the SPP Staff uses its discretion to reduce the response time window to no less than 90 days based on collaboration with Stakeholders. Ms. Bernard 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 started off with the recommendation to change SPP capacity accreditation methodology for wind and solar resources. After many meetings the following results came out of the July MOPC meeting: Generation Working Group (GWG) recommended 60% confidence factor during the top 3% load hours of the peak month with Member option for lower accreditation. MOPC approved the recommendation with an 84.1% vote; dissenting parties argued that the resulting capacity values will rely on wind too much for capacity. Mr. Janssen asked the Board of Directors to approve MOPC’s recommendation regarding CRR-012, Criteria Recommendation for Capacity Accreditation of Wind and Solar Resources. Ms. Bernard moved to approve and Mr. Brown seconded the motion. The Members Committee voted in favor with one against (City Utilities of Springfield). The Board voted; the motion passed.

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SPP Board of Directors/Members Committee Minutes July 29, 2014 Mr. Janssen went on to update the board on the remainder of information items from MOPC. The Seams Steering Committee jointly evaluated seams issues, identified transmission solutions that benefitted both regions (economic congestion and potential reliability violations). The Market Working Group (MWG) considered summary:

• EEC Project was agreed-upon as part of approval of Integrated Marketplace by SPP Membership.

• As staff has indicated previously, ECC Project is taking longer and costing more than originally anticipated.

• Anticipated completion date is now Fall 2015 rather than Spring 2015. • Costs are expected to be approximately $9.2 million rather than $4.6 million. Roughly $1 million

spent to date. Number of analyzed configurations will be less than previously planned. • Significant benefits are expected, but have not been specifically calculated.

Transmission Working Group (TWG) discussed the reliability limits trigger for expansion. TWG approved an SPP Staff recommendation to begin monitoring thermal loading at 90% rather than 95% and voltage at 95% rather than 90%. The final methodology for addressing MOPC Action Item 211-Procedures for identification of generating resources that are required to avoid reliability impacts – will be presented to the MOPC in October for final approval. The Economic Studies Working Group (ESWG) report included a Benefit Metrics report. Mr. Eckelberger suggested the remaining five items be voted on and approved at today’s meeting. Mr. Skilton made the following motion:

1. Approve all five of the recommended metrics based on the MOPC recommendations as augmented by the ESWG recommendations for the two that the MOPC did not approve. The recommendations for treatment of Public Policy projects would be applied from here forward.

2. Acknowledge that the R Plan is a project that provides economic and reliability benefits and not label it as a Public Policy project.

3. These ten metrics be provided to the RARTF to be used as effectively as possible in the RCAR process to drive equitable solutions for those zones with deficient benefits.

Mr. Brix seconded the motion. The Members Committee voted in favor with one abstention (City Utilities of Springfield). The Board voted; the motion passed. The 2015 Integrated Transmission Plan 10 (2015 ITP10) Scope was discussed and MOPC approved it. It was then discussed whether an ITP20 was necessary; it was determined that it was not and work on the ITP20 should be suspended at this time and revisited at the MOPC meeting in October. Next year will be an ITP10 year; this year we do Scenario Two and take advantage of the changing environment. A waiver will need to be completed to drop the ITP20 requirement. The suggestion to the ESWG was to take a little more time on ITP20. Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting to Executive Session at 2:45 p.m. Executive Session The Board heard a report and provided guidance on a pending Tariff compliance matter. Stacy Duckett, Corporate Secretary

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Southwest Power Pool, Inc.

BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING July 29, 2014

Embassy Suites Omaha-Downtown/Old Market – Omaha, Nebraska • A G E N D A •

8:00 a.m. – 3:00 p.m. Central 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 Donna Nelson

d. Federal Energy Regulatory Commission Report ..................................... Mr. Patrick Clarey

e. Oversight Committee Report ....................................................................... Mr. Josh Martin

f. Human Resources Committee Report ........................................................... Mr. Julian Brix

g. Corporate Governance Committee Report ................................................... Mr. Nick Brown

h. Finance Committee Report ........................................................................ Mr. Harry Skilton

3. Consent Agenda ....................................................................................................... Mr. Jim Eckelberger

a. Approve April 29 and June 9 Minutes (as amended)

b. Markets and Operations Policy Committee

i. MWG 1. MPRR173 2. MPRR178 3. MPRR183 4. MPRR190

ii. RTWG 1. TRR125 2. TRR126 3. TRR127 4. TRR133

iii. TWG 1. CRR-013

iv. SPCWG 1. Relay Misoperations Paper

v. Staff 1. Cost Tracking Recommendation 2. Legacy Project Baseline Cost Estimates 3. RE-evaluation of Chamber Springs-Farmington 4. Modification of Cowskin Hoover NTC

c. Strategic Planning Committee Recommendation

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable

4. Staff Reports

a. Integrated Marketplace ................................................................................. Mr. Bruce Rew

b. Project Pinnacle ....................................................................................... Ms. Barbara Sugg

5. Strategic Planning Committee Report ........................................................................ Mr. Ricky Bittle

6. Markets and Operations Policy Committee Report ................................................. Mr. Rob Janssen

7. Future Meetings ................................................................................................. Mr. Jim Eckelberger

RET/RSC/BOD – October 27-28…………………………Little Rock

BOD – December 9…………………………..……………Little Rock 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

BOD – December 8………………….………..……………Little Rock

Executive Session

Corporate Metrics 2nd Quarter 2014

July 21, 2014

1 Congestion

2 Regional Control Performance

3 Transmission Utilization Proxy

4 EIS Prices and Price Range

5 Revenue Neutrality 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 SPP Regional Entity Compliance

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 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2011 2012 2013 12 mo

Binding & Breached Time 694 581 628 687 735 663 592 588 656 574 498 595 647 548 655 555 625 623 620

Over Limit Time 264 164 413 422 477 276 191 363 410 377 383 * * * * 156 277 307 242

% Tags/ Schedules Curtailed (GWh) 0.95% 0.35% 0.34% 0.55% 0.72% 0.65% 0.32% 0.45% 0.83% 0.46% 0.20% 0.03% 0.03% 0.03% 0.04% 0.62% 0.61% 0.51% 0.36%

* not available at time of report publication

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

2011 2012 2013 12 mo

Average Monthly Binding & Breached Time (hrs)

-

100

200

300

400

2011 2012 2013 12 mo

Average Monthly Over Limit Time (hrs)

1b. Congestion - Curtailments

in GWh Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2011 2012 2013 12 mo

Tag Curtailments 28.2 21.7 10.1 23.3 39.0 63.8 60.5 65.0 133.8 34.7 20.8 5.0 3.9 5.1 7.3 87 42 42 39

Market (Schedules) Curtailments 177.6 59.2 78.6 137.3 172.7 103.7 13.9 36.3 79.3 85.9 27.1 * * * * 67 105 84 55

TOTAL Curtailments 205.8 80.9 88.8 160.5 211.7 167.5 74.4 101.4 213.1 120.5 48.0 5.0 3.9 5.1 7.3 154 148 126 93

Total Tags/ Schedules 21,662 23,084 26,010 29,098 29,602 25,827 22,976 22,724 25,740 26,486 23,442 15,630 14,840 16,005 20,526 24,689 24,343 24,640 22,741

% Tags/ Schedules Curtailed 0.95% 0.35% 0.34% 0.55% 0.72% 0.65% 0.32% 0.45% 0.83% 0.46% 0.20% 0.03% 0.03% 0.03% 0.04% 0.62% 0.61% 0.51% 0.36%

* no Market (Schedules) Curtailments in Integrated Marketplace

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

% 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

2011 2012 2013 12 mo

Tag Curtailments (GWh)

-

30

60

90

120

2011 2012 2013 12 mo

Market Curtailments (GWh)

1c. Congestion - TLR / CME Time

in hours Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2011 2012 2013 12 mo

Level 3A 166 177 120 227 290 498 379 392 377 435 202 291 248 149 160 517 369 306 304 Level 3B 9 14 23 13 7 28 13 13 30 41 28 11 13 4 9 46 23 17 18 Level 4 0 0 0 0 0 0 0 4 0 1 0 5 0 0 0 77 9 4 1 Level 5A 20 59 10 80 160 66 0 58 276 151 144 41 46 35 34 52 110 84 91 Level 5B 3 5 4 3 0 1 0 3 15 12 11 2 1 3 9 6 5 5 5 Total TLR Time 198 255 157 323 457 593 392 470 698 640 385 350 308 191 212 697 517 415 418 CME Time (loading >90%) 2,474 1,791 2,969 2,682 2,961 2,370 2,284 2,151 2,660 2,143 1,839 2,208 1,930 1,890 3,075 1,315 2,276 2,351 2,349

Tran

smis

sion

& M

arke

t Ind

icat

ors

Monthly Average in Hours

-500

500

1,500

2,500

3,500H

ours

in T

LR /

CM

E

Level 5B Level 5A Level 4 Level 3B Level 3A CME Time (loading >90%)

-

400

800

1,200

2011 2012 2013 12 mo

Monthly Average Level 3 TLR (hrs)

-

40

80

120

2011 2012 2013 12 mo


-

20

40

60

80

100

2011 2012 2013 12 mo


-

500

1,000

1,500

2,000

2,500

2011 2012 2013 12 mo

CME Time (loading > 90%) (hrs)

1d. Congestion - Congested Intervals

Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2011 2012 2013 12 mo

Uncongested Intervals 4% 22% 13% 8% 1% 8% 20% 18% 12% 23% 26% 20% 10% 26% 9% 30.8% 23.8% 14.5% 15.0%

Intervals with Binding Only 87% 73% 81% 86% 94% 86% 74% 72% 75% 65% 63% 65% 77% 62% 72% 63.8% 71.8% 79.2% 74.5%

Intervals with a Breach 9% 5% 7% 6% 5% 6% 5% 9% 14% 12% 11% 15% 13% 12% 19% 5.4% 4.4% 6.3% 10.5%

Interval = 5 minutes

Tran

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ors

Average

Figures beginning March 2014 are for Real-Time

congestion in the Integrated Marketplace.

0%

10%

20%

30%

40%

2011 2012 2013 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%

2011 2012 2013 12 mo

Intervals with Binding Only

0%

2%

4%

6%

8%

10%

12%

2011 2012 2013 12 mo

Intervals with a Breach

1e. Price Contour Map (March - June 2014)

Day-Ahead

Tran

smis

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& M

arke

t Ind

icat

ors

1f. Price Contour Map (March - June 2014)

Real-Time

Tran

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icat

ors

1g. Congestion - Flowgates (March - June 2014)

Flowgate Name Region Flowgate LocationOSGCANBUSDEA Texas Panhandle Osage Switch - Canyon East (115) ftlo Bushland - Deaf Smith (230)WDWFPLWDWTAT Western Oklahoma Woodward - FPL Switch (138) ftlo Woodward EHV - Tatonga (345)TEMP06_18995 Central Kansas Smokey Hills - Summit (230) ftlo Mullegren - Circle (230)IATSTRSTJHAW KC - Omaha Corridor Iatan - Stranger Creek (345) ftlo St. Joe - Hawthorn (345)TEMP14_20121 Wichita area Gordon Evans - Maize (138) ftlo Wichita - Benton (345)SHAXFRTUCOKU Texas Panhandle Shamrock Xfmr (115/69) ftlo Elk City Xfmr (230/138)TEMP38_20360 SW Kansas Sun City - Medicine Lodge (115) ftlo Finney - Hitchland (345)TEMP15_20172 Western Nebraska Snake Creek - Alliance (115) ftlo Stegall - Wayside (230)NEORIVNEOBLC SE Kansas Neosho - Riverton (161) ftlo Neosho - Blackberry (345)TEMP44_20033 Central Oklahoma Woodring Xfmr (345/138) ftlo Sooner Xfmr (345/138)

Tran

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ors

0%

20%

40%

60%

80%

$0

$40

$80

$120

$160

% C

onge

sted

Shad

ow P

rice

($/M

Wh)

DA Average Shadow Price RT Average Shadow Price DA % Intervals Congested RT % Intervals Congested

2a. Regional Control Performance - CPS1 Compliance

CPS1 Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2010 2011 2012 2013

>150% 7 7 6 6 9 7 8 9 8 6 7 6 4 4 8

100%-150% 13 13 14 14 11 13 12 11 12 11 10 13 16 16 12

<100% 0 0 0 0 0 0 0 0 0 0 0 - - - -

Notes:1. Three BAs (CLEC, LEPA, LAFA) became part of MISO with Entergy's integration into MISO in December 2013.2. March 1, 2014 all exisiting BAs became part of the Consolidated SPP BA.

Tran

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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 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2010 2011 2012 2013

>95% 15 13 12 14 14 15 15 17 18 12 13 17 17 17 15

90-95% 5 7 8 6 6 5 5 3 2 5 4 2 3 3 5

<90% 0 0 0 0 0 0 0 0 0 0 0 0 - - -

Notes:1. Three BAs (CLEC, LEPA, LAFA) became part of MISO with Entergy's integration into MISO in December 2013.2. March 1, 2014 all exisiting BAs became part of the Consolidated SPP BA.

Tran

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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%

2c. Balancing Authority Report - CPS Performance

CPS1 (statistical measure of 1 minute average ACE vs. Frequency)

>=100% <100%

CPS2 (10 minute average of ACE performance)

>95% 90%-95% <90%SPP BA is not subject to CPS, but is subject to BAAL. CPS is reported here for informational purposes only.

Mar

ketp

lace

Indi

cato

rs

50%

100%

150%

200%

Mar 14 Apr 14 May 14 Jun 14 Jul 14 Aug 14 Sep 14 Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15

85%

90%

95%

100%


2d. Balancing Authority Report - BAAL Performance

Event Length Mar 14 Apr 14 May 14 Jun 14 Jul 14 Aug 14 Sep 14 Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15>10 and <=30 min 1 0 0 1>30 min 0 0 0 0

Mar

ketp

lace

Indi

cato

rs 0

2

4

6

8

10


Even

ts

>10 and <=30 min >30 min

3a. Transmission Utilization - $

Service (in MM $) Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2011 2012 2013 12 mo

Network 84.09 88.07 91.14 98.99 93.14 93.13 89.49 89.01 91.84 92.01 101.86 104.32 98.30 102.93 106.19 66.16 77.17 88.77 96.77

Firm PTP 7.25 7.35 7.56 8.27 7.20 7.85 8.76 5.31 7.94 10.64 9.14 9.06 7.05 7.33 9.42 4.65 6.50 7.57 8.16

Non-Firm PTP 0.71 0.68 0.47 0.75 0.59 0.64 0.68 0.60 0.86 1.58 1.17 0.43 0.29 0.38 0.35 0.65 0.66 0.65 0.69

Total 92.04 96.11 99.17 108.01 100.93 101.62 98.92 94.91 100.64 104.23 112.17 113.80 105.63 110.64 115.96 71.46 84.33 96.99 105.62

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Monthly Average

0

20

40

60

80

100

120in

mill

ions

$

Non-Firm PTP Firm PTP Network

$0

$30

$60

$90

$120

2011 2012 2013 12 mo

in m

illio

ns

Non-Firm PTP Firm PTP Network

3b. Transmission Service Requests

Confirmed Refused Confirmed Refused Confirmed Refused Confirmed RefusedHourly 30,473 9,525 26,973 8,733 28,986 9,234 6,613 2,297Daily 3,286 19,098 1,795 13,676 1,045 6,318 613 2,449Weekly 987 4,723 520 5,796 772 4,204 563 3,106Monthly 6,436 54,967 5,503 107,103 9,021 34,716 5,340 14,566Yearly 724,067 62,545 792,533 104,685 793,821 124,476 386,619 81,493Total 765,249 150,858 827,324 239,993 833,645 178,948 399,748 103,911

2014 (first 6 months)2011 2012 2013

Tran

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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

2011 2012 2013 2014 (first 6 months)

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

2011 2012 2013 2014 (first 6 months)

GW

h

4a. Price and Price Range (Real-Time) Integrated Marketplace - March - June 2014Tr

ansm

issi

on &

Mar

ket I

ndic

ator

s

AECC AEPM

BEPM

CHAN

EDEP

FREM

GMOC

GRDX GSEC

INDN KBPU KCPS

KMEA

KPP

LESM MEAN

MEUC

MIDW

OGE OMPA

OPPM

REMC

SEPC

SPSM

TEAC

TEAN

TNSK

WFES

WRGS

$32.86

1.23

0.6

1.0

1.4

1.8

2.2

$24

$28

$32

$36

$40

LSE Volatility LSE Average SPP Average SPP Volatility

4b. Electricity/Gas Cost Comparison

Average in $ Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14

EIS LIP ($/MWh) 27.59 27.52 25.35 26.95 26.39 24.48 23.86 23.92 30.39 29.22 42.78

DA LMP ($/MWh) 39.82 35.70 35.58 31.24

RT LMP ($/MWh) 38.70 29.59 35.97 26.78

PEPL GasCost ($/MMBtu) 4.03 3.87 3.56 3.47 3.23 3.43 3.51 3.41 4.22 4.83 8.00 5.17 4.44 4.37 4.34

Tran

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ors

$0

$2

$4

$6

$8

$10

$0

$10

$20

$30

$40

$50

Jun12

Jul 12 Aug12

Sep12

Oct12

Nov12

Dec12

Jan13

Feb13

Mar13

Apr13

May13

Jun13

Jul 13 Aug13

Sep13

Oct13

Nov13

Dec13

Jan14

Feb14

Mar14

Apr14

May14

Jun14

Gas

Cos

t (Pa

nhan

dle

East

ern

Pipe

line)

$/M

MB

tu

EIS LIP DA LMP RT LMP Gas (PEPL) 12 month avg Gas

Elec

tric

ity P

rice

($/M

Wh)

5. Revenue Neutrality Uplift

in thousands $ Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2011 2012 2013 12 mo

Total Uplift -610 -1,165 -381 265 828 -1,089 -2,282 -1,535 -546 -1,510 -3,350 -839 -1,565 -2,156 -4,964 -2,398 -13,769 -7,463 -18,744

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

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ors

Total

-$6,000

-$4,000

-$2,000

$0

$2,000in

thou

sand

s $

-$20,000

-$16,000

-$12,000

-$8,000

-$4,000

$0

$4,000

2011 2012 2013 12 mo

in th

ousa

nds $

6a. Market Liquidity - Offered and Dispatchable

Daily Average Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2010 2011 2012 12 mo

Dispatchable MW 11,360 12,351 16,077 17,028 16,991 15,443 12,102 12,350 14,396 14,588 14,155 11,221 12,738 13,693 14,632

Total Offered MW 26,215 28,411 35,764 38,706 38,976 34,699 27,950 28,831 32,259 32,740 32,043 33,917 32,079 31,781 33,276

% of Total Offered 43% 43% 45% 44% 44% 45% 43% 43% 45% 45% 44% 33.1% 39.7% 43.1% 44.0%

Tran

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& M

arke

t Ind

icat

ors

Monthly Average

0%

20%

40%

60%

80%

0

10,000

20,000

30,000

40,000

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 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14

% 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 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2011 2012 2013 12 mo

Sales (MWh) 69,420 68,504 88,415 82,315 84,023 77,024 64,210 67,634 74,713 75,710 71,884 60,380 73,795 72,856 74,689

Sales ($000's) 1,799 1,804 2,123 2,178 2,182 1,787 1,414 1,435 2,025 2,014 2,875 1,695 1,571 1,786 1,989

Tran

smis

sion

& M

arke

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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


Sale

s ($

000s

)

Sale

s M

Wh

EIS Market Sales Volumes (average daily volume by month)

Sales (MWh) Sales ($000's)

0

25,000

50,000

75,000

2011 2012 2013 12 mo

Aver

age

Dai

ly S

ales

(MW

h)

0

1,000

2,000

2011 2012 2013 12 mo

Aver

age

Dai

ly S

ales

($00

0's)

7. SPP Admin Fee Performance

2006 2007 2008 2009 2010 2011 2012 2013 2014Budgeted Net Revenue Required ($000s) 45,688$ 52,819$ 61,462$ 56,478$ 68,358$ 78,368$ 89,560$ 121,800$ 132,600$ Budgeted Load (000's) 258,556 288,649 312,496 331,324 333,458 343,000 353,453 360,915 348,178 Budgeted NRR / Budget Load 0.177$ 0.183$ 0.197$ 0.170$ 0.205$ 0.228$ 0.253$ 0.337$ 0.381$

Approved Admin Fee 0.160 0.190 0.190 0.170 0.195 0.210 0.255 0.315 0.381 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Actual Net Revenue Required ($000's) 48,613$ 47,998$ 58,081$ 59,837$ 63,497$ 80,841$ 84,776$ 123,336$ 136,152$ Actual Load (000's) 286,446 301,098 296,135 328,175 331,610 341,438 361,686 357,535 352,081 Actual NRR / Actual Load 0.170$ 0.159$ 0.196$ 0.182$ 0.191$ 0.237$ 0.234$ 0.345$ 0.387$

EIA-411 Load Growth Forecast -0.60% 1.80% 2.10% 2.40% -1.00% 2.21%

Actual Load Growth 7.19% 5.12% -1.65% 10.82% 1.05% 2.96% 5.93% -1.15% -1.53%

Fina

ncia

l Met

rics

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

$0.16

$0.20

$0.24

$0.28

$0.32

$0.36

$0.40

2006 2007 2008 2009 2010 2011 2012 2013 2014

$ pe

r MW

h

Approved Admin Fee Budgeted NRR / Budget Load Actual NRR / Actual Load

8. Budget Performance Monitor

in thousands $ Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14

Budgeted Operating Expense 12,901 12,714 12,852 13,527 12,855 12,674 13,491 13,258 13,622 16,884 16,514 16,765

Actual Operating Expense 12,264 12,217 12,813 12,525 12,454 13,059 12,171 12,942 16,238 16,146 21,391 17,570

Monthly Variance:Over Budget / (Under Budget) (637) (497) (39) (1,002) (401) 385 (1,320) (316) 2,616 (738) 4,877 805

12 month Cumulative Variance:Over Budget / (Under Budget) (637) (1,134) (1,173) (2,175) (2,576) (2,191) (3,511) (3,827) (1,211) (1,949) 2,928 3,733

Fina

ncia

l Met

rics

-$6,000

-$4,000

-$2,000

$0

$2,000

$4,000

$6,000

Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14in th

ousa

nds

$

Operating Expense Variance

Monthly Variance Cumulative Variance

9. Financial Settlement Index

in thousands Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 12 moLate Transmission Payments $553 $338 $12 $192 $1,002 $2,525 $69 $332 $222 $2,284 $39 $1,980 $9,548Total Transmission Payments $30,260 $33,509 $33,570 $32,464 $31,938 $26,996 $31,455 $33,174 $37,083 $38,438 $36,508 $38,244 $403,639

% Late Payments 2% 1% 0% 1% 3% 9% 0% 1% 1% 6% 0% 5% 2%

in thousands Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 12 moLate Market Payments $0 $0 $7 $192 $846 $80 $158 $19 $800 $1,298 $21 $51 $3,472Total Market Payments $17,430 $23,617 $18,276 $14,630 $12,307 $27,687 $23,007 $36,153 $59,324 $55,695 $87,725 $65,091 $440,942

% Late Payments 0% 0% 0% 1% 7% 0% 1% 0% 1% 2% 0% 0% 1%

in thousands Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 12 moTransmission Short Pays $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $0EIS Market Short Pays $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $ - $0

Fina

ncia

l Met

rics

0%

3%

6%

9%

12%%

of T

otal

Pay

out

% of Late Transmission Payments

0%

3%

6%

9%

12%

% 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

Market Short Pays

10a. Financial Disputes Index - $ EIS Market

(Figures in $000's)

Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2011 2012 2013 12 mo

Total Disputes $33.2 $104.6 $10.8 $107.8 $27.0 $381.1 $1,183.9 $71.4 $53.0 $328.6 $54.7 $20.3 $54.9 $0.0 $1.0 45.2$ 61.5$ 178.0$ 190.3$

Avg. Dispute Size $2.4 $3.3 $0.3 $4.1 $1.4 $16.6 $21.1 $5.1 $10.6 $14.3 $2.7 $1.3 $3.6 $0.0 $0.3 1.3$ 2.7$ 5.7$ 6.8$

Largest single dispute $14.6 $28.6 $6.9 $34.3 $11.0 $68.2 $0.3 $22.6 $50.1 $130.0 $11.5 $5.6 $22.5 $0.0 $1.0 212.4$ 231.8$ 88.1$ 130.0$ *

* Annual maximum

Fina

ncia

l Met

rics

Monthly Average

$0

$50

$100

$150

$200

$250

$300

$350

$400$0

00's

Settlement DisputeStatistics ($)

Total Disputes Largest single dispute Average Dispute Size

$0

$100

$200

$300

2011 2012 2013 12 mo

Monthly Average Amount in Dispute ($000's)

$0

$2

$4

$6

$8

$10

2011 2012 2013 12 mo

Average Dispute Size ($000's)

$0

$100

$200

$300

2011 2012 2013 12 mo

Largest Single Dispute ($000's)

10b. Financial Disputes Index - EIS Market

(Figures in $000's) Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 2011 2012 2013 12 mo# Disputes 30 22 50 38 30 15 16 41 20 15 4 - - 38.1 24.3 27.3 20.9 # Resettlements 6 48 30 17 61 86 18 10 56 73 20 18 23 8.6 23.9 29.5 38.3 Avg Days Outstanding 32 54 35 42 35 36 57 32 24 25 60 - 79 27.3 40.5 38.4 39.9

Fina

ncia

l Met

rics

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

2011 2012 2013 12 mo

Monthly Average of Active Disputes

-

10

20

30

2011 2012 2013 12 mo

Average Monthly Resettlements

-

10

20

30

40

50

2011 2012 2013 12 mo

Average Days Outstanding

10c. Financial Disputes Index - $ Intergrated Marketplace

(Figures in $000's)

Mar 14 Apr 14 May 14 Jun 14 Jul 14 Aug 14 Sep 14 Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15 Apr 15 May 15

Total Disputes $80.8 $300.0 $17.0 $55.5

Avg. Dispute Size $26.9 $75.0 $3.4 $6.9

Largest single dispute $63.5 $127.5 $8.4 $49.4 *

* Annual maximum

Fina

ncia

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rics

$0

$50

$100

$150

$200

$250

$300$0

00's

Settlement Dispute Statistics ($)

Total Disputes Avg. Dispute Size Largest single dispute

$0

$100

$200

$300

Monthly Average Amount in Dispute ($000's)

$0

$2

$4

$6

$8

$10 Average Dispute Size ($000's)

$0

$100

$200

$300 Largest Single Dispute ($000's)

10d. Financial Disputes Index Integrated Marketplace

(Figures in $000's) Mar 14 Apr 14 May 14 Jun 14 Jul 14 Aug 14 Sep 14 Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15

# New Disputes 28 21 33 27 # Resettlements - - - 15 Avg Days Outstanding 4 7 7 2

Fina

ncia

l Met

rics

Monthly Average

-

10

20

30

40

# New Disputes

-

20

40

Monthly Average of Active Disputes

-

10

20

30

Average Monthly Resettlements

-

10

20

30

40

50Average Days Outstanding

-

4

8

12

16

20

# Resettlements

-

2

4

6

8

10

Avg Days Outstanding

11a. Employee Turnover - monthly

Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14Voluntary TO Rate 0.9% 0.2% 0.3% 0.5% 0.7% 0.7% 0.5% 0.5% 0.4% 0.2% 0.0% 0.4% 0.5% 0.7% 0.7%Involuntary TO Rate 0.0% 0.0% 0.0% 0.0% 0.0% 0.2% 0.2% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.2% 0.0%Total Turnover (# of employees) 5 1 2 3 4 5 4 3 2 1 - 2 3 5 4

Permanent Employees 566 569 573 575 576 576 571 568 569 571 571 571 572 573 574

Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14Rolling 12-monthTurnover Rate 5.0% 5.0% 4.8% 5.0% 4.6% 5.3% 6.0% 5.6% 5.8% 5.6% 5.4% 5.6% 5.2% 5.9% 6.3%

Lear

ning

& G

row

th

300

350

400

450

500

550

600

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

Jun12

Jul 12 Aug12

Sep12

Oct12

Nov12

Dec12

Jan13

Feb13

Mar13

Apr13

May13

Jun13

Jul 13 Aug13

Sep13

Oct13

Nov13

Dec13

Jan14

Feb14

Mar14

Apr14

May14

Jun14

Turn

over

Rat

e Employee Turnover (monthly)

Involuntary TO Rate Voluntary TO Rate # of Employees

0%

2%

4%

6%

8%

10%


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 2014

Total Turnover 3 1 7 7 10 8 8 8 14 21 30 13 21 20 28 33 15 Total Employees 39 45 73 110 110 116 131 169 245 295 345 423 449 514 558 569 571 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% 5.8% 5.3%

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 2014

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 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14

Filled w/ Internal Hire 2 - 1 3 2 1 3 5 - - 4 1 - 3 2 Filled w/ External Hire 5 4 6 5 4 3 - - 3 3 - 2 5 3 4 Hired YTD 20 24 31 39 45 49 52 57 60 3 7 10 15 21 27

2011 2012 2013 2014

Filled w/ Internal Hire 78 53 22 10 Filled w/ External Hire 78 54 38 17 Hired YTD 156 107 60 27

Lear

ning

& G

row

th

0

20

40

60

80

Apr 13 May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14

Empl

oyee

s

Filled w/ External Hire Filled w/ Internal Hire Hired YTD

13. SPP Regional Entity Compliance

2010 2011 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 2013 2014Starting Caseload 154 268 245 178 206 207 212 195 182 178 195New Violations 254 239 364 56 46 45 44 32 42 191 74

Processed by SPP RE 117 187 331 19 35 33 47 34 24 134 58

Dismissed by SPP RE 23 75 83 9 10 7 14 11 15 40 26

Ending Caseload 268 245 195 206 207 212 195 182 185 195 185

Cumulative Violations 448 687 860 916 962 1,007 1,051 1,083 1,265

Perf

orm

ance

0

100

200

300

2010 2011 2012 2013 1Q '14 2Q '14

Period End Open Caseload

2010 2011 2012 2013 1Q 2014 2Q 2014 3Q 20140

100

200

300Violations

New Processed Dismissed

14a. IT System Performance - 12 month Service Availability

The below chart reflects only performance for the period from March - June 2014.

Perf

orm

ance

14b. IT System Performance - 12 month Service Availability

The below chart reflects the rolling 12 month availability through 2/28/2014.

Perf

orm

ance

16a. Studies - Aggregate - MW

Completed 2Q 13 3Q 13 4Q 13 1Q 14 2Q 14 In Progress 2Q 13 3Q 13 4Q 13 1Q 14 2Q 142011-AGP12011-AG2 452 2011-AG22011-AG3 745 2011-AG3 2,869 1,519 2012-AG1 1,700 2012-AG1 2,834 2,834 2,834 2012-AG2 313 2012-AG2 4,655 1,840 1,841

2012-AG3 8,323 5,434 5,189 3,581 3,581 TOTAL 452 - 745 1,700 313 2013-AG1 3,945 3,563 1,483 1,483

2013-AG2 5,974 14,855 14,757 14,557 2013-AG3 2,889 2,309

TOTAL 17,895 17,971 20,416 23,971 19,621

MWMW

Perf

orm

ance

2011-AG3 2011-AG3

Completed 2011-AG2

2012-AG1 2012-AG1

2012-AG1

2012-AG2

2012-AG2

2012-AG2 Completed 2012-AG2

Completed 2011-AG3

2012-AG3

2012-AG3

2012-AG3

2012-AG3

2012-AG3

2013-AG1

2013-AG1

2013-AG1

2013-AG1

2013-AG2

2013-AG2

2013-AG2

2013-AG2

2013-AG3

2013-AG3

Completed 2012-AG2

(4,000)

-

4,000

8,000

12,000

16,000

20,000

24,000

28,000

32,000

2Q 13 3Q 13 4Q 13 1Q 14 2Q 14

MW

16b. Studies - Aggregate - Upgrade $

Completed 2Q 13 3Q 13 4Q 13 1Q 14 1Q 14 In Progress 2Q 13 3Q 13 4Q 13 1Q 14 2Q 14

2011-AG2 3.3$ 2011-AG22011-AG3 22.0$ 2011-AG3 464.0$ 61.0$ 2012-AG1 1.1$ 2012-AG1 186.6$ 26.6$ 51.4$ 2012-AG2 -$ 2012-AG2 332.2$ 0.4$ 2.8$

2012-AG3 368.9$ 510.1$ 291.2$ 103.5$ 105.1$ TOTAL 3.3$ -$ 22.0$ 1.1$ -$ 2013-AG1 101.3$ 35.6$ 55.6$ 31.6$

2013-AG2 289.4$ 23.8$ 181.8$ 175.0$ 2013-AG3 72.1$ 36.0$

TOTAL 1,120.8$ 1,219.2$ 474.5$ 379.6$ 311.7$

$ (in millions) $ (in millions)

Perf

orm

ance

2011-AG3

2011-AG3

2012-AG1

2012-AG1 2012-AG1

2012-AG2

2012-AG2 2012-AG2

2012-AG3

2012-AG3

2012-AG3

2012-AG3 2012-AG3

2013-AG1

2013-AG1 2013-AG1 2013-AG1

2013-AG3

2013-AG3

2013-AG2

2013-AG2

2013-AG2 2013-AG2

-$400

$0

$400

$800

$1,200

2Q 13 3Q 13 4Q 13 1Q 14 1Q 14

$ (in

mill

ions

)

16c. Studies - Generation Interconnection - MW

In Progress 2Q 13 3Q 13 4Q 13 1Q 14 2Q 14DISIS-2009-001 201

DISIS-2010-001 300 300

DISIS-2010-002 728 278 278 81 70

DISIS-2011-001 3,319 1,719 1,420 521 401

DISIS-2011-002 1,096 1,096 887 157 53

DISIS-2012-001 491 451 230 230 230

DISIS-2012-002 2,759 2,617 2,109 1,094 609

DISIS-2013-001 1,629 1,590 1,390 1,242 1,241

DISIS-2013-002 2,213 2,213 2,213

DISIS-2014-001 1,885 2,217

PISIS-2013-001 400 400

PISIS-2013-002 326 326

PISIS-2014-001 213 213

FCS-2013-003 200 200 150

FCS-2014-001 472 472

FCS-2014-002 1,858 Pending Withdrawal

TOTAL 11,124 8,652 9,004 8,435 9,577

Perf

orm

ance

MW

-

4,000

8,000

12,000

2Q 13 3Q 13 4Q 13 1Q 14 2Q 14

MW

Generation Interconnection MW - In Progress

2009 Studies 2010 Studies 2011 Studies 2012 Studies 2013 Studies 2014 Studies

16d. Schedule of Commerical Operation Dates for Upcoming Generation Interconnection Agreements as of June 30, 2014

MW CapacityIA Fully Executed / On Suspension 1,669.4 IA Fully Executed / On Schedule 9,833.7

Total Scheduled or Suspended Generation 11,503.1

Perf

orm

ance

Charts above reflect Executed Generation Interconnection Agreements (GIA’s) with upcoming Commercial Operation Date (COD) milestones by year and month. Data based on Queue Status of “IA Fully Executed / On Schedule”,

0

400

800

1,200

1,600

2,000

Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2014 2015

MW

Cap

acity

Commercial Operation Month

0

1

2

3

2014 2015 2016 2017 2018 2019

GW

Cap

acity

Commercial Operation Year

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).

Regulatory Update - Activity in Significant Dockets Second Quarter 2014

SPP Tariff/Governing Document Revisions Docket Number Short Description Summary ER12-1179 ER13-1173 ER14-416 13-1181 (U.S. Court of Appeals)

Submission of Tariff Revisions to Implement SPP Integrated Marketplace Revisions to Modify Certain Aspects of the SPP Integrated Marketplace Submission of Tariff Revisions to Modify SPP Integrated Marketplace Nebraska Public Power District (“NPPD”) v. Federal Energy Regulatory Commission - Petition for Review of Orders in FERC Docket ER12-1179

On April 1, 2014, FERC issued an Order Conditionally Accepting Compliance Filing in Docket No. ER12-1179-016. The Commission conditionally accepted SPP's January 22, 2014 Compliance Filing to incorporate for the Integrated Marketplace provisions required by SPP's Order No. 745 compliance proceeding, effective March 1, 2014. SPP's compliance filing is due on December 1, 2014. On April 14, 2014, NPPD filed a Motion for Voluntary Dismissal in U.S. Court of Appeals Case No. 13-1181. On April 15, 2014, the U.S. Court of Appeals issued an Order dismissing the case. On April 30, 2014, FERC issued an order accepting SPP's February 25, 2014 Compliance Filing in Docket No. ER14-416-001. This order constitutes final agency action. On June 19, 2014, FERC issued an Order on Compliance Filing in Docket Nos. ER12-1179-018 and ER13-1173-000, conditionally accepting SPP's February 26, 2014 Compliance Filing effective March 1, 2014, subject to an additional compliance filing due on July 21, 2014. On July 11, 2014, SPP filed a Motion for Clarification regarding the allocation of costs associated with manual resource commitments to address Local Reliability Issues in the Integrated Marketplace.

ER13-366 and ER13-367

Submission of Tariff Revisions to Comply with Order No. 1000 Regional Planning and Cost Allocation Requirements Submission of Revisions to its Membership Agreement to Comply with Order No. 1000

FERC action is pending on SPP’s November 15, 2013 Compliance Filing. SPP’s Order No. 1000 Compliance Filing due to incorporate a competitive component into SPP's Aggregate Study Process is due on August 15, 2014.

ER13-1292 Order No. 764 Compliance Filing

On April 17, 2014, FERC issued an Order Conditionally Accepting Compliance Filing. The proposed revisions to Attachment P were accepted, effective November 12, 2013 as requested. The proposed revisions to sections 13.8 and 14.6 of the Tariff were conditionally accepted, effective November 12, 2013 and March 1, 2014, as requested. SPP was directed to submit a compliance filing to revise sections 13.8 and 14.6 of the Tariff to make clear that transmission customers may schedule transmission service in increments of less than 15 minutes. On May 9, 2014, SPP submitted its compliance filing in response to the Order Conditionally Accepting Compliance Filing issued on April 17, 2014.

Page 1 of 8


SPP Tariff/Governing Document Revisions Docket Number Short Description Summary

On June 23, 2014, FERC issued an order accepting SPP's May 9, 2014 Compliance Filing, effective March 1, 2014. This order constitutes final agency action.

ER13-1748 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 Other Tariff Language

On June 19, 2014, FERC issued an Order on Compliance Filing, conditionally accepting SPP's proposed Tariff revisions, effective March 1, 2015, subject to a further compliance filing. SPP was directed to submit an informational report containing information on how the mileage factor has evolved, based on SPP's system-wide regulation deployment analyses, and whether changes in the mileage factor have had an effect in reducing unused mileage make whole payments (thus indicating more efficient clearing and equitable settlement in the regulation market). SPP was also directed to include in its informational report an evaluation of the continued appropriateness of the five percent Regulation Mileage Operating Tolerance band. SPP's informational report is due May 2, 2016. The Commission stated that with regard to the refined mitigated mileage offer procedures approved by SPP's Board of Directors for proposed inclusion in the Tariff, SPP should submit these procedures at least 60 days before the March 1, 2015 implementation date of SPP's Order No. 755 reforms. SPP was directed to revise certain aspects of its proposal in a compliance filing due on July 21, 2014.

ER13-1939 Submission of Tariff Revisions to Comply with Order No. 1000 Interregional Coordination and Cost Allocation Requirements

FERC action is pending.

ER13-2031 Submission of Revisions to Bylaws and Membership Agreement to Implement Withdrawal Obligations and Revisions to Provide Greater Flexibility Regarding the Functions of Various SPP Committees Reporting to the Board of Directors

On May 14, 2014, FERC issued an order accepting SPP's November 1, 2013 Compliance Filing, effective September 23, 2013. This order constitutes final agency action.

Page 2 of 8


SPP Tariff/Governing Document Revisions Docket Number Short Description Summary ER14-781 Submission of Tariff Revisions

to Modify the Generator Interconnection Procedures

On June 13, 2014, FERC issued an Order Conditionally Accepting in Part and Rejecting in Part Tariff Revisions, to become effective March 1, 2014, subject to a compliance filing. The Commission rejected SPP's proposed revisions to limited operation service and "queue jumping" proposal. SPP's changes to the Definitive Queue, revisions to milestones, changes to Article 2.3.2 of the Generator Interconnection Agreement, and proposed transition provisions were conditionally accepted, subject to compliance filing. On July 14, 2014, SPP submitted its compliance filing in response to the June 13, 2014 Order.

ER14-1357 Submission of Tariff Revisions regarding Credit Limits for Transmission Congestion Rights ("TCRs")

On April 11, 2014, FERC issued an order accepting tariff revisions necessary to correct an unintended consequence of the current credit requirement calculations for transactions involving Transmission Congestion Rights. An effective date of May 1, 2014 was granted. This order constitutes final agency action.

ER14-1653 Submission of Tariff Revisions to Modify SPP Integrated Marketplace

On April 3, 2014, SPP submitted tariff revisions to effectuate a general clean-up filing to comport the Tariff with previous Commission orders, and to modify certain aspects of the Integrated Marketplace. Effective dates of March 1, 2014 and May 1, 2014 were requested. On April 24, 2014, Southern Companies filed a Motion to Intervene and Protest concerning pseudo-tied resources. On May 9, 2014, SPP filed an answer in response to Southern Companies' Protest. On May 30, 2014, FERC issued a letter requesting additional information in order to process the April 3, 2014 Filing. SPP submitted its responses on July 1, 2014.

ER14-1993 Tariff Revisions to Clarify Methodology for Quantifying Real Power Losses

On May 20, 2014, SPP submitted tariff revisions to provide additional clarity to the Tariff with regard to real power loss responsibility of transmission customers. The proposed revisions clean-up relevant references to real power losses so the terminology is used consistently throughout the Tariff. The modifications also provide supplemental information that explains more clearly how real power losses are calculated for Network Integration Transmission Service and Point-to-Point Transmission Service. The revisions also update the zonal loss factors listed in Appendix 1 to Attachment M for each Transmission Owner. An effective date of July 19, 2014 was requested.

Page 3 of 8


Other Filings of Interest Docket Number Short Description Summary EL11-34 12-1158 (U.S. Court of Appeals) EL14-21 ER14-1174 EL14-30

Midcontinent Independent 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”) SPP Complaint for an Order Finding the Midcontinent Independent System Operator, Inc. ("MISO") is Violating the Joint Operating Agreement ("JOA") between SPP and MISO and the SPP Tariff and Requiring MISO to Compensate SPP for Use of SPP's Transmission System (“SPP Complaint”) Unexecuted Firm Point-To-Point Transmission Service Agreement between SPP as Transmission Provider and Midcontinent Independent System Operator, Inc. ("MISO") as Transmission Customer Midcontinent Independent System Operator, Inc. ("MISO") Complaint Regarding Transmission Service Invoices

On April 11, 2014, MISO filed a Request for Rehearing of the March 28, 2014 Order. On April 28, 2014, the MISO Transmission Owners filed a Request for Rehearing of the March 28, 2014 Order. On April 28, 2014, the MISO Transmission Owners filed a Motion to Stay Effectiveness of Service Agreement Pending Decision on Rehearing. On May 12, 2014, FERC issued an Order Granting Rehearing for Further Consideration of the March 28, 2014 Order. Settlement Conferences were held on April 29, 2014 and June 3, 2014. The next Settlement Conference is scheduled to be held on August 21, 2014.

Page 4 of 8


Other Filings of Interest Docket Number Short Description Summary

from SPP (“MISO Complaint”)

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)

FERC action is pending.

EL14-38 Sunflower Electric Power Corporation ("Sunflower") Complaint Against Kansas Municipal Energy Agency (“KMEA”) and SPP Alleging that the KMEA/Garden City Supply Arrangement is Defective under the Commission's and SPP's Rules

On April 9, 2014, Sunflower filed a Complaint against KMEA and SPP alleging that the KMEA/Garden City supply arrangement is defective under the Commission's and SPP's rules. On April 30, 2014, SPP and KMEA filed answers in response to the Complaint. On May 29, 2014, Sunflower filed an answer in response to SPP's and KMEA's answers filed on April 30, 2014. On June 27, 2014, SPP filed an answer in response to Sunflower's Motion for Leave to Reply and Reply filed on May 29, 2014.

EL14-49 and EL14-65

SPP’s Petition for Declaratory Order Seeking the Commission's Confirmation that Acceptance of a Notice of Termination of a Point-to-Point Transmission (“PTP”) Service Agreement Does Not Preclude a Transmission Provider from Seeking Contract Damages for Breach of the Service Agreement AES Shady Point, LLC's ("AES") Petition for Declaratory Order Asking the Commission to Determine that SPP's Tariff

On May 9, 2014, SPP filed a Petition for Declaratory Order seeking the Commission's confirmation that the acceptance of a notice of termination of a PTP service agreement, filed in accordance with the Commission's regulations, does not preclude a transmission provider from seeking contract damages for breach of the service agreement in a court of appropriate jurisdiction. On June 9, 2014, AES filed a Motion to Intervene and Protest. AES stated that the Commission should deny or otherwise reject SPP's Petition for Declaratory Order because it is contrary to the plain language of SPP's Tariff. On June 9, 2014, AES filed a Petition for Declaratory Order asking the Commission to determine that SPP's Tariff prohibits SPP from recovering damages in the form of lost revenues from AES. On July 9, 2014, SPP filed a Motion to Intervene, Protest, and Answer. SPP stated: 1) the Commission should grant the unopposed SPP Petition; 2) the Commission should deny AES' Petition as the matters it raises do not require the Commission's special expertise; and

Page 5 of 8


Other Filings of Interest Docket Number Short Description Summary

Prohibits SPP from Recovering Damages in the Form of Lost Revenues from AES

3) if the Commission elects to address the AES Petition, it should find that the SPP Tariff does not prohibit SPP from seeking the full unpaid contract price under the AES Agreement.

EL14-57 City of Hastings, Nebraska and City of Grand Island, Nebraska ("Complainants") Complaint Charging SPP with Violating the Federal Power Act (“FPA”) by Demanding that Complainants Purchase Transmission Service that is Not Required by the Tariff and Demanding that Complainants Pay Unreserved Use Penalties that Are Not Permitted Under the Tariff

On May 23, 2014, Complainants filed a Complaint charging SPP with violating the FPA by demanding that Complainants purchase transmission service that is not required by the Tariff and by demanding that Complainants pay unreserved use penalties that are not permitted under the Tariff. On June 12, 2014, SPP filed an answer to the Complaint. SPP stated 1) contrary to the Complainants, the Tariff requires customers to have sufficient transmission for all services and authorizes SPP to impose unreserved use penalties for failure to secure such transmission; 2) obstacles and impediments alleged by Complainants are largely red herrings; and 3) SPP is amendable to revisiting TRR 102M or some similar proposal to minimize Complainants' exposure to unreserved use penalties. On June 12, 2014, Nebraska Public Power District filed a Motion to Intervene and Answer to the Complaint. On June 27, 2014, Complainants filed an answer in response to SPP's and Nebraska Public Power District's answers filed on June 12, 2014.

ER14-1407 Amendments to Joint Operating Agreement ("JOA") between SPP and the Midcontinent Independent System Operator, Inc. ("MISO") to Account for Import and Export Transactions in the Market Flow Calculations (SPP Rate Schedule FERC No. 9)

On April 8, 2014, SPP, MISO, and PJM Interconnection, L.L.C. filed an answer in response to comments and protests filed in this proceeding. On April 24, 2014, FERC issued a deficiency letter requiring additional information in order to process the March 3, 2014 Filing. SPP submitted its responses on May 27, 2014.

ER14-2062 Proposed Modifications to Section 3.3 of Attachment 3 (Emergency Energy Transactions) of the Joint Operating Agreement ("JOA") between Midcontinent Independent System Operator, Inc. ("MISO") and SPP (SPP Rate Schedule FERC No. 9)

On May 29, 2014, SPP submitted proposed revisions to Section 3.3 of Attachment 3 of the J OA between MISO and SPP. The changes will allow MISO to recover costs invoiced to MISO as a transmission customer under the SPP Service Agreement in the event that MISO market flows exceed the existing contract path capacity limit of 1,000 MW between the MISO Midwest Region and the MISO South Region in order to provide emergency energy assistance to SPP. An effective date of May 30, 2014 was requested.

Page 6 of 8


State Cases Docket Number Short Description Summary Arkansas 13-041-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 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 10, 2014, the APSC issued Order No. 35, granting SWEPCO's and Save the Ozarks' petitions for rehearing for the purpose of further consideration. On June 9, 2014, the APSC issued Order No. 36, finding that, while some transmission development in the area appears warranted, the record is presently insufficient to determine: the need for the particular 345 kV project that has been proposed, whether that project is consistent with the public convenience and necessity, and whether the project represents an "acceptable adverse environmental impact considering...the various alternatives, if any, and other pertinent considerations." The Commission granted rehearing for consideration of additional evidence on the need for, and the potential environmental impact of, the proposed 345 kV project. The Commission also granted rehearing for consideration of additional evidence on the routing of the proposed transmission line. Because the Commission granted rehearing for consideration of additional evident, the prior grant of the CECPN for Route 109 was vacated By separate order, the Commission will set a procedural schedule for additional testimony and hearings.

Kansas 14-SPPE-563-SHO

In the Matter of the General Investigation of Southwest Power Pool, Inc. to Show Cause Why the Costs Associated With the Proposed Membership of Western Area Power Administration - Upper Great Plains Region, Basin Electric Power Cooperative, and Heartland Consumers Power District (“Integrated System”) are in the Public Interest of Kansas Electric Retail Customers

On June 9, 2014, the Kansas Corporation Commission (“Commission”) issued a Show Cause Order, Discovery Order, and Protective Order. The Commission stated it has concerns regarding the due diligence undertaken by SPP with respect to the proposed "Federal Service Exemptions" and questions whether terms reflected in the membership agreement are unduly preferential. The Commission finds that SPP should show cause why the proposed membership agreement offered to the Integrated System is in the public interest of Kansas retail electric ratepayers. The Commission specifically requires SPP to provide evidence that the benefits to Kansas retail electric ratepayers will exceed the increased costs of serving the integrated system. The Commission ordered SPP to Show Cause why the proposed terms and conditions offered to the integrated system is in the public interest of Kansas retail electric ratepayers. On June 19, 2014, SPP provided its responses to the Commission's Information Requests 1 and 2. On June 23, 2014, SPP provided its responses to the Commission's Information Request 3. On June 27, 2014, SPP filed a Motion for Extension of Time to July 30, 2014 to submit its response to the Show Cause Order.

Page 7 of 8


State Cases Docket Number Short Description Summary

On July 1, 2014, the Prehearing Officer issued an Order Granting Southwest Power Pool, Inc.'s Motion for Extension of Time. SPP's response to the Show Cause Order is due by July 30, 2014.

Missouri EW-2014-0156

In the Matter of an Investigation Into the Possible Methods of Mitigating Identified Harmful Effects of Entergy Joining the Midcontinent Independent System Operator, Inc. (“MISO”) on non-MISO Missouri Utilities and Their Ratepayers and Maximizing the Benefits for Missouri Utilities and Ratepayers Along RTO and Cooperative Seams

On July 1, 2014, SPP filed Comments in Response to the Commission's Questions Identified in its Order Opening an Investigation into Seams issued on November 26, 2013. Several parties filed Comments in response to the questions posed in the November 26, 2013 Order.

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”)

On April 4, 2014, the Parties filed a Proposed Certification of Unopposed Stipulation. On May 1, 2014, the Hearing Examiner filed a Certification of Stipulation, recommending that the Commission approve the Stipulation. On May 21, 2014, the Commission issued a Final Order Adopting Certification of Stipulation. SPS' interim period for participation in the SPP RTO was extended to December 31, 2029. SPS' Extended Interim Period Report is due on July 1, 2028. On June 2, 2014, SPS filed its annual report in accordance with the Uncontested Stipulation.

Page 8 of 8

Regulatory Outlook

EW-2014-0156

7/1/2014State of Missouri Responses to questions listed in the November 26, 2013 Order are due (Order Granting Joint Motion to

Extend Time for Filing; Order Setting Deadline for Responses issued on January 3, 2014)

EL14-65

7/9/2014FERC Comments due in response to AES Shady Point, LLC's Petition for Declaratory Order (Notice of Petition

for Declaratory Order issued June 9, 2014)

ER14-781

7/14/2014FERC Compliance filing due to revise Generator Interconnection Procedures (Order Conditionally Accepting in

Part and Rejecting in Part Tariff Revisions issued on June 13, 2014)

ER13-1748

7/21/2014FERC SPP's Order No. 755 Compliance Filing is due (Order on Compliance Filing issued on June 19, 2014)

ER12-1179

7/21/2014FERC SPP's Integrated Marketplace Compliance Filing is due (Order Conditionally Accepting Compliance Filing

issued on June 19, 2014)

ER13-1173

7/21/2014FERC SPP's Integrated Marketplace Compliance Filing is due (Order Conditionally Accepting Compliance Filing

issued on June 19, 2014)

RM14-11

7/29/2014FERC Comments due in response to NOPR concerning Open Access and Priority Rights on Interconnection

Customer's Interconnection Facilities (Notice of Proposed Rulemaking issued on May 15, 2014)

14-SPPE-563-SHO

7/30/2014State of Kansas SPP to Show Cause why the proposed terms and conditions offered to the Integrated System is in the

public interest of Kansas retail electric rate payers (Show Cause Order issued on June 9, 2014;

Prehearing Officer Order Granting Southwest Power Pool, Inc.'s Motion for Extension of Time issued on

July 1, 2014)

RM13-2

8/4/2014FERC Each public utility Transmission Provider to submit a compliance filing revising its Small Generator

Interconnection Procedures and Small Generator Interconnection Agreement or other document(s)

subject to the Commission's jurisdiction as necessary to demonstrate that it meets the requirements set

forth in Order No. 792 (Order No. 792 issued on November 22, 2013)

7/15/2014 9:13:26 AM Page: 1

Regulatory Outlook

ER14-1225

8/7/2014FERC Compliance Filing due to to incorporate Lea County Electric Cooperative, Inc.'s rates filed in the

settlement into SPP's Tariff (Letter Order issued on July 8, 2014)

ER13-366

8/15/2014FERC Order No. 1000 Compliance Filing due to incorporate a competitive component into SPP's Aggregate

Study Process (Notice of Extension of Time issued on October 24, 2013; Order on Compliance Filing

issued on July 18, 2013)

ER13-367

8/15/2014FERC Order No. 1000 Compliance Filing due to incorporate a competitive component into SPP's Aggregate

Study Process (Notice of Extension of Time issued on October 24, 2013; Order on Compliance Filing

issued on July 18, 2013)

42636

8/15/2014State of Texas Workshop to be held to discuss the proposed EPA Rule on Greenhouse Gas Emissions for Existing

Generating Units (Public Notice of Workshop issued on July 3, 2014)

EW-2012-0065

8/18/2014State of Missouri Workshop to be held to address the cost of compliance with the EPA’s recently published proposed

state-specific rate-based goals for carbon dioxide emissions for existing fossil fuel-fired electric

generating unit (Order Scheduling a Workshop Meeting and Directing Response issued on July 2, 2014)

EL14-21

8/21/2014FERC Settlement Conference to be held (Order Scheduling Settlement Conference issued on June 10, 2014)

EL11-34


ER14-1174


EL14-30


7/15/2014 9:13:26 AM Page: 2

Regulatory Outlook

RM14-1

8/25/2014FERC Effective date of Order No. 797, Final Rule approving Reliability Standard EOP-010-1 (Geomagnetic

Disturbance Operations) (Order No. 797 issued on June 19, 2014)

RM14-7

8/25/2014FERC Comments due in response to NOPR proposing to approve Modeling, Data, and Analysis Reliability

Standard MOD-001-2 developed by the North American Electric Reliability Corporation (Notice of

Proposed Rulemaking issued on June 19, 2014)

ER12-1179

8/28/2014FERC SPP's Compliance Filing due 180 days after the commencement of the Integrated Marketplace to

establish long-term firm transmission rights pursuant to Order No. 681. Provided the Integrated

Marketplace is implemented on March 1, 2014, SPP's compliance filing will be due by August 28, 2014

(Order Conditionally Accepting Tariff Revisions to Establish Energy Markets issued October 18, 2014)

AD14-14

9/8/2014FERC Price Formation in Energy and Ancillary Services Markets Operated by RTOs/ISOs workshop to be held

to discuss the technical, operational and market issues that give rise to uplift payments and the levels of

transparency (Notice of Workshop issued on July 9, 2014)

ER05-652

10/15/2014FERC File Informational Report on SPP Aggregate Study (Safe Harbor Report) (April 22, 2005 Order)

ER08-1338

11/1/2014FERC SPP to file its Annual Budget in FERC Docket Nos. ER04-48, ER08-1338, RT04-1

RM14-2

11/28/2014FERC Comments due in response to NOPR proposing to revise the Commission's regulations at section 284.12

to better coordinate the scheduling of natural gas and electricity markets in light of increased reliance on

natural gas for electric generation, as well as to provide additional flexibility to all shippers on interstate

natural gas pipelines (Notice of Proposed Rulemaking issued on March 20, 2014)

ER12-1179

12/1/2014FERC Integrated Marketplace Compliance Filing due to address Net Benefits Test and Demand Response Cost

Allocation (Order Conditionally Accepting Compliance Filing issued on April 1, 2014)

7/15/2014 9:13:26 AM Page: 3

To: SPP Officers / Directors / ManagersFrom: Sheri Dunn / Cindy GoodwinDate: July 21, 2014RE: June 2014 Financial Package

Page1). Financial Commentary: FY Actual to Budget Variances 1

2). Financial Overview: FY Actual by month compared to Budget and Prior Year 2

3). Income Statement Actual Results Overview: Current Month Actual compared to Forecast, FY Actual compared to Budget and FY Actual compared to Prior Year

4

4). Balance Sheet: Current Month compared to Ending Prior Year 5

6). 6

7). Headcount Analysis: Forecast compared to Budget 8

Memorandum

Capital Projects Summary: Project-to-Date and Remaining Forecast compared to Total Capital Project Budget

Attached are the June 2014 monthly financial reports.

2014 FY 2014 FY Fav/(Unfav)Forecast Budget Variance

Revenues $162,912 $163,166 ($254) (0.2%)

Expenses 205,351 200,692 (4,658) (2.3%)

Net Income/(Loss) ($42,438) ($37,526) ($4,913) (13.1%)


Tariff Administration Service $134,143 $132,600 $1,543 1.2%

FERC Fees & Assessments 14,667 14,500 167 1.1%

NERC ERO Regional Entity Rev 9,625 11,824 (2,199) (18.6%)

Miscellaneous Income 3,570 3,350 220 6.6%

Contract Services Revenue 453 453 1 0.0%

Annual Non-Load Dues 456 440 16 3.6%

Total Revenue $162,912 $163,166 ($254) (0.2%)

9

10

2014 Financial CommentaryJune 30, 2014(in thousands)

Summary

Revenue

In preparation of the 2014 budget for Tariff Administration Service revenues, SPP estimated network service billing determinants utilizing January -August 2013 actual results, which were running 3% below 2012 actuals, and applied that same reduction to the September - December 2013 estimates. The SPP region realized a significant reversal of the trend for the September -December 2013 period. The 2014 MWh forecast is anticipated to be approximately 352 million MWh as compared to the budget of 348 million.

2012 Actual 2014 Budget 2013 ActualNetwork Service (GWh) 325,356 307,106 318,980Point-to-Point 36,000 41,094 38,555

361,356 348,200 357,535

SPP expects to collect approximately $1,543 more than budgeted for Schedule 1A administrative fees during 2014.

NERC ERO Regional Entity revenue is based on Regional Entity (RE) budgeted expenditures and anticipated pass-thru expenses for SPP resources outside the RE. The primary drivers of the unfavorable revenue variance relate to compensation and pass-thru expense associated with outside services and SPP resource time. Although the budget assumed the RE would be fully staffed at the beginning of the year, currently 4 of the 31 budgeted positions remain vacant (with 1 position which was removed from the RE 2015 budget). The services variance is related to fewer audit and hearings expenses. The revenue forecast has been reduced to align with the current revenue trend for 2014. The net impact associated with both RE revenue and expense is unfavorable by $767.

Page 1 of 8

2014 Financial CommentaryJune 30, 2014(in thousands)


Salary & Benefits $84,585 $82,247 ($2,338) (2.8%)

Assessments & Fees 16,323 15,300 (1,023) (6.7%)

Communications 3,769 3,916 146 3.7%

Maintenance 15,826 15,866 40 0.3%

Outside Services (Including RSC) 15,652 14,640 (1,012) (6.9%)

Administrative & Leases 4,602 4,858 256 5.3%

Travel & Meetings 2,903 3,112 209 6.7%

Depreciation & Amortization 51,583 49,718 (1,865) (3.8%)

Other Expenses 10,107 11,035 928 8.4%

Total Expense $205,351 $200,692 (4,659) (2.3%)

Expense

Salary & Benefits expenses represent an unfavorable variance to budget primarily resulting from an unbudgeted performance payout to SPP staff which was proposed and approved by the SPP Board of Directors and Members Committee. The impact of the performance payout has been mitigated somewhat by lower staffing levels year to date (approx. 4% vacancy resulting in $1,100 reduction in expenses), decreased contributions to retirement plans ($650 reduction), and lower than budgeted expenditures for continuing education ($200 reduction).

The Assessments and Fees has increased significantly from prior forecasts. SPP received its annual assessment invoice from FERC in June and immediately recognized a $240 charge to true-up the prior year under-accrual and also increased the current year accrual by $740 in recognition of the increased FERC costs now expected for 2014.

Outside Services exceeds budget as a result of classification of the activities of several of the consultants engaged in Integrated Marketplace as operating expenses instead of capital expenses as they were budgeted. These activities were primarily the expected post go-live support activities ($1,860 increase). Additionally, a supplement to the 2013 State of the Market report was approved by the SPP Oversight Committee out of budget at a cost of $200. Conversely, outside services trail budget across several departments, with the main contributors found in Regional Entity ($340), Engineering ($365), Legal ($245), and Internal Audit ($230). The Regional Entity variance relates to fewer audit and hearings expenses. Year-to-date outside legal fees related to the Integrated Market were lower than expected, but this decrease was partially offset by higher than anticipated expenses related to the MISO contested docket. Internal Audit expense trails budget as a result of restructuring the Type 1 audit. This change resulted in part of the Type 1 audit items being included in the 2013 Readiness Assessment.

Travel expenses fall below budget across most departments, with the most notable variances in the Regional Entity ($87), and Engineering ($23). This is partially due to lower headcount. Various working group meetings trail budget, contributing to the favorable variance in Meetings expense ($62).

Depreciation for the Integrated Marketplace was budgeted to begin April 1st instead of March 1st and therefore results in an unfavorable variance in depreciation expense; however this variance is non-cash and has no impact on cost recovery.

Page 2 of 8

Actual Actual Actual Actual Actual Actual Fcst Fcst Fcst Fcst Fcst Fcst FY 2014 FY 2014 Variance FY 2013 VarianceJan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Forecast Budget Fav/(Unfav) Actual Fav/(Unfav)

IncomeTariff Administrative Service 11,613 10,265 11,348 10,970 11,338 11,079 11,488 11,595 11,112 11,193 10,901 11,243 $134,143 132,600 $1,543 112,624 $21,519Fees & Assessments 2,483 2,122 1,789 1,982 1,748 2,115 2,118 2,218 2,218 2,018 1,918 2,018 24,747 26,764 (2,016) 25,188 (441)Contract Services Revenue 36 36 38 38 38 38 38 38 38 38 38 38 453 453 0 425 28Miscellaneous Income 380 191 231 362 301 430 279 279 279 279 279 279 3,570 3,350 220 4,502 (932)

Total Income 14,512 12,615 13,406 13,352 13,425 13,661 13,923 14,130 13,647 13,528 13,136 13,578 162,912 163,166 (254) 142,738 20,174

ExpenseSalary & Benefits 6,489 6,737 6,646 6,806 10,919 6,646 6,645 6,699 6,707 6,780 6,740 6,770 84,585 82,247 (2,338) 79,660 (4,924)Employee Travel 106 135 150 153 168 167 170 177 229 232 156 163 2,007 2,192 186 1,868 (139)Administrative 188 344 207 533 255 539 347 313 255 331 829 285 4,425 4,675 250 3,967 (459)Assessments & Fees 1,300 1,300 1,300 1,300 1,300 1,645 1,363 1,363 1,363 1,363 1,363 1,363 16,323 15,300 (1,023) 14,699 (1,624)Meetings 91 72 77 80 67 84 90 55 79 81 75 45 896 919 23 930 34Communications 374 318 308 305 305 308 308 308 308 309 309 309 3,769 3,916 146 3,665 (105)Leases 13 12 16 18 12 15 15 15 15 15 15 15 177 183 6 432 255Maintenance 1,013 1,012 1,144 1,270 1,787 1,447 1,369 1,359 1,355 1,355 1,356 1,358 15,826 15,866 40 11,301 (4,526)Services 837 1,261 1,857 1,155 2,156 973 1,184 1,124 1,207 1,341 1,136 1,142 15,374 14,313 (1,062) 15,870 495Regional State Committee 11 15 15 14 20 15 73 23 23 23 23 23 278 328 50 207 (71)Depreciation & Amortization 1,750 1,736 4,517 4,511 4,403 5,731 4,950 4,765 4,790 4,790 4,800 4,840 51,583 49,718 (1,865) 19,398 (32,185)

Total Expense 12,171 12,942 16,238 16,146 21,391 17,570 16,515 16,202 16,333 16,620 16,802 16,314 195,243 189,657 (5,586) 151,995 (43,249)

Other Income/(Expense)Other Income/Expense (41) 58 (36) (18) 34 31 - - - - - - 28 - 28 5,651 (5,623)Interest Income 2 2 3 4 4 6 - - - - - - 21 - 21 223 (202)Interest Expense (837) (886) (841) (962) (930) (1,034) (920) (920) (918) (900) (898) (900) (10,946) (12,195) 1,249 (10,540) 406Capitalized Interest - - 221 12 - 78 - - 175 - - 270 756 1,160 (404) 2,777 2,020Change in Valuation of Swap - - 27 - - 7 - - - - - - 34 - 34 923 889

Net Other Income (Expense) (875) (826) (627) (964) (893) (912) (920) (920) (743) (900) (898) (630) (10,107) (11,035) 928 (910) (2,566)

Net Income (Loss) $1,465 ($1,153) ($3,459) ($3,758) ($8,858) ($4,821) ($3,512) ($2,991) ($3,428) ($3,993) ($4,564) ($3,366) ($42,438) ($37,526) ($4,913) ($10,168) ($32,271)(26,608,179)

2014 Headcount Forecast 569 570 573 576 575 576 574 575 577 576 580 583 583 *2014 Headcount Budget 597 598 598 598 598 598 598 598 598 598 598 598 598

Over / (Under) Budget (28) (28) (25) (22) (23) (22) (24) (23) (21) (22) (18) (15) (15) Headcount Vacancy -5% -5% -4% -4% -4% -4% -4% -4% -4% -4% -3% -3% -3%

NRR Over / (Under) Recovery $3,193 $501 ($1,825) $4,041 ($4,153) $1,350 $1,501 $1,685 ($4,180) $960 $448 ($5,753) ($2,232) $0 ($2,232) $4,549 ($6,781)

* The 2014 forecast assumes a vacancy average of 3% for October - December.

Southwest Power PoolMonthly Overview

June 30, 2014(in thousands)

Page 3 of 8

Jun-2014 Jun-2014 Variance Jun-2014 Jun-2014 Variance Jun-2014 Jun-2013 VarianceActual Forecast Fav/(Unfav) Actual Budget Fav/(Unfav) Current Year Prior Year Fav/(Unfav)

IncomeTariff Administrative Service $11,079 $10,992 $87 $66,612 $66,300 $312 $66,612 $55,975 $10,637Fees & Assessments $2,115 $2,068 47 $12,239 $13,452 (1,213) $12,239 $12,092 147Contract Services Revenue $38 $38 $225 $225 $225 $208 17Miscellaneous Income $430 $279 150 $1,895 $1,675 220 $1,895 $1,819 76

Total Income 13,661 13,377 284 80,971 81,651 (681) 80,971 70,093 10,877

ExpenseSalary 4,546 4,564 17 27,116 27,662 546 27,116 26,118 (998)Benefits & Taxes 2,059 2,057 (2) 16,797 13,133 (3,664) 16,797 12,193 (4,604)Continuing Education 41 87 46 331 574 242 331 309 (22)Salary & Benefits 6,646 6,707 $61 44,244 41,368 ($2,875) 44,244 38,620 ($5,624)Employee Travel 167 193 26 879 1,107 228 879 1,010 130Administrative 539 627 87 2,066 2,373 307 2,066 2,013 (53)Assessments & Fees 1,645 1,300 (345) 8,145 7,650 (495) 8,145 7,421 (724)Meetings 84 36 (47) 471 489 17 471 492 21Communications 308 308 () 1,917 1,958 41 1,917 1,814 (103)Leases 15 15 85 91 6 85 335 250Maintenance 1,447 1,374 (73) 7,674 7,945 271 7,674 5,475 (2,199)Services 973 1,119 145 8,240 7,442 (798) 8,240 7,138 (1,101)Regional State Committee 15 23 8 89 139 50 89 97 7Depreciation & Amortization 5,731 4,953 (778) 22,648 19,971 (2,677) 22,648 9,598 (13,050)

Total Expense 17,570 16,656 (914) 96,458 90,534 (5,925) 96,458 74,013 (22,445)

Other Income/(Expense)Gain or Loss on Sale of Fixed Asset - - - - - - - 58 (58)Other Income/Expense 31 - 31 28 - 28 28 85 (57)Interest Income 6 - 6 21 - 21 21 114 (92)Interest Expense (1,034) (937) (97) (5,490) (6,095) 605 (5,490) (5,330) (160)Capitalized Interest 78 50 28 311 996 (685) 311 1,519 (1,208)Change in Valuation of Swap 7 - 7 34 - 34 34 592 (559)

Net Other Income (Expense) (912) (887) (25) (5,097) (5,099) 2 (5,097) (2,963) (2,134)

Net Income (Loss) ($4,821) ($4,166) ($655) ($20,585) ($13,981) ($6,603) ($20,585) ($6,883) ($13,701)

Headcount 576 573 3 576 598 (22) 576 572 4

Southwest Power PoolActual Results Overview

(in thousands)

Current Month Compared to Forecast YTD Actual Compared to YTD Budget YTD 2014 Compared to YTD 2013

June 30, 2014

Page 4 of 8

6/30/2014 12/31/2013 Net Change

ASSETS Current Assets Cash & Equivalents $51,451 $34,874 $16,577 Restricted Cash Deposits 218,237 76,712 141,525 Accounts Receivable (net) 30,066 24,134 5,932 Other Current Assets 12,999 6,966 6,033 Total Current Assets $312,754 $142,687 $170,067

Total Fixed Assets 191,523 204,259 (12,736) Total Other Assets 2,797 3,158 (361) Investments 1,416 1,305 111

TOTAL ASSETS $508,488 $351,409 $157,079

LIABILITIES & EQUITY Liabilities Current Liabilities Accounts Payable (net) $21,787 $15,953 $5,834 Customer Deposits 218,271 76,713 141,559 Current Maturities of LT Debt 25,774 22,998 2,775 Other Current Liabilities 32,048 29,038 3,011 Deferred Revenue 6,341 5,919 422 Total Current Liabilites 304,221 150,620 153,601

Long Term Liabilities US Bank 5.45% Senior Notes - 2016 6,000 9,000 (3,000) US Bank Maumelle Mortgage - 2027 3,444 3,547 (103) Campus 4.82% Senior Notes - 2042 62,423 62,963 (540) Integrated Marketplace 3.55% Senior Note - 2024 61,250 64,750 (3,500) Senior Notes - 2024 90,000 95,000 (5,000) Senior Notes - 2025 37,000 - 37,000 Other Long Term Liabilities 5,631 6,425 (793) Total Long Term Liabilities 265,748 241,685 24,063

Net Income (20,585) (10,168) (10,417) Members' Equity (40,896) (30,728) (10,168) Total Members' Equity (61,481) (40,896) (20,585)

TOTAL LIABILITIES & EQUITY $508,488 $351,409 $157,079

Southwest Power PoolBalance SheetJune 30, 2014(in thousands)

Page 5 of 8

Capital Project Dashboard(in millions)

$115.2

$21.8 $16.7 $23.5

$114.4

$21.8 $11.9

$23.6

$0.0

$20.0

$40.0

$60.0

$80.0

$100.0

$120.0

$140.0

Integrated MarketplaceGo-Live

Phase II (Including Ph IDeferred)

Carry Over and NewProjects

IT / Ops Foundation

2014-2016 Total Project Budget vs. Forecast *

Total Budget Total Forecast

$124.3

$47.5

Project-to-Date

RemainingForecast

Project-to-Date vs. Remaining Forecast

* Includes prior year expenses (except for IT / Ops Foundation projects)

$177.2 $171.8

Total Budget Total Forecast

Total Project Budget vs. Forecast

Page 6 of 8

Total Budget

Project-to-Date Actual

Remaining Forecast

Total Forecast

Over/(Under) Budget

Integrated Marketplace Go-Live $115,173 $114,413 - $114,413 ($761)

Phase II (Project Pinnacle), Including Phase I Deferred $21,770 $4,728 $17,084 $21,812 $42

Carry Over and New ProjectsOPS DTS Upgrade to TTSE (cancelled) 4,400 - - - (4,400)Transmission Settlements Upgrade ETSE3.0 (2015) 3,775 - 3,775 3,775 - Netezza Upgrade 3,038 2,646 392 3,038 (0)EMS Upgrade 1,696 - 1,447 1,447 (249)EMS Readiness 728 889 - 889 161Data Center Migration 720 264 450 714 (6)Aurea ESB Replacement 706 - 706 706 - Project Server Upgrade 300 12 108 120 (180)Miscellanous Facilities 318 72 246 318 0Alstom ETS Foundation 225 - 225 225 - QA ICCP Buildout 180 77 106 183 3TAGIT Database Enhancement 150 - 150 150 - Cost Allocation SQL Database 50 - 50 50 - Engineering App Store 25 - 25 25 - FERC Order 1000 Regional RFP 165 - 165 165 - EIS Sunset (costs will not be capitalized) 150 - - - (150)Rate Impact Automation (2015) 75 - 75 75 - 2013 Carryforward - Centralized Modeling Tool - 7 - 7 72013 Carryforward - Credit Stacking - 2 - 2 22014 Unbudgeted - Engineering POM License - 25 - 25 25

Carry Over and New Projects $16,700 $3,993 $7,918 $11,912 ($4,788)

IT / Ops Foundation *

IT Systems Foundation 8,154 48 8,120 8,168 14IT Network Telecom 7,596 719 6,922 7,642 46IT Applications Foundation 2,799 - 2,799 2,799 - IT Service Management Foundation 901 107 791 898 (3)IT Environment Foundation 173 - 173 173 - Operations Foundation 3,889 248 3,654 3,902 13

IT / Ops Foundation $23,513 $1,122 $22,459 $23,581 $69

Total Capitalized Project Expense $177,156 $124,256 $47,462 $171,718 ($5,438)

* IT / Operations foundation projects are reforecast during each budget cycle and do not include any carry-over funds. Project-to-Date reflects only 2014year-to-date actual results for both IT and Ops foundation projects. The remaining forecast includes 2015 and 2016 forecast.

Complete Project List Total Project-to-Date and Remaining Forecast Compared to Budget

As of June 30, 2014(in thousands)

Page 7 of 8

Current Month Actual vs. Budget Full Year Forecast vs. BudgetActual Budget Over/(Under) FY 2014 FY 2014 Over/(Under)Jun-14 Jun-14 Budget Forecast Budget Budget

Administration 0 0 0 (12) 0 (12)Officers 10 10 0 10 10 0Accounting 10 10 0 10 10 0Credit 4 4 0 4 4 0Settlements 24 25 (1) 24 25 (1)

Administration 48 49 (1) 36 49 (13)

Corporate Services 29 29 0 29 29 0

Inter-Regional Affairs 4 4 0 4 4 0Project Management 12 13 (1) 13 13 0Training 11 13 (2) 11 13 (2)Customer Service 9 9 0 10 9 1Process Management 3 2 1 3 2 1Internal Audit 6 6 0 6 6 0

Process Integrity 45 47 (2) 47 47 0

SPP Compliance 12 13 (1) 12 13 (1)Communications 4 3 1 4 3 1Market Monitoring 13 14 (1) 14 14 0

Compliance & Market Monitoring 29 30 (1) 30 30 0

SPP Regional Entity 27 31 (4) 30 31 (1)

Information Technology 139 144 (5) 146 144 2

Markets 6 6 0 6 6 0

Interregional Relations 3 3 0 3 3 0

Operations 155 157 (2) 155 157 (2)

Engineering Planning 39 41 (2) 43 41 2

Engineering Other 30 35 (5) 32 35 (3)

Regulatory Policy & General Counsel 26 26 0 26 26 0

TOTAL HEADCOUNT 576 598 (22) 583 598 (15)

* The 2014 forecast assumes a vacancy average of 3% for July - December.

Southwest Power PoolHeadcount Analysis

June 30, 2014

Page 8 of 8

SPP RE Update to Board of Directors

July 29, 2014

John MeyerChairman, SPP RE Trustees

Bulk Electric System Definition Update• New BES definition went into effect 7/1/14

• BESNet tool open for submitting collect Self-Determinations and Exception Requests

• Through 7/15/14, SPP RE has processed four requests

• Exception Requests submitted between 7/1/14 and 9/1/14 will be considered for Compliance purposes as received on 7/1/14

• Contact Greg Sorenson for more information

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https://identity.eroenterprise.com/account/signin?ReturnUrl=%2fissue%2fwsfed%3fwa%3dwsignout1.0%26wreply%3dhttps%253a%252f%252fbesnet.eroenterprise.com%252f&wa=wsignout1.0&wreply=https%3a%2f%2fbesnet.eroenterprise.com%2f

http://www.nerc.com/pa/RAPA/BES%20DL/InitialBESNotificationProcessing2014-06-18-RegisteredEntities.pdf

mailto:[email protected]

CIP Update

• Revised CIP V3-V5 Guidance is imminent

• Transition pilot program completed; SPP RE thanks Westar for its participation

Vegetation Management Update

• No reportable contacts in SPP RE footprint for 2Q 2014

• 5th consecutive quarter with no reportable contacts

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SPP RE Regional Events - 2Q 2014• Three Category 1 (least severe) events were analyzed

– 1 Category 1h - Loss of monitoring or control at a control center

– 2 Category 1f - Unplanned evacuation from a control center facility

• 16 total events through 2Q– All events rated Category 0 and Category 1

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SPP RE Misoperation Report as of 1Q 2014

Most Violated StandardsBased on rolling 12 months through 6/30/14 [Represents ~ 85% of total violations]

* NERC Report Q4 2013** Not in NERC Rolling 12 month Top Ten

SPPRE

Rank

NERC 12 Month

Rank *Standard Description Number of

Violations Risk Factor

1 1 CIP-007 Systems Security Management 28 Medium

2 10 FAC-008 Facility Ratings (includes FAC-009) 23 Med./Lower

3 3 CIP-005 Electronic Security Perimeters 22 Medium

4 2 CIP-006 Physical Security - Critical Cyber Assets 13 Med./Lower

5 4 PRC-005 Protection System Maintenance 12 High/Lower

6 6 CIP-002 Critical Cyber Asset Identification 11 High/Lower

7 5 CIP-004 Personnel & Training 8 Med./Lower

8 7 CIP-003 Security Management Controls 7 Med./Lower

9 8 VAR-002 Network Voltage Schedules 5 Med./Lower

10 ** PRC-008 UFLS Relay Maintenance 5 Medium

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Outreach

• Upcoming Events– Sept. 30-Oct. 1, Fall Workshop, Oklahoma City

– Oct. 1-2, RTO Compliance Forum, Oklahoma City

• Materials posted for June CIP Workshop, attended by 172 stakeholders

• New CIP videos posted to online video training library– Active Vulnerability Assessments

– CIP-010 and Change Management

– Port Scans & Configuration of PSP Maintenance Laptop

– Technical Feasibility Exception Process Update

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http://www.spp.org/event_detail.asp?dateID=Sep_30_2014

http://www.spp.org/event_detail.asp?dateID=Oct_1_2014

http://www.spp.org/section.asp?group=3151&pageID=27

http://vimeopro.com/sppcompliance/re/video/98750957




Human Resources Committee Report

July 29, 2014

• Mr. Julian Brix, Chairman

• Mr. Josh Martin, Director

• Mr. Duane Highley, Arkansas Electric Cooperative Corporation

• Ms. Kelly Walters, Empire District Electric Company

• Mr. Noman Williams, Sunflower Electric Power Corporation

• Ms. Lori Dunn, Calpine Energy Services

• Ms. Malinda See, SPP Staff Secretary

The SPP Human Resources Committee members include:

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Summary of Agenda Items from June 12, 2014:

• Reviewed 2013 Performance Compensation Plan Process

• Discussed 401(k) Investment Manager Review Process (Action Item)

• SPP Human Resources Staff Report– Metrics

– SPP HR department alignment with SPP Strategic Plan

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2013 Performance Compensation Plan Process

• HRC responsible for approval and review

• Funds are allocated based on:– Employee performance in prior year

– Philosophy that SPP either succeeds or fails as a team

• SPP Management evaluates employees– Discuss employee performance with either CEO or COO

– Awards reviewed and approved by SPP officer team

– Adjustments for equity made as needed

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401(k) Investment Manager• HRC responsible for investment manager engagement

• Current manager: Jay White, Smith Capital Management

• Plan Growth:– 2005: 140 participants, $9 million in assets

– 2014: 580 participants, $60 million in assets

• SPP HRC has not requested bids for investment manager services since 2005

• Action: Committee voted to issue RFP for investment manager services, committee will conduct interviews and select manager at September 10, 2014 meeting

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2014 RTO Budgeted Headcount: 5672014 RE Budgeted Headcount: 312014 Total Budgeted Headcount, RTO & RE: 598

Headcount 1/1/2014: 569• New Hires YTD (6/30/14): 17• Terminations YTD (6/30/14): 15

Headcount 6/30/14: 571• RTO Headcount: 544 (23 vacancies)• RE Headcount: 27 ( 4 vacancies)• Vacancy rate: 4.5%

2014 Headcount

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Turnover YTD Terminations (6/30/2014):

VoluntaryResignations – 8Retirements – 6InvoluntaryTerminations – 1

YTD Turnover Ratio: 1.5%(Excludes Retirements)

Past 12 months , ending (6/30/2014):Voluntary Resignations – 27Retirements – 6InvoluntaryTerminations – 3Total separations=36

Past 12 months Turnover Ratio: 5.3%(Excludes Retirements)

Average length of service of employees leaving (not including retirees) = 4 years

Average age of employees leaving = 38

27

8

6

6

3

1

12 Months ending06/30/14

Year to Date 2014

Resignations RetirementsInvoluntary

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Age of Workforce

<30 79

14%

30-3917230%

40-49 17430%

50-5911220%

>60346%

6% of SPP workforce is within five years of retirement age

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Years of Service

55%31%

14%

0 – 5 years6 – 9 Years

10 + years

55% of SPP employees have 5 years or less, of service with SPP

The average length of service = 6.5 years

Employee Average Age = 42

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Corporate Training MetricsInstructor-Led Training

– 5 Management classes

– 15 All Staff Courses

– 47 Self Study Courses

– Training to support market go-live “Make the Right Call” – 584 trainees

– SPP Leadership Conference – 466 attendees

The Learning Center (LMS)

SPP Member Users – 2,045 2,045 individuals from SPP members have logged into LMS

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Goals:

• Integrate importance of health and nutrition into SPP culture

• Healthier workforce that is more effective and engaged

• Reduce time off for illness

• Reduce costs of medical plan

Program YTD Statistics:

– 329 enrollments in on-line program; 560 activity trackers sold at half retail cost to employees and spouses

– 1,221 pounds lost since program start date (January 15, 2014)

– Wellness events scheduled with community partners at no cost to SPP

Wellness Update

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HR Alignment with SPP Strategic Plan

• HR Staff conducted SWOT Analysis (Strengths, Weaknesses, Opportunities and Threats) of department and programs

• Staff identified solutions and strategies and how those align with SPP corporate goals

• Committee challenged staff to:– Create metrics to measure program success

– Develop mechanism to report value to SPP members

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Next Meetings

• September 10, 2014– Location: Little Rock, Arkansas – SPP Corporate Campus

• October 22, 2014– Location: Chicago O’Hare Airport – Admirals Club

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Finance Committee Report

July 29, 2014

Harry Skilton – ChairTom Dunn

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

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SPP Finance Committee

ACTIVITIES

• Retirement Fund Management

• Director and Officer Insurance

• Gap Period Controls Audit

• 2015 Budget Outlook

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Retirement Fund Management

• Pension fund assets now total approx. $45 million– New manager, Stephens Capital Management, engaged

March 4, 2014

– Portfolio transition to “core/satellite” strategy nearly complete

– Returns consistent with benchmarks

– Committee requested enhanced reporting on portfolio volatility and fixed income credit quality

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Director and Officer Insurance

• Performed review of policy terms and conditions

• Benchmarked policy structure and limit levels against peers, members, general industry

• Reviewed indemnification protections provided by tariff

• Evaluated purchasing stand-alone employment practices policy to provide more “pure” D&O protection to Company and insureds

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Gap Period Controls Audit

• Received report from SPP Internal Audit on controls review for period November 1, 2013 – February 28, 2014

• This period was not covered by audits performed by PWC or KPMG

• Internal Audit report was thorough and did not indicate any control gaps during the period

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2015 BUDGET OUTLOOK

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2015 Budget Outlook

$0.000

$0.100

$0.200

$0.300

$0.400

$0.500

2004 2007 2010 2013 2016 2019 2022

2014 Budget

Admin Fee Forecast Admin Fee Admin Fee Cap Forecast Admin Fee Cap

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2015 Budget Outlook

$0.000

$0.100

$0.200

$0.300

$0.400

$0.500

2004 2007 2010 2013 2016 2019 2022

2014 Budget

Admin Fee Forecast Admin Fee Admin Fee Cap Forecast Admin Fee Cap

$0.000

$0.100

$0.200

$0.300

$0.400

$0.500

2004 2007 2010 2013 2016 2019 2022

July 29, 2014 BOD Meeting Forecast

Historical Admin Fee Rate 2014 Budget Forecast Admin Fee Rate Cap

Current Rate Cap Mid Year 2014 Forecast

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2015 Budget Outlook

Summary• Administrative Fee Forecast:

• 43.1¢/MWh in 2015• 36.5¢/MWh in 2016

• SPP Management addressing expense levels through remainder of 2014 – return to budget levels

• SPP Finance Committee evaluating opportunities to “smooth” forecast rate reduction

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2015 Budget Outlook

Thank You

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2015 Budget Outlook

0

50

100

150

200

250

300

PJM MISO NEISO ERCOT CAISO NYISO SPP -13 SPP - 14

Admin Revenue

12

2015 Budget Outlook

-8

-6

-4

-2

0

2

4

6

2004 2007 2010 2013

$ M

illio

ns

NRR Variance to Budget

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2014 Financial Surprises

Forecast Budget VarianceTariff Admin 134.1$ 132.6$ 1.5$ NITS running 1% above budget; PtP running 9% below 2013 levelsFERC 14.7 14.5 0.2 RE 9.6 11.8 (2.2) $0.7 in overhead contribution lost due to lower staffingOther 4.6 4.4 0.2

163.0$ 163.3$ (0.3)$

S&B 84.6 82.3 (2.3) $4 bonus in MayFERC 16.3 15.3 (1.0) Comm 3.8 3.9 0.1 Maintenance 15.8 15.9 0.1 Services 15.7 14.6 (1.1) Ops support for IM,Admin 4.6 4.9 0.3 Travel 2.9 3.1 0.2 Interest 10.1 11.0 0.9 Delayed funding $70 loanDebt Pmts 13.0 13.0 -

166.8$ 164.0$ (2.8)$

NRR 136.3$ 132.5$ (3.8)$

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Skirvin Hilton, Oklahoma City, OK April 29, 2014

- Summary of Action Items -

1. Approved Markets and Operations Policy Committee’sStaff’s recommendation as awarded amended

that the Board of Directors approve the HPILS Report and direct issuance of NTCs/NTC-Cs as shown in Appendix C. Direct Staff to affirm continued need for all recommended NTCs/NTC-Cs in the 2015 ITP assessments and subsequent assessments. Direct the RTWG to draft Tariff language that incorporates process for application of remedies including those included in the RCAR report. Direct the ESWG to evaluate options for allocating the Reliability metric and recommend best option. The members in whose systems additional HPILS loads and assumed generation additions reside will provide updated forecasts of these loads and generators prior to each subsequent quarterly meeting of the SPP Board, and in addition, will notify the SPP staff immediately upon receipt of any information that, in their judgment, would impact the need for one or more of the previously issued NTCs.

2. Approved Consent Agenda items:

a. Approve January 28, 2014 minutes b. Approve Markets and Operations Policy Committee Recommendations:

i. TWG: KCP&L Sponsored Upgrade ii. MWG: MCRR200 FERC Compliance Filing

MPRR 144, 165, 171 iii. RTWG: TRR 118, 121, 122, 124 iv. Staff: Novation from ITC/PSO to OK Transco

c. Finance Committee i. Annual Financial Audit ii. Benefit Plan Funding

3. Approved Markets and Operations Policy Committee’s recommendation that the Board of Directors

approve NTC No. 200166 be suspended for the project Randall – South Georgia 115 kV (Project ID No. 1033). The suspension will be in effect until Staff completes a re-evaluation of the project using updated reliability models.

4. Approved Markets and Operations Policy Committee’s recommendation that the Board of Directors approve NTC No. 20130 be suspended for the project Randall Co. – South Georgia and Osage Station Line Re-termination (Project ID No. 1001). The suspension will be in effect until Staff completes a re-evaluation of the project using updated reliability models.

5. Remanded Markets and Operations Policy Committee’s recommendation for further consideration

regarding revisions to Criteria Section 12 as noted in CRR012.

MINUTES NO. 158


Skirvin Hilton, Oklahoma City, OK April 29, 2014

Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 8:04 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. Mo Doghman, Omaha Public Power District Mr. Jim Eckelberger, director Mr. Kelly Harrison, Westar Energy 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. Dave Osburn, Oklahoma Municipal Power Authority 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 139 persons in attendance either in person or via phone representing 30 members (Attendance List - Attachment 1). Mr. Nick Brown declared there was a quorum. Mr. Eckelberger said the agenda would be shifted due to a request from the Regional State Committee (RSC) Commissioners. It was asked that the Markets and Operations Policy Committee (MOPC) report at the beginning of the meeting. After the Board meeting there will be an Executive Session to which Mr. Eckelberger invited the Members Committee and the Board. Mr. Eckelberger thanked the many former members of the RSC for coming to the meeting for the 10th Anniversary for the RSC. He welcomed guests Mark Gabriel and Bob Harris (Western), Chris Turner (SPA), Scott Henry (SERC), and Mel Perkins and thanked them for attending the meeting. Mr. Eckelberger said that there were no proxies. Agenda Item 5 – Markets and Operations Policy Committee Report

Mr. Rob Janssen provided the Markets and Operations Policy Committee report (MOPC Report – Attachment 13). Mr. Janssen introduced Mr. Lanny Nickell and asked him to give the High Priority Incremental Load Study (HPILS) presentation. Along with the discussion Mr. Julian Brix suggested an amendment to the Staff’s recommendation. Following considerable discussion Mr. Janssen Nickell gave an overview of the following action item and recommendation along with the amendment for approval:

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SPP Board of Directors/Members Committee Minutes April 29, 2014 1) Approve HPILS Report and direct issuance of NTCs/NTC-Cs as shown in Appendix C. 2) Direct Staff to affirm continued need for all recommended NTCs/NTC-Cs in the 2015 ITP assessments and subsequent assessments. 3) Direct the RTWG to draft Tariff language that incorporates process for application of remedies including those included in the RCAR report. 4) Direct the ESWG to evaluate options for allocating the Reliability metric and recommend best option. 5) The members in whose systems the additional HPILS loads and assumed generation additions reside will provide updated forecasts of these loads and generators prior to each subsequent quarterly meeting of the SPP Board, and in addition, will notify the SPP staff immediately upon receipt of any information that, in their judgment, would impact the need for one or more of the previously issued NTC. Mr. Eckelberger asked that a vote be taken to approve the MOPC’s Staff’s recommendation as amended. Mr. Brix moved to approve the HPILS Report; Mr. Harry Skilton seconded the motion. The Members Committee voted with two voting no and one abstention. The Board voted; the motion passed. Agenda Item 4 – Oversight Committee Report

Looking Forward Report

Mr. Craig Roach from Boston Pacific presented the Looking Forward Report (Looking forward Report – Attachment 11). Mr. Roach discussed the strategic issues that may be affecting Southwest Power Pool (SPP) beyond the next year. Agenda Item 2- Board Reports

Regional State Committee Report

RSC President Donna Nelson (PUCT) presented the Regional State Committee (RSC) report. At the RSC educational session held on Monday there was a presentation from a producer in the Bakken shale area of the Integrated System. The High Priority Incremental Load recommendation was reviewed. The group also discussed the plans for the Integrated System (IS) to become members of SPP. At the RSC meeting the Cost Allocation Working Group (CAWG) presented its update, focusing on reviewing the new wind accreditation. They did not take a position, but recommended that should the SPP Board change the wind number, SPP should review the capacity margin, any effect on potential transmission needs, and should continue to monitor the actual performance of wind and solar facilities. The RSC Bylaws were amended so that the educational sessions and retreats may be conducted in closed session. A special meeting is scheduled in Dallas on May 27th to further discuss the IS integration as it impacts the RSC. The RSC adopted MPRR 171, a clarification to Long Term Congestion Rights, and endorsed the lessons learned regarding the RCAR process. There was additional, robust, and respectful discussion regarding HPILS. There were presentations on the seams issues, Order 1000, the Integrated Marketplace, the strategic planning process and the FERC technical conference on the 2013-14 winter operations. Agenda Item 4 – Oversight Committee Report

2013 State of the Market Report

Mr. Martin introduced Mr. Alan McQueen to give the State of the Market Report (2013 State of the Market Report - Attachment 10). Mr. McQueen provided the report, noting no areas of concern from the Market Monitor as the existing market drew to a close, and preliminary results from the new markets are very good. Agenda Item 2- Board Reports

Regional Entity Trustees Report

Mr. John Meyer gave the Regional Entity (RE) Trustees report (RE Trustees Report – Attachment 6). In addition to the presentation Mr. Meyer reported that 200 people attended the most recent workshop, and the RE won an award for their online video library which describes different issues on compliance. The 2015 preliminary budget is basically flat, with $80,000 increase out of an $11 million budget. The violations have leveled off and are starting downward trends. There will be a June 17th meeting in Little Rock to consider

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and approve the 2015 budget. SPP Board of Directors/Members Committee Minutes April 29, 2014 Federal Energy Regulatory Committee Report

Mr. Patrick Clarey provided the FERC Report. On April 1, FERC hosted a Commission-led technical conference on Winter 2013-2014 Operations and Market Performance in Regional Transmission Organizations and Independent System Operators. The conference explored the impacts of recent cold weather events on the RTOs and discussed actions taken to respond to those impacts. Mr. Clarey expressed appreciation for Chair Nelson’s and SPP’s participation in this conference. Written public comments may be submitted regarding the conference until May 15, 2014. On March 4, the Commission submitted its FY2015 Budget Request and FY 2014-2018 Strategic Plan to Congress. The 2015 request is for $327 million up from $304 million in 2014 with a net appreciation of $0 due to offsetting collections from annual charges. FERC initiated further steps to improve the coordination and scheduling of natural gas pipeline capacity with electricity markets in light of increased reliance on natural gas by electric generators. The steps include: a Notice of Proposed Rulemaking (NOPR) to seek public comments on proposals to revise the natural gas operating day and scheduling practices used by interstate pipelines to schedule natural gas transportation service; proceedings under the Federal Power Act (FPA) and Natural Gas Act (NGA) to ensure that these entities’ scheduling practices correlate with any revisions to the natural gas scheduling practices that may be adopted by the NOPR; and an NGA Section 5 Show Cause proceeding requiring all interstate natural gas pipelines to revise their tariffs to provide for the posting of offers to purchase released pipeline capacity in compliance with Commission’s regulations. In late March FERC addressed multiple dockets involving a dispute between MISO and SPP regarding the JOA between the two organizations and transfers between MISO South and classic MISO. FERC accepted and suspended for filing subject to refund a Service Agreement, as well as consolidated various related complaints between the two RTOs and set those for hearing and settlement judge proceedings, the first of which is being held today, April 29. Following is a message from Acting Chair Cheryl LaFleur- "Congratulations to the SPP RSC on your 10-year anniversary. One of the early meetings I attended as a Commissioner was the SPP RSC. I learned more than I could ever have imagined about the Lesser Prairie Chicken, and I also learned so much about how the RSC operates. I was very impressed by how well you worked together, the engagement of the members, and the substance of the discussion. Just last year I was able to visit SPP’s new control center, and I continue to be impressed by the strides SPP is making, most notably with the commencement of the new market. It’s an important and exciting time to be involved with SPP. Congratulations again on your milestone anniversary." Agenda Item 4 – Oversight Committee Report Oversight Committee Report

Mr. Josh Martin finished the OC report: The Committee met in Washington DC in March.

• The Committee heard quarterly reports from Internal Audit, Compliance, and Market Monitoring staff. o Internal Audit continues its regular audits. The staff has been working with the new controls

auditors, KPMG, as they initiate their work at SPP. In addition, Internal Audit is covering the “gap” controls audit period for the EIS market; that report will be presented to the Finance Committee and Board upon completion.

o A Compliance Forum was held in February in Dallas. It was well-attended. The next Forum will be in Little Rock in June, and focused on CIP requirements. At members’ requests, a seminar was offered on Subject Matter Expert preparation for audits. Participation was very strong, and a video version has been produced and posted for continued use. Compliance will spend more time on spot checks, especially related to the new Balancing Authority requirements.

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SPP Board of Directors/Members Committee Minutes April 29, 2014

• The Committee received and reviewed the Memo of Authority provided each year from Carl Monroe as COO to the Reliability Coordinators, clarifying their authority in regard to operation of the grid, specifically the authority to call for load shedding in the appropriate circumstances. This is posted in the Operations Center, as required.

• The Committee received an updated review of its role in the Order 1000 process. A great deal of work has been done for this, but questions remain and details continue to be worked through.

• The Committee had two presentations for the meeting today, which we have heard. There is also a presentation for Order 1000 processes (Order 1000 Process – Attachment 12), specifically the Oversight Committee’s role, included in the materials for the meeting. If there are questions, please direct those to Paul Suskie.

The Oversight Committee’s next scheduled meeting is June 9 in Little Rock. After the lunch break committee member Kelly Harrison had to leave for the day, and gave his proxy to Dennis Reed (Attachment 2). Agenda Item 3 – Consent Agenda

Mr. Eckelberger presented the following Consent Agenda items for approval (Consent Agenda – Attachment 9):

d. Approve January 28, 2014 minutes e. Approve Markets and Operations Policy Committee Recommendations:

i. TWG: KCP&L Sponsored Upgrade ii. MWG: MCRR200 FERC Compliance Filing

MPRR 144, 165, 171 iii. RTWG: TRR 118, 121, 122, 124 iv. Staff: Novation from ITC/PSO to OK Transco

f. Finance Committee i. Annual Financial Audit ii. Benefit Plan Funding]

Mr. Eckelberger asked for requests to remove any items from the Consent Agenda. Hearing no requests, he then asked for a motion to approve. Mr. Larry Altenbaumer moved to approve the Consent Agenda items; Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Agenda Item 2- Board Reports

Finance Committee Report

Mr. Harry Skilton provided an update on the Finance Committee activities (FC Report – Attachment 7). Mr. Skilton reported that the FC has met twice since the last Board Meeting. The FC wanted enough time to get into the Credit Practices and business improvements. SPP received a clean report from the financial audit. If you have any specific questions concerning the audit contact Mr. Skilton or Mr. Tom Dunn. Mr. Skilton briefly discussed the benefit plan contributions, for which the FC just approved a $3.66 million contribution. Agenda Item 5 – Markets and Operations Policy Committee Report

Mr. Janssen resumed the remaining MOPC report (MOPC Report – Attachment 13). Mr. Janssen reported that there are two additional items to be presented and voted on: NTC suspension coming out of Project Tracking, and the proposed change in the Criteria as recommended by the Generation Working Group (GWG). Project Tracking – Suspension of two NTCs

Mr. Lanny Nickell provided background on two separate projects: (NTC) No. 200166 to Southwest Public Service Company (SPS) to reconductor a 4.1-mile section of the 6.1-mile 115 kV line from Randall Co. to

5

South Georgia. The project was identified in the 2012 ITP Near-Term Assessment as needed for reliability in 2017. (NTC) No. 20130 to SPS for a project that included a new 2-mile 115 kV line from Osage Station to SPP Board of Directors/Members Committee Minutes April 29, 2014 Randall Co., the re-terminations of the South Georgia – Osage Station and Canyon East – Osage Station 115 kV lines into Randall Co., the removal of the 115 kV line from Osage Station to Manhattan Tap, and the reconfiguration of the Randall Co. substation to a breaker-and-a-half scheme. The project was identified in the 2010 regional reliability assessment as needed in 2016 to address overloads in the area for multiple contingencies. Mr. Janssen asked that the Board of Directors approve MOPC’s recommendations that NTC No. 200166 and NTC No. 20130 both be suspended. Mr. Larry Altenbaumer moved to approve the suspensions; Mr. Julian Brix seconded the motion. The Members Committee voted in unanimous approval. The Board voted; the motion passed. Generation Working Group Criteria 12

Mr. Mitch Williams, Chair of the GWG reported on the recommendation for the SPP capacity accreditation methodology for wind and solar resources. These changes are made to SPP Criteria 12.1.5.3.g and included in CRR-012. After much discussion Mr. Eckelberger asked that if there were no objections from the Board or Members Committee he would like to send the item back to the MOPC for consideration of maximum and minimum caps and make sure an answer is developed that people are supportive of, including the Operating Reliability Working Group (ORWG). There were no objections to this suggestion. Mr. Janssen reported that Oklahoma Gas and Electric Company (OG&E) requested a brief update on calculating Z2 credits. Staff identified some issues with the software and they are being worked through. Credits should be ready to be distributed by June 1. Agenda Item 2 – Board Reports

President’s Report

Mr. Nick Brown introduced Mr. Bruce Rew and shared his personal appreciation for Mr. Rew for his leadership and effort in facilitating the success of the Integrated Marketplace. Mr. Rew provided a report on the Integrated Marketplace (Integrated Marketplace Update – Phase I – Attachment 4). The group is working on metrics for reporting. He also reported that wind numbers are at an all-time high, running 25% of the region’s energy through wind right now. Mr. Rew expressed his appreciation to everyone who helped make the Integrated Marketplace a success. Mr. Brown introduced Ms. Barbara Sugg who will be the Phase II project manager to provide a status report (Phase II – Attachment 5). Ms. Sugg explained that Phase II is a collection of independent projects that are all competing with each other in terms of resources, what systems they are impacting, and when they are expected to go live. Some of the projects are FERC mandated and must be in place by March 1, 2015. Mr. Brown continued with his President’s Report (President’s Report – Attachment 3) referring to the copies of 2013 Annual Report and the theme this year, Engage. Mr. Brown expressed that we would not be successful as a member-driven organization without the significant engagement from our Board of Directors, Members Committee, and Membership. Mr. Brown felt we did a great job capturing all of the significant events of 2013 but would appreciate any feedback. Mr. Brown thanked Ms. Stacy Duckett and her staff on the success of the Annual Report. Mr. Brown reported on the Corporate Governance Committee (CGC). He explained that it is primarily focused on the modifications to the Bylaws and Membership Agreement for the membership of the Integrated System entities. There will be a conference call on May 1. Mr. Brown feels we are very close to completing an agreement. Mr. Brown discussed the special meetings that will take place June 9 for the Membership and the Board/Members Committee. The agenda is a work in progress and as information becomes available it will be sent out. Mr. Brown discussed how fortunate we are to have a long tenured Board. There has been no turn-over in the Board for the last six years. The Board recently determined to make some changes in committee

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assignments: Ms. Phyllis Bernard was the Chair of the Human Resources (HR) Committee and is moving to the Strategic Planning Committee (SPC). Mr. Martin is moving from the SPC to the HR Committee. Mr. Brix will be taking over as the Chair of the HR Committee. We invite all of our Board Members to attend at least one meeting of a committee to which they are not assigned. Mr. Brown reported on some staff changes. Southwest Power Pool (SPP) has a relatively young staff. We currently know of seven employees that have or are retiring this year. One staff member in particular is going to impact everyone involved on the Board and Members Committee. Ms. Cheryl Robertson has been with SPP for 14 years. Her institutional knowledge is phenomenal. Mr. Brown presented Ms. Robertson with a Resolution for her years of service and dedication. Due to time the Strategic Planning Committee report was not given but a written report is attached (Attachment 8) Agenda Item 6 – Future Meetings Mr. Eckelberger reminded the group of the SPP Board of Directors future meetings including the Special Meetings for the Board/Members Committee and Membership on June 9 to finalize the IS documents for filing for their membership in SPP. (Future Meetings – Attachment 14). Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned the meeting to Executive Session at 2:04 p.m. Executive Session

• The Board considered waiver requests from two members. One request was declined; one was approved.

• The Board approved additional compensation to be distributed to staff in appreciated for the successful implementation of the Integrated Marketplace on March 1.

Members Committee member Michael Deggendorf had to leave the meeting and gave his proxy to Denise Buffington (Attachment 2).

Stacy Duckett, Corporate Secretary

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Southwest Power Pool SPECIAL BOARD OF DIRECTORS/MEMBERS COMMITTEE MEETING

Southwest Power Pool Corporate Offices, Little Rock, AR

June 9, 2014 Agenda Item 1 - Administrative Items SPP Chair Mr. Jim Eckelberger called the meeting to order at 1:18 p.m. There were 75 people in attendance either in person or via phone representing 24 members (Attendance List – Attachment 1). Stacy Duckett reported proxies (Proxies – Attachment 2).

Mr. Larry Altenbaumer, director Ms. Phyllis Bernard, director Mr. Ricky Bittle, Arkansas Electric Cooperative Mr. Julian Brix, director Ms. Denise Buffington, proxy for Mike Deggendorf, Kansas City Power and Light Mr. Tom Burke, proxy for Mike Wise, Golden Spread Electric Cooperative Mr. Phil Crissup, Oklahoma Gas and Electric Mr. Mo Doghman, Omaha Public Power District Mr. Jim Eckelberger, director Mr. Kelly Harrison, Westar Energy Mr. Rob Janssen, Dogwood Energy; also proxy for Brett Kruse, Calpine Energy Services Mr. Tom Kent, Nebraska Public Power District Mr. Jeff Knottek, City Utilities of Springfield Mr. Josh Martin, director Mr. Dave Osburn, Oklahoma Municipal Power Authority 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

Agenda Item 2 – SPP Membership Agreement and Bylaws Amendments Mr. Eckelberger reminded everyone that the project of working with the Integrated Systems (IS) has taken over two years. It was a process that took a lot of work and he expressed his thanks to the IS representatives for their hard work as well. He went on to reference the memo from the Regional State Committee (RSC) chairman, (CAWG Report for the Special Meeting – Attachment 3). The RSC expressed concern and suggested we review the processes in which this kind of change occurs. Mr. Eckelberger is going to hand this over to the Strategic Planning Committee (SPC) to take the action and review the process. He would also like the Membership to be involved along with the Business Practices Working Group (BPWG) and then advance through to the other groups. He wants to make sure there is equity throughout all of the working groups. Mr. Eckelberger then passed the meeting to Mr. Carl Monroe. Mr. Monroe started his presentation by discussing the introduction of the IS, the process, cost and benefits, and major components of suggested changes (IS Introduction to the BOD – Attachment 4). Mr. Eckelberger asked for a motion for approval of the amendments for Integrated System entities as detailed in the attachments (Amendment to Bylaws – Attachment 5). Mr. Julian Brix made the motion and Mr. Harry Skilton seconded it. Ms. Stacy Duckett explained that when these materials were posted not all of the changes showed up so she went through the changes with the group (Attachments 6,7,8,9,10). There were no further comments so Mr.

Special SPP Board of Directors/Members Committee Minutes June 9, 2014 Eckelberger called for the vote. The Members Committee voted in favor with three four five abstentions (Westar Energy, Kansas City Power and Light, American Electric Power, City Utilities of Springfield and Oklahoma Gas and Electric). The Board voted and the motion passed. Agenda Item 3 – MOPC Report/SPP Tariff Revisions Mr. Rob Janssen gave the Market Operations Policy Committee (MOPC) report discussing the Tariff revisions (MOPC Report to the BOD – Attachment 11). The Regional Tariff Working Group (RTWG) and Market Working Group (MWG) were tasked with developing Tariff and Protocol changes based on policies negotiated by SPP Staff and the IS Parties. While presented together, Tom Kent from Nebraska Public Power District (NPPD) requested that TRR 123 be considered separately. Mr. Eckelberger asked for a motion to approve TRR 123 representing the Tariff changes required to implement the integration of the IS entities, (Western-UGP, Basin, Electric & Heartland) into SPP pursuant to the policies presented to MOPC. The RTWG will have the ability to modify Attachment L II.B.2 h to set eligibility for revenue distribution to loads represented on October 1, 2015. Mr. Julian Brix moved to approve the motion Ms. Phyllis Bernard seconded the motion. The Members Committee voted in favor with five abstentions (American Electric Power, Oklahoma Municipal Power Authority, Westar Energy, City Utilities of Springfield, and Kansas City Power and Light) and two one against (Nebraska Public Power District and Kansas City Power and Light). The Board voted and the motion passed. Mr. Eckelberger recommended the remaining items be voted on together in a consent agenda format. There was no objection. The MOPC recommendations for the Board to approve TRR 129 Attachment AN revisions, as representing the Tariff changes required to implement the integration of the IS entities (Western-UGP, Basin Electric & Heartland) into SPP pursuant to the policies presented to the MOPC; approve TRR 130 Attachment V revisions, as representing the Tariff changes required to implement the integration of the IS entities (Western-UGP, Basin Electric & Heartland) into SPP pursuant to the policies presented to the MOPC; and approve MPRR 180 revisions, as representing the Tariff changes required to implement the integration of the IS entities (Western-UGP, Basin Electric & Heartland) into SPP pursuant to the policies presented to the MOPC. Mr. Larry Altenbaumer made a motion to approve TRR 129 and 130 and MPRR 180; Mr. Josh Martin seconded the motion. The Members Committee voted in favor with four abstentions (American Electric Power, Westar Energy, City Utilities of Springfield, and Kansas City Power and Light). The Board voted and the motion passed Adjournment With no further business, Mr. Eckelberger thanked everyone for participating and adjourned at 3:03 p.m.

Stacy Duckett, Corporate Secretary

2


MARKETS AND OPERATIONS POLICY COMMITTEE Recommendation to the Board of Directors

MPRRs 173, 178, 183 and 190 July 29, 2014

Organizational Roster

The following members represent the Market Working Group:

Richard Ross, AEP, Chairman Gene Anderson, OMPA, Vice Chairman Shawn McBroom, 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. Marguerite Wagner, Boston Energy Trading & Marketing Ron Thompson, NPPD Bruce Walkup, AECC Rick Yanovich, OPPD Debbie James, SPP, Secretary

Background

Please see the MPRR Recommendation Report for MPRRs 173, 178, 183, and 190 that were included in the MOPC July 15-16, 2014 background materials.

Analysis

Please see the MPRR Recommendation Report for MPRRs 173, 178, 183, and 190 that were included in the MOPC July 15-16, 2014 background materials.

Recommendation

The MOPC recommends that the BOD approve its request regarding Marketplace Protocol Revision Requests 173, 178, 183, and 190.

Action Requested: Approval of MWG’s request on 173, 178, 183, and 190

3.b.i.1 - MWG MPRR Recommendations to MOPC_20140715-16 Page 1 of 2

APPROVED: MOPC July 15-16, 2014 MPRR 173 Passed Unanimously with two abstentions-ITC Great Plains & Calpine MPRR 178 Passed Unanimously MPRR 183 Passed Unanimously MPRR 190 Passed w/Modifications unanimously with two abstentions-ITC Great Plains & Calpine

MPRR Number

Description

MWG Meeting Vote

RTWG Meeting Vote

ORWG Meeting Vote

MPRR 173 Physical Withholding Screen

4/22/2014 – Approved TNSK – Opposed

6/17/2014 – Unanimously Approved

RTWG modifications

5/23/2014 – Approved with modifications

5/8/2014 – Approved

MPRR 178 DVER and NDVER Operating Limit Clarification

5/20/2014 – Unanimously Approved

6/25/2014 – Unanimously

Approved

6/19/2014 – Approved

MPRR 183 Re-pricing Clarification 5/20/2014 – Approved

Boston Energy - abstained

6/25/2014 – Approved with modifications

6/19/2014 – Approved with no

Reliability Impacts

MPRR 190 MWP Start-Up Offer Recovery Eligibility

Clarifications

6/27/2014 – Approved WR, OGE – opposed

Exelon, Boston Energy, Xcel, OPPD –

abstained

7/1/2014 –

Approved with no Reliability Impacts

3.b.i.1 - MWG MPRR Recommendations to MOPC_20140715-16 Page 2 of 2

PRR Recommendation Report PRR No. 173 PRR

Title Physical Withholding Screen

Timeline Normal Expedited Urgent Action

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

Recommendation Action

Approve Reject

Require additional information

Defer Refer

Rating-Ranking Rating – Ranking Rating: 1 – FERC Compliance 2 – Defect

N/A – N/A 3 – Member Request 4 – Other

Impact Analysis Required Yes – If yes, estimated cost: No

SPP Staff will complete this section.

Protocol Section(s) Requiring Revision

Section No.: 8.2.6; 8.2.6.1; 8.2.6.3 Title: Physical Withholding; Thresholds for Identifying Physical Withholding of Resource Capacity; Sanctions for Physical Withholding Protocol Version: 19.1a

Type of Revision Correction/Clean-Up Clarification

Design Enhancement Design Change

Revision Description

For resources in both Frequently Constrained Areas (FCAs) and outside FCAs, the revision inserts both local market power and price and make whole payment impact criteria. It also clarifies that resources off dispatch must exceed the URD threshold to be considered for potential withholding. The requirement to report all screen failures to FERC is modified to a requirement to report all suspected physical withholding. This also exempts VERs from the Physical Withholding process in the Day-Ahead Market.

Tariff Implications or Changes

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

Attachment AG Section 4.6.4 Physical Withholding; 4.6.4.1 Thresholds for Identifying Physical Withholding of Resource Capacity; 4.6.4.3 Sanctions

No

Criteria Impact or Changes


No

MWG Review PRR Recommendation

Date of Vote: 4/22/2014 Vote: Approved

Opposed: TNSK

Abstained: N/A

Date of Vote: 6/17/2014 Vote: Approved RTWG modifications

Opposed: N/A

Abstained: N/A

RTWG Review Date of Vote: 5/23/2014 Vote: Approved with modifications

3.b.i.2 - MWG MPRR 173 Recommendation Report 6/17/2014 Page 1 of 6

Opposed: TNSK

Abstained: EDE ORWG Review Date of Vote: 5/8/2014 Vote: Approved

MOPC Recommendation Date of Vote: Vote:

Board Review Date of Vote: Vote:

Date 4/4/2014

Sponsor Name Catherine Tyler Mooney and John Hyatt E-mail Address [email protected] and [email protected] Company SPP Market Monitoring Phone Number 501.688.8249 and 501.688.1630

Reasons for Opposing Dissenter John Varnell, TNSK Date 4/22/2014

Reason TNSK believes that the Asset Owner should be the one who is deemed physical withholding and not the Market Participant.

Comments Received

Comment Author Micha Bailey on behalf of MWG Date 4/22/2014

Comment Description MWG added “the Dispatch Instruction minus” to the withholding sections in the Protocols and Tariff. The added language helps clarify how a Resource operating in real-time could be withholding.

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

Comments Received

Comment Author Brenda Fricano on behalf of RTWG Date 5/23/2014

Comment Description RTWG made some clarifications to the Tariff in this MPRR which include grammar corrections, section reference corrections and rephrasing sentences.

Comment Status

Proposed Protocol Language Revision

8.2.6 Physical Withholding

The Market Monitor will monitor for physical withholding of capacity from the Energy and Operating Reserve Markets, and unavailability of transmission facilities. Physical withholding may include,

(1) Declaring that a Resource has been derated, forced out of service or otherwise been made unavailable for technical reasons that are untrue or that cannot be verified;

(2) Refusing to provide offers or schedules for a Resource when it would otherwise have been in the economic interest to do so without market power;




(3) Operating a Resource in real-time to produce an output level that is less than the Dispatch Instruction minus the Resource’s Operating Tolerance defined in Section 4.4.4.1 and the Resource is not exempt from URD under Section 4.4.4.1.1.less than the dispatch instruction;

(4) Derating a transmission facility for technical reasons that are not true or verifiable; and

(5) Operating a transmission facility in a manner that is not economic and that causes a binding transmission constraint or binding reserve zone or reliability issue.

Market Participants will not be deemed to be physically withholding if they are following the directions of the SPP Consolidated Balancing Authority or applicable reliability standards. In addition, Market Participants will not be determined to have physically withheld if they are selling into another market at a higher price. Variable Energy Resources will not be determined to be physically withheld in the Day-Ahead Market under the conditions in 8.2.6 (1) – (2).

8.2.6.1 Thresholds for Identifying Physical Withholding of Resource Capacity

A Market Participant is deemed to be physically withholding capacity in a Frequently Constrained Area if the following conditions hold:

(1) One or more of the transmission constraints or Reserve Zone constraints that define the Frequently Constrained Area are binding;

(2) The Market Participant controls or owns a Resource located in the Frequently Constrained Areathat satisfies condition 8.2.6(1), 8.2.6(2), or 8.2.6(3) and is located in the Frequently Constrained Area identified in (1);

(2)(3) The Market Monitoring Unit determines that the withheld capacity has impacts on prices or make-whole payments that exceed the Market Impact Test thresholds in Section 8.2.2.9.

A Market Participant is deemed to be physically withholding capacity in an area not designated as a Frequently Constrained Area if the following conditions hold:

(1) One or more transmission constraints are binding or a Reserve Zone is binding; and

(1)(2) The Market Participant owns or controls one or more Resources that has local market power as defined in Section 8.2.2.7; and

(2)(3) The Market Participant owns or controls a Resource where either of (a) or (b) hold; h8.2.2.7Either of (a) or (b) hold;

(a) The total capacity withheld, by the Resources identified in (2) that satisfy condition 8.2.6(1) or 8.2.6(2) exceeds the lower of 5 percent of the total capability owned or controlled by the Market Participant or 200 MW;

(b) The real-time output of the a Resource identified in (2) is less than the Dispatch Instruction minus the Resource’s Operating Tolerance defined in Section 4.4.4.1 and the Resource is not exempt from URD under Section 4.4.4.1.1;


(4) The Market Monitoring Unit determines that the withheld capacity has impacts on prices or make-whole payments that exceed the Market Impact Test thresholds in Section 8.2.2.9.

8.2.6.3 Sanctions for Physical Withholding The Market Monitor will record instances where Market Participants have failed the physical withholding screens in Sections 8.2.6.1 and 8.2.6.2. and The Market Monitor will notify the Commission’s Office of Enforcement, or successor organization, of such suspected physical withholding behavior. In the event the Market Monitor determines there is credible evidence of a market violation, the Market Monitor shall make a referral to the Commission as described in Section 8.1.9.

Proposed Tariff Language Revision

Attachment AG

4.6.4 Physical Withholding

The Market Monitor will monitor for physical withholding of capacity from the

Energy and Operating Reserve Markets, and unavailability of facilities. Physical

withholding and unavailability of facilities may include:

(a) Declaring that a Resource has been derated, forced out of service or

otherwise been made unavailable for technical reasons that are untrue or

that cannot be verified;

(b) Refusing to provide offers or schedules for a Resource when it would

otherwise have been in the economic interest to do so without market

power;

(c) Operating a Resource in real-time to produce an output level that is less

than the Dispatch Instruction minus the Resource’s Operating Tolerance

defined in Section 6.4.1 of Attachment AE to this Tariff and the Resource

is not exempt from URD under Section 6.4.1.1 of Attachment AE to this

Tariffless than the dispatch instruction;

(d) Derating a transmission facility for technical reasons that are not true or

verifiable;

(e) Operating a transmission facility in a manner that is not economic and that

causes a binding transmission constraint or binding reserve zone or local

reliability issue; and


(f) Declaring that the capability of Resources to provide Energy or Operating

Reserves is reduced for reasons that are not true or verifiable.

Market Participants will not be deemed to be physically withholding if they are

following the directions of the SPP Balancing Authority, Reliability Coordinator,

or applicable reliability standards. In addition, Market Participants will not be

determined to have physically withheld if they are selling into another market at a

higher price. Variable Energy Resources will not be determined to be physically

withheld in the Day-Ahead Market under the conditions in Sections 4.6.4 (a),

4.6.4 (b) or 4.6.4 (f).

4.6.4.1 Thresholds for Identifying Physical Withholding of Resource

Capacity

4.6.4.1.1 A Market Participant is deemed to be physically withholding

capacity in a Frequently Constrained Area if all of the following

conditions exist:

(a) One or more of the transmission constraints or Reserve

Zone constraints that define the Frequently Constrained

Area are binding; and

(b) The Market Participant controls or owns a Resource located

in the Frequently Constrained Area that satisfies condition

4.6.4(a), 4.6.4(b), 4.6.4(c), or 4.6.4(f) of this Attachment

AG and is located in the Frequently Constrained Area

identified in (a).

(c) The Market Monitoring Unit determines that the withheld

capacity has impacts on prices or make-whole payments

that exceed the Market Impact Test thresholds in Section

3.7 of Attachment AF of this Tariff.

4.6.4.1.2 A Market Participant is deemed to be physically withholding

capacity in an area not designated as a Frequently Constrained

Area if all of the following conditions exist:

(a) One or more transmission constraints are binding or a

Reserve Zone is binding; and

(b) The Resource(s) meets either of the following criteria (1) or

(2); The Market Participant owns or controls one or more


Resources that have local market power as defined in

Section 3.1 of Attachment AF of this Tariff; and

(c) One of the following conditions apply:

(1) Such Resource(s) satisfy one of the conditions in

Sections 4.6.4(a), 4.6.4(b), or 4.6.4(f) of this

Attachment AG and the total withheld capacity

exceeds the lower of 5 percent of the total capability

owned or controlled by the Market Participant or

200 MW; or

(2) Where the real-time output of each such Resource is

less than the Dispatch Instruction minus the

Resource’s Operating Tolerance defined in

Attachment AE, Section 6.4.1 of this Tariff and the

Resource is not exempt from Uninstructed Resource

Deviation under Attachment AE, Section 6.4.1.1 of

this Tariff.

(d) The Market Monitoring Unit determines that the withheld

capacity has impacts on prices or make-whole payments

that exceed the Market Impact Test thresholds in

Attachment AF, Section 3.7 of this Tariff.

4.6.4.3 Sanctions

The Market Monitor will record instances where Market Participants have

failed the screens in Sections 4.6.4.1 and 4.6.4.2 of this Attachment AG. and The

Market Monitor will notify the Commission’s Office of Enforcement, or

successor organization, of such suspected physical withholding behavior. In the

event the Market Monitor determines there is credible evidence of a market

violation, the Market Monitor shall make a referral to the Commission as

described in Section 4.3 of this Attachment AG.

Proposed Criteria Language Revision N/A



Title DVER and NDVER Operating Limit Clarification




Approve Reject


Defer Refer






Section No.: 4.2.2.5.5, 4.2.2.5.6 Title: Dispatchable Variable Energy Resources, Non-Dispatchable Variable Energy Resources Protocol Version: 19.1




(1) The Markets User Interface has a validation to verify that minimum operating limits (emergency, economic, and normal) for an NDVER are zero MWs. The Protocols currently list only the Emergency and Economic Operating Limits but fail to mention Normal Operating Limits. (2) The Markets User Interface has a validation to verify that minimum operating limits (emergency, economic, and normal) for an NDVER are zero MWs. The DVER section has this validation, but this validation was inadvertently left out of the Protocols.



Attachment AE Section 4.1.2.5; Non-Dispatchable Variable Energy Resource

No



No


Date of Vote: 5/20/2014 Vote: Unanimously Approved

Opposed: N/A

Abstained: N/A

RTWG Review Date of Vote: 6/25/2014 Vote: Unanimously Approved

ORWG Review Date of Vote: 6/19/2014 Vote: Approved




Date 4/4/2014

Sponsor Name Jared Greenwalt E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.8314


4.2.2.5.5 Dispatchable Variable Energy Resources

The following rules apply to Resources registered as Dispatchable Variable Energy Resources (“DVER”):

(1) The Minimum Emergency Capacity Operating Limit, and Minimum Economic Operating Capacity Limit and Minimum Normal Capacity Operating Limit submitted as part of the Day-Ahead Market and/or RTBM Resource Offer must be submitted as zero MW. Otherwise, the Resource Offer will be rejected;

(2) For DVERs with an Emergency Maximum Capacity Operating Limit of less than 200MW, the maximum ramp rate between MW specified in the Ramp-Rate-Up Curve and Ramp-Rate Down Curve in the RTBM Resource Offer multiplied by 5 cannot exceed 40MW. For DVERs with an Emergency Maximum Capacity Operating Limit greater than or equal to 200MW, the maximum ramp rate between MW levels specified in the Ramp-Rate-Up Curve and Ramp-Rate-Down Curve in the RTBM Resource Offer multiplied by 5 cannot exceed 20% of the DVER’s Emergency Maximum Capacity Operating Limit;

(3) For the RUC processes, the maximum operating limit shall be the lesser of the Emergency Maximum Capacity Operating Limit as specified in the DVER RTBM Offer and SPP’s output forecast for that DVER. DVERs for which SPP is calculating an output forecast are not eligible to receive RUC make whole payments as described under Section 4.5.9.8;

(4) For the Real-Time Balancing Market, DVER Dispatch Instructions are calculated assuming the DVER is dispatchable regardless of its Control Status. DVERs eligible to clear Regulation-Down must submit a Control Status of “Regulating” if capable of providing Regulation-Down. SPP will provide a dispatch flag to the DVER indicating whether or not the DVER should “follow” or “ignore” its Setpoint Instruction. Use of these dispatch flags in calculating Setpoint Instruction is described under Section 4.4.3.1. These flags are set as part of the RTBM solution as follows:

(a) The default value of the dispatch flag will be “ignore”. When the dispatch flag is “ignore”, the DVER’s maximum operating limit is set equal to the DVER’s actual output at the time of the current RTBM run;



(b) The dispatch flag will be set to “follow” if (i) the DVER is dispatched below its maximum operating limit or (ii) the DVER is cleared for Regulation-Down;

(5) For the Real-Time Balancing Market for the current RTBM run, if the dispatch flag is “follow” as set by the previous RTBM run, then the DVER’s maximum operating limit in each subsequent Dispatch Interval is set equal to either:

(a) The lesser of (i) SPP’s output forecast for that DVER or (ii) the DVER’s Emergency Maximum Capacity Operating Limit; or

(b) The Emergency Maximum Capacity Operating Limit as specified in the DVER Offer if the SPP output forecast is not available for that DVER; or

(c) SPP’s output forecast for that DVER if the Emergency Maximum Capacity Operating Limit: (i) Was not submitted in the DVER Offer; or

(ii) Was not updated in the Offer during the Operating Hour prior to the Operating Hour in which the Resource limit would apply but before the lead time described in Section 4.2.2; or

(iii) Exceeds the maximum physical rating of the DVER that was submitted at market registration.

Such maximum operating limit continues to be set as described above until such time that the Resource’s Dispatch Instruction is equal to the maximum operating limit, after which, the DVER’s maximum operating limit is calculated as described under (4)(a) above.

4.2.2.5.6 Non-Dispatchable Variable Energy Resources

The following rules apply to Resources registered as Non-Dispatchable Variable Energy Resources (“NDVER”):

(1) The Minimum Emergency Capacity Operating Limit, Minimum Economic Operating Capacity Limit and Minimum Normal Capacity Operating Limit submitted as part of the Day-Ahead Market and/or RTBM Resource Offer must be submitted as zero MW. Otherwise, the Resource Offer will be rejected;

(1)(2) For the RUC processes, the maximum operating limit shall be as submitted in the Resource Offer, except that, for wind powered NDVERs, the lesser of the Resource Offer or SPP’s wind output forecast for that Resource shall be used to set the maximum operating limit;

(a) NDVERs for which SPP is calculating an output forecast are not eligible to receive RUC make whole payments as described under Section 4.5.9.8.

(2)(3) For the Real-Time Balancing Market, the Resource’s Energy Offer Curve shall not apply and offer prices shall be assumed equal to zero for the purposes of calculating production costs relating to RUC make-whole payments and cost allocation thereof under Sections 4.5.9.8 and 4.5.9.10. The Resource must operate within Setpoint Instructions. The Setpoint Instructions will


be an echo of actual SCADA output as updated every ten seconds. For NDVERs, the Control Status Mode is not required. If it is not provided, it will be set to Manual.

Proposed Tariff Language Revision ATTACHMENT AE

4.1.2.5 Non-Dispatchable Variable Energy Resource Each Market Participant may submit Resource Offers for Non-Dispatchable

Variable Energy Resources using the same Offer parameters available to any other

Resource, except that

(1) The minimum operating limits specified in the Resource Offer must be equal to

zero;

(12) For the RTBM, the Resource’s Energy Offer Curve shall not apply;

(23) For the RTBM, the Resource’s Dispatch Instruction shall be equal to the

Resource’s actual output at the start of the Dispatch Interval and the Resources

must operate as non-dispatchable;

(34) Resource Energy Offer Curve prices shall be assumed equal to zero (0) for the

purposes of calculating production costs relating to RUC make whole payments

and cost allocation thereof under Sections 8.6.5 and 8.6.7 of this Attachment AE;

(45) For the RTBM, during times when it is necessary to issue a Manual Dispatch

Instruction to a Non-Dispatchable Variable Energy Resource to resolve an

Emergency Condition or reliability issue, the Transmission Provider will direct

the Resource to a specified MW output. In addition, the Transmission Provider

will issue the dispatch instruction to the Resource in accordance with Section

6.2.4 of this Attachment AE; and

(56) The maximum operating limits for use in the Day-Ahead RUC and the Intra-Day

RUC shall be calculated by the Transmission Provider as equal to the lesser of the

maximum operating limits submitted in the Resource Offer or the Transmission

Provider’s output forecast for that Resource to the extent that such output forecast

is available, otherwise the maximum operating limits shall be equal to those

submitted in the Resource Offer;


(a) Non-Dispatchable Variable Energy Resources for which the Transmission

Provider is calculating an output forecast are not eligible to receive RUC

make whole payments as described under Section 8.6.5 of this Attachment

AE.




Title Re-pricing Clarification




Approve Reject


Defer Refer






Section No.: 7.2.2.1 Title: Notice to Market Participants and the Public Protocol Version: 19.1a



Revision Description This MPRR deletes the legacy EIS Market language and updates the re-pricing language to the current process. The current language below is EIS Market language that puts the re-pricing of a settlement period out to OD+9. This date is after the initial OD+7 settlement posting. The correct posting of re-pricing is OD+5.



Attachment AE Section 8.4 Price Corrections

No



No



Opposed: N/A

Abstained: Boston Energy

RTWG Review Date of Vote: 6/25/2014 Vote: Approved as Modified

ORWG Review Date of Vote: 6/19/2014 Vote: Approved with no Reliability Impact




Date 4/30/2014

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 5/20/2014

Comment Description MWG added some clarifying language to section 7.2.2.1. Instead of using the words “settlement period” MWG decided to use “during an Operating Day”.

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

Comments Received

Comment Author Brenda Fricano on behalf of RWTG Date 6/25/2014

Comment Description RTWG changed “on the fifth (5) calendar day” to “five (5) calendar days” to match the language in the Protocols.

Comment Status


7.2.2.1 Notice to Market Participants and the Public

(1) In any hour for which If SPP reasonably believesdetermines that a data or software error has occurred during an Operating Day that may requires a correction of one or more LMPs and/or MCPs, SPP shall post a notice that it is considering a correction for that hour on its OASIS and website and shall notify Market Participants as soon as practicable, but not later than 5:00 p.m. four (4) Calendar Days after the Operating Day.

(2)(1) Prior to making a price correction,SPP must post on its OASIS and website a description of its proposed price correction and shall notify Market Participants as soon as reasonably practicable. In any event, SPP must post a description of the proposed price correction no later than 5:00 p.m. within five (5) Calendar Days after the Operating Daydate on which a notice of a price correction is posted. If SPP determines that a price correction is not necessary, it shall withdraw the notice of possible price correction from its OASIS and website as soon as reasonably practicable.




Attachment AE

8.4 Price Corrections

If LMP and MCP corrections are required due to software errors and/or data input errors,

the Transmission Provider shall impose corrective measures and take immediate action to

remedy such errors and recalculate LMPs and MCPs in accordance with the following

procedures:

(1) Notice to Market Participants:

In any Operating Hour for which the If the Transmission Provider believes

determines that a software error or data input error will requires a correction of one or

more LMPs and MCPs, the Transmission Provider shall make publicly available on its

OASIS as soon as practicable but not later than 1700 hours on the fourth calendar day

following the day in which the LMPs and MCPs would be affected by the contemplated

price correction.

If practicable prior to making a price correction, the Transmission Provider shall make

publicly available on its OASIS a description of its proposed price correction. In any

event, the Transmission Provider shall post a description of the proposed price correction

within no later than 1700 hours five (5) calendar days following the day in which the

LMPs and MCPs would be affected by the contemplated price correctionafter the date on

which a notice of a price correction is posted. If the Transmission Provider determines

that a price correction is not necessary, it shall withdraw the notice of possible price

correction from its OASIS as soon as practicable.

(2) Price corrections identified after the end of the notice period:

If the Transmission Provider identifies software or data input errors requiring a

price correction subsequent to the issuance of the final Settlement Statement, but does not

(a) post a notice of price correction or (b) post a description of the proposed price

correction within the required time periods, the Transmission Provider shall request

Commission approval prior to making the necessary price correction.

(3) Process for recalculating prices and compensation for the Day-Ahead Market:

The Transmission Provider shall recalculate LMPs, MCPs and Day-Ahead Market

cleared amounts for the Day-Ahead Market in a manner that reflects, as closely as

practicable, the LMPs and MCPs that would have resulted but for the software or data

input error for the Day-Ahead Market while maintaining the original Day-Ahead Market


unit commitment. The Transmission Provider shall perform any necessary resettlement

using the recalculated Day-Ahead Market results. Such recalculated Day-Ahead Market

results shall be provided to Market Participants in the same manner as the original Day-

Ahead Market results determined in the ordinary course of business.

(4) Process for recalculating prices and compensation for the RTBM:

SPP shall recalculate LMPs and MCPs for the RTBM in a manner that reflects, as

closely as practicable, the LMPs and MCPs that would have resulted but for the software

or data input error for the RTBM and shall perform any necessary resettlement using

these recalculated values. Such recalculated LMPs and MCPs shall be provided to

Market Participants in the same manner as LMPs and MCPs determined in the ordinary

course of business. Compensation to Market Participants results from the recalculated

prices shall be as follows:

(a) For instances where the recalculated RTBM LMP is less than a Resource’s

Energy Offer Curve price, compensation shall be as described under Section

8.6.6(1);

(b) For instances where a Resource’s recalculated RTBM LMP is greater than the

Day-Ahead Market LMP and the Market Participant is buying back its Day-

Ahead Market position as a result of a Dispatch Instruction, compensation shall

be as described under Section 8.6.6(2) except that, the MW amount eligible for

compensation shall be equal to the difference between the Resource’s Day-Ahead

Market MW position and the greater of that Resource’s actual MW output in the

Dispatch Interval or the Resource’s average Setpoint Instruction in the Dispatch

Interval;

(c) For instances where a Resource’s recalculated RTBM Operating Reserve product

MCP is greater than the Day-Ahead Market Operating Reserve product MCP and

the Market Participant is buying back its Day-Ahead Market Operating Reserve

product position resulting from the Transmission Provider clearing all or a portion

of that Operating Reserve product on a different Resource in the market solution,

compensation shall be as described under Section 8.6.6(3).




Title MWP Start-Up Offer Recovery Eligibility Clarifications

Timeline

Normal Expedited Urgent Action

Provide explanation if Expedited and/or Urgent Action is selected: This MPRR is Expedited to address the Settlement concerns.


Approve Reject


Defer Refer


(2) Defect – (2) High 3 – Member Request 4 – Other

Impact Analysis Required Yes, Estimated Cost: $4,000 Duration: 1 months No



Section No.: 4.5.8.12, 4.5.9.8 Title: Day-Ahead Make-Whole-Payment Amount, RUC Make-Whole-Payment Amount Protocol Version: 20.b




The eligibility rules regarding recovery of Start-Up Offer costs in the DA Market MWP and the RUC MWP allowed recovery of certain Start-Up Offer costs which should not have been eligible for recovery. These revisions allow for changes to be made to the SPP Settlement System to properly include Start-Up Offer recovery by adding key language that states: “Start-Up Offer costs are eligible for recovery as long as SCUC (both DA Market and RUC) considered those costs in making the commitment decision”. Scenario #1 – A unit has been committed by the DA Market in Market status. The unit has been running and has met the minimum run time some time ago, but DA sees that this unit is economical, so DA keeps the unit running. Late at night, the unit trips and is offline for several hours. Because the unit was offline prior to the next day commitment and it was committed by the DA Market, by definition, the unit is eligible for Start-Up. Even though the unit has been online for several days and has met its min run time, the unit appeared to be off and then appeared to be started up by the DA Market. This unit should not have received a start-up amount since SPP never started them up on the next day. Scenario #2 - Same a scenario #1, except the unit has been committed by the DA Market in Self Status and trips and goes offline late at night. The unit then comes back online right before the next commitment begins. Because the unit was offline prior to the next day commitment and it was committed by the DA Market, by definition, the unit is eligible for Start-Up. Even though the unit has been online the day before, the unit appeared to be off and then appeared to be started up by the DA Market. This unit should not have received a start-up amount since SPP never started them up on the next day. Scenario #3 - A unit has been committed by the DA market in market status. RUC decides to bring the unit on early in front of the original DA commitment. However, the start-up cost for the unit is higher in Real Time then it is for the next day’s DA


commitment (which is what originally committed the unit). When RUC solves, it assumes no start-up cost since it was assessed in the DA run. However, current design pulls the startup cost from RUC and that is what Settlements uses to settle. Therefore causing a higher start-up cost to be awarded to the MP.



Attachment AE Section 8.5.9 Day-Ahead Make Whole Payment Amount; Section 8.6.5 Reliability Unit Commitment Make Whole Payment Amount

No



No



Opposed: WR, OGE

Abstained: Exelon, Boston Energy, Xcel, OPPD

RTWG Review Date of Vote: Vote:

ORWG Review Date of Vote: 7/1/2014 Vote: Approved with no Reliability Impact



Date 6/11/2014

Sponsor Name Micha Bailey E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.2522

Reasons for Opposing Dissenter Clifford Franklin, WR Date 6/27/2014

Reason

Westar votes NO on MPRR190. Conceptually, Westar agrees with SPP intent of this language but there is a flaw in the MPPR190 language that incorrectly limits unit RUC MWP eligibility to only units committed by SCUC in which the unit startup costs were considered. Westar assumes that the intent of MPRR190 was not to exclude SPP RUC MWP eligibility from units manually committed by the TP or local TO conducted in a non-discriminatory manner. Thus, SPP needs to clarify that manual reliability commitments made in a non-discriminatory manner are also eligible for RUC MWPs. Westar will support MPRR190 once the clarification is made by SPP MPRR190 for manual reliability commitment eligibility.



Reasons for Opposing Dissenter Shawn McBroom, OGE Date 6/27/2014

Reason

OG&E foundationally agrees that a resource that was originally a self-committed resource and in subsequent commitment days has been awarded a market commitment and the Market has had the opportunity to benefit from the resource’s low energy offer for an extended period of time and then an unforeseen event occurs and the resource experiences operating issues and must come offline; yet fails to return to service in the commitment day, then the resource should not receive a make whole payment. However, while the Market solution has not considered the startup cost of the resource because it was absorbed by the MP with its original self-commitment, the Market has taken advantage of the low energy offer output from this resource and does in fact return to service in the commitment period, for which it has received a market commitment, then it is believed that the Market should provide the start-up make whole payment to that resource for the purpose of allowing the Market to return to optimization of the lowest cost generation.

Reasons for Abstaining Abstainer Amber Metzker, Xcel Date 6/27/2014

Reason

I still have concerns that the language added is not detailed enough and could change the systems in a way that Market Participants that should receive a MWP may not (example discussed at MWG). I do agree with the MWP needing to be taken away for the circumstances SPP described, but am uncomfortable with how broad the wording is.


4.5.8.12 Day-Ahead Make-Whole-Payment Amount

(1) The Day-Ahead Make-Whole-Payment Amount is a credit or charge1 to a Resource Asset Owner and is calculated for each Resource with an associated DA Market Commitment Period that was committed by SPP with a Day-Ahead Market Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1, or was committed as part of the Multi-Day Reliability Assessment as defined under Section 4.2.6.3. A payment is made to the Resource Asset Owner when the sum of the Resource’s DA Market Start-Up Offer costs, No-Load Offer costs, Transition State Offer costs,[MPRR101.1] Energy Offer Curve and Operating Reserve Offer costs associated with cleared DA Market amounts for Energy and Operating Reserve is greater than the Energy and Operating Reserve DA Market revenues received for that Resource over the Resource’s DA Market Make-Whole-Payment Eligibility Period.

(2) A Resource’s DA Market Make-Whole-Payment Eligibility Period is equal to a Resource’s DA Market Commitment Period except as defined below:

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.


(a) For Resources with an associated DA Market Commitment Period that begins in one Operating Day and ends in the next Operating Day, two DA Market Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the hour that the DA Market Commitment Period begins and ends in the last hour of the first Operating Day. The second period begins in the first hour of the next Operating Day and ends in the last hour of the DA Market Commitment Period.

(3) The following cost recovery eligible rules apply to each DA Market Make-Whole-Payment Eligibility Period. Offer costs are calculated using the DA Market Offer prices in effect at the time the commitment decision was made except under the situation described under Section (b)(i)(1) below.

(a) There may be more than one DA Market Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single DA Market Make-Whole Payment Eligibility Period is contained within a single Operating Day.

(b) A Resource’s DA Market Start-Up Offer costs are not eligible for recovery in the following DA Market Make-Whole Payment Eligibility Periods:

(i) Any DA Market Make-Whole Payment Eligibility Period for which the Day-Ahead Market SCUC did not consider the Resource’s Start-Up Offer in the commitment decision that is adjacent to the end of a RUC Make-Whole Payment Eligibility Period except as described in (1) below;

(1) As described under Section 4.5.9.8(3)(h), to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the adjacent RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the adjacent Day-Ahead Make-Whole Payment Eligibility Period.

(ii) Any DA Market Make-Whole Payment Eligibility Period resulting from a DA Market Commitment Period that contains a DA Market Self-Commit Hour; and

(iii) Any DA Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s DA Market Commit Time less the Resource’s Sync-To-Min Time unless such time is within a contiguous RUC Make-Whole Payment Eligibility Period that is created subsequent to the DA Market Make-Whole-Payment Eligibility Period.

(c) For each DA Market Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s DA Market Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time rounded down to the nearest hour or (2) 24 Hours, and that portion of the Start-Up Offer is included as a cost in each hour of the DA Market Make-Whole


Payment Eligibility Period until the sum of these hourly costs are equal to the DA Market Start-Up Offer or until the end of the DA Market Make-Whole Payment Eligibility Period, whichever occurs first.

(d) To the extent that the full amount of the DA Market Start-Up Offer is not accounted for in the last DA Market Make-Whole Payment Eligibility Period in the Operating Day, any remaining DA Market Start-Up Offer costs are carried forward for recovery in the first DA Market Make-Whole Payment Eligibility Period of the following Operating Day. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $10,000. The DA Market Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For DA Market Make-Whole Payment calculation purposes, the DA Market Commitment Period is split into two separate DA Market Make-Whole Payment Eligibility Periods as described in (2).b above. The first DA Market Make-Whole Payment Eligibility Period will include $1000/hour of Start-Up Offer costs ($10,000 / 10 Hours) in hours 23 and 24. The second DA Market Make-Whole Payment Eligibility Period will include $1000/hour of Start-Up Offer costs in hours 1 through 8.

(e) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at an average Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, such cost is not due to any independent action of the Market Participant and such cost is not incurred during a RUC Make-Whole Payment Eligibility Period. In such cases, the additional costs are equal to the difference between the Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs is limited to the time period defined as the Transition State Time submitted in the Resource Offer.[MPRR101.2]

…


…

Variable Unit Settlement Interval

Definition

DaStartUpAmt a s, c

(Not Available on Settlement Statement)

$ Eligibility Period

Day-Ahead Start-Up Cost Amount per AO per Settlement Location per DA Market Make-Whole-Payment Eligibility Period - The DA Market Start-Up Offer used in the commitment decision, which includes the impacts of mitigation and the expected state of the Resource prior to the DA Market Commitment Period, associated with AO a’s eligible Resource at Settlement Location s for DA Market Make-Whole-Payment Eligibility Period c.

…


4.5.9.8 RUC Make-Whole-Payment Amount

(1) The RUC Make-Whole-Payment Amount is a credit or charge2 to a Resource Asset Owner and is calculated for each Resource with a RUC Commitment Period that was committed by SPP with an RTBM Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1. Asset Owners of Resources committed by a local transmission operator to address a Local Emergency Condition are eligible to receive a RUC make whole payment, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a RUC make whole payment. For such eligible local transmission operator commitments, a manual process is employed for the calculations and the make-whole-payments will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The RUC Make-Whole-Payment Amount is also calculated for combined cycle Resources with a RUC Commitment Period during which the Resource is moved into a configuration that incurs additional costs over the Resource configuration used in the DA Market Commitment Period for the corresponding time period[MPRR101.3]. A payment is made to the Resource Asset Owner when the sum of the Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy Offer Curve, Transition State Offer costs[MPRR101.4] and Operating Reserve Offer costs associated with actual MWh amounts for Energy and cleared RTBM Operating Reserve is greater than the Energy and Operating Reserve RTBM revenues received for that Resource over the Resource’s RUC Make-Whole-Payment Eligibility Period. Recovery of such compensation shall be collected in accordance with Section 8.6.7 of Attachment AE.

(2) A Resource’s RUC Make-Whole-Payment Eligibility Period is equal to the Resource’s RUC Commitment Period except as described below:

(a) As shown in Exhibit 4-25, for Resources with a RUC Commitment Period that begins in one Operating Day and ends in the next Operating Day, two RUC Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last Dispatch Interval of the first Operating Day. The second period begins in the first Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated with the Resource’s RUC De-Commit Time.

Exhibit 4-1: RUC Make-Whole Payment Eligibility Period – Multiple Operating Days


Operating Day 1 Operating Day 2 Real-Time Make-Whole Payment Eligibility Period

Real-Time Make-Whole Payment Eligibility Period


(b) If the Resource is a combined cycle Resource committed in the DA Market and then, during an RTBM hour within the DA Market Commitment Period, the Resource is moved into a configuration that is different from the configuration used in the DA Market Commitment period and such configuration incurs a Transition State Offer cost and/or a No-Load Offer cost that is higher than the No-Load Offer cost associated with the configuration used in the DA Market, that RTBM hour will be considered the start of a RUC Make-Whole-Payment Eligibility Period. The end of this RUC Make-Whole-Payment Eligibility Period will be defined by the RTBM hour when the configuration in that RTBM hour is the same configuration as the configuration used in the corresponding DA Market Commitment Period hour, the Resource’s De-Commit Time or the end of the Operating Day, whichever is less.[MPRR101.5]

(3) The following cost recovery eligible rules apply to each RUC Make-Whole-Payment Eligibility Period. Resource production costs are calculated using the RTBM Offer prices in effect at the time the commitment decision was made for start-up, no-load, and minimum-energy; and the RTBM Offer prices in effect at the solving of a dispatch interval for incremental energy, Regulation-Up, Regulation-Down, Spin, and Supplement Reserves.

(a) If SPP cancels a start-up order prior to the start of the associated RUC Make-Whole-Payment Eligibility Period and the Resource is not a Synchronized Resource, the Asset Owner will receive reimbursement for a time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset Owners may request additional compensation through submittal of actual cost documentation to the SPP. SPP will review the submitted documentation and confirm that the submitted information is sufficient to document actual costs and that all or a portion of the actual costs are eligible for recovery.

(b) In order to receive Start-Up Offer recovery within a RUC Make-Whole-Payment Eligibility Period, the Resource must be a Synchronized Resource for at least one Dispatch Interval in the RUC Make-Whole Payment Eligibility Period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the RUC Make-Whole Payment Eligibility Period, the Resource must be a Synchronized Resource in that Dispatch Interval.

RUC Commitment

Period

Time


(d) There may be more than one RUC Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single RUC Make-Whole Payment Eligibility Period is contained within a single Operating Day.

(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the following RUC Make-Whole Payment Eligibility Periods:

(i) Any RUC Make-Whole Payment Eligibility Period for which the RUC SCUC did not consider the Resource’s Start-Up Offer in the commitment decisionthat is adjacent to the end of a DA Market Make-Whole Payment Eligibility Period;

(ii) Any RUC Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s RUC Commit Time less the Resource’s Sync-To-Min Time; and

(iii) Any RUC Make-Whole Payment Eligibility Period resulting from a RUC Commitment Period that contains an hour for which the Resource Commitment Status is Self-Commit.

(f) For each RUC Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time multiplied by 12 rounded down to the nearest whole interval or (2) 24 Hours multiplied by 12, and that portion of the Start-Up Offer is included as a cost in each interval of the RUC Make-Whole Payment Eligibility Period until the sum of these interval costs are equal to the RTBM Start-Up Offer or until the end of the RUC Make-Whole Payment Eligibility Period, whichever occurs first.

(g) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the last RUC Make-Whole Payment Eligibility Period in the Operating Day, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the first RUC Make-Whole Payment Eligibility Period of the following Operating Day provided that the Resource has not been committed in the DA Market in any hour of the first RUC Make-Whole Payment Eligibility Period as described in (h) below. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $12,000. The RUC Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For RUC Make-Whole Payment calculation purposes, the RUC Commitment Period is split into two separate RUC Make-Whole Payment Eligibility Periods as described in (2).a above. The first RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs ($12,000 / 120 intervals) in hour 23 and 24 intervals. The second RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs in hours 1 through 8 intervals.

(h) If the Resource has been committed in the DA Market in a period adjacent to and following a RUC Make-Whole Payment Eligibility Period to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the RUC Make-Whole Payment Eligibility Period, any


remaining RTBM Start-Up Offer costs are carried forward for recovery in the Day-Ahead Make-Whole Payment Eligibility Period.

(i) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at a Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, and such cost is not due to any independent action of the Market Participant. In such cases, the additional costs are equal to the difference between the average Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs associated with Contingency Reserve is limited to the time period defined as the Transition State Time submitted in the Resource Offer. Recovery of these costs associated with Regulation-Up and/or Regulation-Down is limited to all Dispatch Intervals within the transition hour.[MPRR101.6]

…


…

Variable

Unit

Settlement Interval

Definition

RtStartUpAmt a s, c



Real-Time Start-Up Cost Amount per AO per Settlement Location per RUC Make-Whole-Payment Eligibility Period - The RTBM Start-Up Offer used in the commitment decision, which includes the impacts of mitigation and the expected state of the Resource prior to the RUC Commitment Period, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c.

…



Attachment AE

8.5.9 Day-Ahead Make Whole Payment Amount

(1) The Day-Ahead make whole payment amount is a payment to an Asset Owner and is

calculated for each Resource with an associated Day-Ahead Market Commitment Period

that was committed by the Transmission Provider with a Day-Ahead Market Resource

Offer commitment status as defined under Sections 4.1(10)(b) and (c) of this Attachment

AE, or was committed as part of the Multi-Day Reliability Assessment as defined under

Section 4.5.3 of this Attachment AE. A payment is made to the Asset Owner when the

sum of the Resource’s costs is greater than the Day-Ahead Market revenues received for

that Resource over the Resource’s Day-Ahead Market make whole payment eligibility

period. The make whole payment is equal to this difference between these costs and

revenues.

(2) A Resource’s Day-Ahead Market make whole payment eligibility period is equal to a

Resource’s Day-Ahead Market Commitment Period except as defined herein. For

Resources with an associated Day-Ahead Market Commitment Period that begins in one

Operating Day and ends in the next Operating Day, two (2) Day-Ahead Market make

whole payment eligibility periods are created. The first period begins in the first

Operating Day in the hour that the Day-Ahead Market Commitment Period begins and

ends in the last hour of the first Operating Day. The second period begins in the first

hour of the next Operating Day and ends in the last hour of the Day-Ahead Market

Commitment Period.

(3) The following cost recovery rules apply to each Day-Ahead Market make whole payment

eligibility period. Offer costs are calculated using the Day-Ahead Market Offer prices in

effect at the time the commitment decision was made except under the situation described

under Section (b)(i) below.

(a) There may be more than one Day-Ahead Market make whole payment eligibility

period for a Resource in a single Operating Day for which a charge or payment is

calculated. A single Day-Ahead Market make whole payment eligibility period is

contained within a single Operating Day.


(b) A Resource’s Day-Ahead Market Start-Up Offer costs are not eligible for

recovery in the following Day-Ahead Market make whole payment eligibility

periods:

(i) For any Day-Ahead Market make whole payment eligibility period for

which the Day-Ahead Market SCUC algorithm did not consider the

Resource’s Start-Up Offer in the commitment decisionthat is adjacent to

the end of a RUC make whole payment eligibility period except as

described under Section 8.6.5(3)(h);

(ii) For any Day-Ahead Market make whole payment eligibility period

resulting from a Day-Ahead Market Commitment Period that contains a

Day-Ahead Market self-commit hour; or

(iii) For any Day-Ahead make whole payment eligibility period for which a

Resource is a Synchronized Resource prior to this commitment period at a

time one (1) hour prior to that Resource’s Day-Ahead Market Commit

Time less the Resource’s Sync-To-Min Time unless such time is within a

contiguous RUC make-whole payment eligibility period that was created

subsequent to the Day-Ahead make whole payment eligibility period;

where RUC make-whole payment eligibility period is as defined under

Section 8.6.5(2).

(c) For each Day-Ahead Market make whole payment eligibility period within an

Operating Day, a Resource’s Day-Ahead Market Start-Up Offer is divided by the

lesser of (1) the Resource’s Minimum Run Time rounded down to the nearest

hour or (2) twenty-four (24) hours, and that portion of the Start-Up Offer is

included as a cost in each hour of the Day-Ahead Market make whole payment

eligibility period until the sum of these hourly costs are equal to the Day-Ahead

Market Start-Up Offer or until the end of the Day-Ahead Market make whole

payment eligibility period, whichever occurs first.

(d) To the extent that the full amount of the Day-Ahead Market Start-Up Offer is not

accounted for in the last Day-Ahead Market make whole payment eligibility

period in the Operating Day, any remaining Day-Ahead Market Start-Up Offer

costs are carried forward for recovery in the first Day-Ahead Market make whole

payment eligibility period of the following Operating Day.


(4) The payment to each Asset Owner for each eligible Settlement Location for a given Day-

Ahead Market make whole payment eligibility period is calculated as follows:

Day-Ahead Make Whole Payment Amount =

Maximum of [Either Zero or Sum of ((Day-Ahead Make Whole Payment Cost

Amount in the Day-Ahead Market Make Whole Payment Eligibility Period) +

(Day-Ahead Make Whole Payment Revenue Amount in the Day-Ahead Market

Make Whole Payment Eligibility Period))] * (-1)

(a) An Asset Owner’s Day-Ahead Make Whole Payment Cost Amount for each

eligible Resource is equal the sum for all hours in the Day-Ahead Market Make

Whole Payment Eligibility Period of:

(i) Day-Ahead Market Start-Up Offer,

(ii) Day-Ahead Market No-Load Offer,

(iii) Energy cost associated with cleared Resource Energy from Resource

Energy Offers as described under Section 5.1.3 of this Attachment AE, as

calculated by multiplying cleared Resource Energy by the cost of such

Energy as calculated from the Resource’s Day-Ahead Market Energy

Offer Curve,

(iv) Regulation-Up Service cost associated with cleared Regulation-Up Service

from Regulation-Up Service Offers as described under Section 5.1.3 of

this Attachment AE, as calculated by multiplying Regulation-Up Service

by the cost of such Regulation-Up Service as calculated from the

Resource’s Day-Ahead Market Regulation-Up Service Offer,

(v) Regulation-Down Service cost, associated with cleared Regulation-Down

Service from Regulation-Down Service Offers as described under Section

5.1.3 of this Attachment AE, as calculated by multiplying Regulation-

Down Service by the cost of such Regulation-Down Service as calculated

from the Resource’s Day-Ahead Market Regulation-Down Service Offer,

(vi) Spinning Reserve cost, associated with cleared Spinning Reserve from

Spinning Reserve Offers as described under Section 5.1.3 of this

Attachment AE, as calculated by multiplying Spinning Reserve by the cost

of such Spinning Reserve as calculated from the Resource’s Day-Ahead

Market Spinning Reserve Offer, and


(vii) Supplemental Reserve cost, associated with cleared Supplemental Reserve

from Supplemental Reserve Offers as described under Section 5.1.3 of this

Attachment AE, as calculated by multiplying Supplemental Reserve by the

cost of such Supplemental Reserve as calculated from the Resource’s Day-

Ahead Market Supplemental Reserve Offer

(b) An Asset Owner’s Day-Ahead Make Whole Payment Revenue Amount for each

eligible Resource is equal to the sum for all hours in the Day-Ahead Market Make


(i) Energy revenue associated with cleared Resource Energy from Resource

Energy Offers as described under Section 5.1.3 of this Attachment AE,

calculated by multiplying Resource Energy by Day-Ahead LMP at that

Resource Settlement Location, and

(ii) The sum of the revenues calculated under Section 8.5.2, 8.5.3 and 8.5.4

for that eligible Resource.

8.6.5 Reliability Unit Commitment Make Whole Payment Amount

(1) Asset Owners of Resources committed by the Transmission Provider with an RTBM

Resource Offer commitment status as defined under Sections 4.1(10)(b) and (c) of this

Attachment AE, are eligible to receive a RUC make whole payment. Asset Owners of

Resources committed by a local transmission operator to address a Local Emergency

Condition are eligible to receive a RUC make whole payment, except that, if the Market

Monitor determines such Resources were selected in a discriminatory manner by the local

transmission operator, as determined pursuant to Section 6.1.2.1 of this Attachment AE,

and such Resources were affiliated with the local transmission operator, then such

Resources are not eligible to receive a RUC make whole payment. A RUC make whole

payment is made to the Asset Owner when the sum of a Resource’s eligible RTBM Start-

Up Offer costs, No-Load Offer costs, Energy Offer Curve and Operating Reserve Offer

costs associated with actual Energy and cleared RTBM Operating Reserve is greater than

the Energy and Operating Reserve RTBM revenues received over the Resource’s RUC

make whole payment eligibility period. Recovery of such compensation shall be

collected in accordance with Section 8.6.7 of this Attachment AE.


(2) A Resource’s RUC make whole payment eligibility period is equal to that Resource’s

RUC Commitment Period. For Resources with a RUC Commitment Period that begins in

one Operating Day and ends in the next Operating Day, two RUC make whole payment

eligibility periods are created. The first period begins in the first Operating Day in the

Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last

Dispatch Interval of the first Operating Day. The second period begins in the first

Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated

with the Resource’s RUC De-Commit Time.

(3) The following cost recovery rules apply to each RUC make whole payment eligibility

period. Resource production costs are calculated using the RTBM Offer prices in effect

at the time the commitment decision was made for start-up, no-load, and minimum-

energy; and the RTBM Offer prices in effect at the solving of a dispatch interval for the

Energy above minimum energy, Regulation-Up, Regulation-Down, Spinning Reserve, and

Supplemental Reserve.

(a) If the Transmission Provider cancels a Commitment Instruction prior to the start

of the associated RUC make whole payment eligibility period and the Resource is

not a Synchronized Resource, the Asset Owner will receive reimbursement for a

time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset Owners

may request additional compensation through submittal of actual cost

documentation to the Transmission Provider. The Transmission Provider will

review the submitted documentation and confirm that the submitted information is

sufficient to document actual costs and that all or a portion of the actual costs are

eligible for recovery.

(b) In order to receive the full amount of Start-Up Offer recovery within a RUC make

whole payment eligibility period, the Resource must be a Synchronized Resource

in at least one Dispatch Interval in the RUC make whole payment eligibility

period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in

the RUC make whole payment eligibility period, the Resource must be a

Synchronized Resource in that Dispatch Interval.

(d) There may be more than one RUC make whole payment eligibility period for a

Resource in a single Operating Day. A single RUC make whole payment

eligibility period is contained within a single Operating Day.


(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the

following RUC make whole payment eligibility periods:

(i) Any RUC make whole payment eligibility period for which the RUC

SCUC did not consider the Resource’s Start-Up Offer in the commitment

decisionthat is adjacent to the end of a Day-Ahead Market make whole

payment eligibility period;

(ii) Any RUC make whole payment eligibility period for which a Resource is

a Synchronized Resource prior to this commitment period at a time one (1)

hour prior to that Resource’s RUC Commit Time less the Resource’s

Sync-To-Min Time; and

(iii) Any RUC make whole payment eligibility period resulting from a RUC

Commitment Period that contains an hour for which the Resource was

self-committed.

(f) For each RUC make whole payment eligibility period within an Operating Day, a

Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s

Minimum Run Time multiplied by twelve (12), rounded down to the nearest

whole interval, or (2) twenty-four (24) hours multiplied by twelve (12), and that

portion of the Start-Up Offer is included as a cost in each interval of the RUC

make whole payment eligibility period until the sum of these interval costs are

equal to the RTBM Start-Up Offer or until the end of the RUC make whole


(g) To the extent that the full amount of the RTBM Start-Up Offer is not accounted

for in the last RUC make whole payment eligibility period in the Operating Day,

any remaining RTBM Start-Up Offer costs are carried forward for recovery in the

first RUC make whole payment eligibility period of the following Operating Day

provided that the Resource has not been committed in the Day-Ahead Market in

any hour of the first RUC make whole payment eligibility period as described in

(h) below.

(h) If the Resource has been committed in the Day-Ahead Market in a period adjacent

to and following a RUC make whole payment eligibility period to the extent that

the full amount of the RTBM Start-Up Offer is not accounted for in the RUC

make whole payment eligibility period, any remaining RTBM Start-Up Offer


costs are carried forward for recovery in the Day-Ahead make whole payment

eligibility period.

(i) If a Resource has operated outside of its Operating Tolerance in any Dispatch

Interval, any cost associated with energy output above the Resource’s economic

operating point is not eligible for recovery for that Dispatch Interval where such

cost is calculated as described under Subsection 4(c) below.

(j) If a Resource becomes non-dispatchable in any Dispatch Interval, any cost

associated with energy output above the Resource’s economic operating point is

not eligible for recovery for that Dispatch Interval where such cost is calculated as

described under Subsection 4(c) below.

(k) If a Resource’s minimum operating limit is increased above the Resource’s

minimum operating limit that was used to make the commitment decision, the

increase is greater than the Resource’s Operating Tolerance and the Resource

remains dispatchable in any Dispatch Interval, any cost associated with energy

output above the Resource’s economic operating point is not eligible for recovery

for that Dispatch Interval where such cost is calculated as described under

Subsection 4(c) below.

(4) The payment to each Asset Owner for each eligible Settlement Location for a given RUC

make whole payment eligibility period is calculated as follows:

RUC Make Whole Payment Amount =

Maximum of [Either Zero or (RUC Make Whole Payment Cost Amount in the RUC

Make Whole Payment Eligibility Period + RUC Make Whole Payment Revenue Amount

in the RUC Make Whole Payment Eligibility Period – Uninstructed Resource Deviation

Cost Disallowance – Non-Dispatchable Cost Disallowance – Minimum Limit Cost

Disallowance)]

(a) An Asset Owner’s RUC Make Whole Payment Cost Amount for each eligible

Resource is equal the sum for all Dispatch Intervals in the RUC Make Whole

Payment Eligibility Period of (i) Start-Up Offer used to make commitment

decision, (ii) No-Load Offer used to make commitment decision, (iii) Energy cost

at minimum output as calculated from the Energy Offer Curve used to make

commitment decision, (iv) Energy cost above minimum output as calculated from

the Energy Offer Curve that applied to the current Dispatch Interval, and (v)

Operating Reserve cost associated with cleared Real-Time Operating Reserve as


calculated from the Operating Reserve Offers except that Operating Reserve costs

associated with self-scheduled Operating Reserve where such self-schedules are

less than or equal to the amount of Operating Reserve cleared shall be set equal to

zero.

(b) An Asset Owner’s RUC Make Whole Payment Revenue Amount for each eligible


Payment Eligibility Period of (i) revenue associated with Energy calculated by

multiplying actual Energy by Real-Time LMP (ii) the sum of the revenues

calculated under Section 8.6.2, 8.6.3 and 8.6.4 of this Attachment AE for that

eligible Resource (iii) Energy revenue associated with payments made under

Section 8.6.6 of this Attachment AE (iv) amounts associated with settlement

made under Section 8.6.15 of this Attachment AE (v) Unused Regulation-Up

Mileage Make Whole Payment as calculated under Section 8.6.19 of this

Attachment AE and (vi) Unused Regulation-Down Mileage Make Whole Payment

as calculated under Section 8.6.20 of this Attachment AE.

(c) An Asset Owner’s Uninstructed Resource Deviation Cost Disallowance, Non-

Dispatchable Cost Disallowance, or Minimum Limit Cost Disallowance is equal

to the positive difference between the Resource’s Energy cost at actual output as

calculated from the Resource’s current Dispatch Interval Energy Offer Curve and

the Resource’s Energy cost at the Resource’s economic operating point as

calculated from the Resource’s current Dispatch Interval Energy Offer Curve.

(d) A Resource’s economic operating point is the MW output where the cost on the

Resource’s current Dispatch Interval Energy Offer Curve first exceeds the Real-

Time LMP for that Resource.



PRR Comments

MPRR

No. 190 MPRR Title MWP Start-Up Offer Recovery Eligibility Clarifications

Date 7/3/2014

Submitter Name Micha Bailey E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.688.2522

Comments These comments clarify that Manual Commitments made by the Transmission Provider or by a Local Transmission Operator are eligible for Start-Up Offer cost recovery. The comments also reinstate the RUC adjacency rule that was removed by mistake. All changes are highlighted in yellow.

Revised Proposed Protocol Language Revision

4.5.8.12 Day-Ahead Make-Whole-Payment Amount

(1) The Day-Ahead Make-Whole-Payment Amount is a credit or charge1 to a Resource Asset Owner and is calculated for each Resource with an associated DA Market Commitment Period that was committed by SPP with a Day-Ahead Market Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1, or was committed as part of the Multi-Day Reliability Assessment as defined under Section 4.2.6.3. A payment is made to the Resource Asset Owner when the sum of the Resource’s DA Market Start-Up Offer costs, No-Load Offer costs, Transition State Offer costs,[MPRR101.1] Energy Offer Curve and Operating Reserve Offer costs associated with cleared DA Market amounts for Energy and Operating Reserve is greater than the Energy and Operating Reserve DA Market revenues received for that Resource over the Resource’s DA Market Make-Whole-Payment Eligibility Period.

(2) A Resource’s DA Market Make-Whole-Payment Eligibility Period is equal to a Resource’s DA Market Commitment Period except as defined below:


3.b.i.6 - MWG MPRR 190 SPP Comments 7-3-2014 Page 1 of 18


(a) For Resources with an associated DA Market Commitment Period that begins in one Operating Day and ends in the next Operating Day, two DA Market Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the hour that the DA Market Commitment Period begins and ends in the last hour of the first Operating Day. The second period begins in the first hour of the next Operating Day and ends in the last hour of the DA Market Commitment Period.

(3) The following cost recovery eligible rules apply to each DA Market Make-Whole-Payment Eligibility Period. Offer costs are calculated using the DA Market Offer prices in effect at the time the commitment decision was made except under the situation described under Section (b)(i)(1) below.

(a) There may be more than one DA Market Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single DA Market Make-Whole Payment Eligibility Period is contained within a single Operating Day.

(b) A Resource’s DA Market Start-Up Offer costs are not eligible for recovery in the following DA Market Make-Whole Payment Eligibility Periods except as described in (i)(1) and (i)(2) below:

(i) Any DA Market Make-Whole Payment Eligibility Period for which the Day-Ahead Market SCUC did not consider the Resource’s Start-Up Offer in the commitment decision or any Day-Ahead Make-Whole Payment Eligibility Period that is adjacent to the end of a RUC Make-Whole Payment Eligibility Period that was created subsequent to the Day-Ahead Market Make-Whole Payment Eligibility Period during the day before the Operating Day for which the Day-Ahead Market Make-Whole Payment Eligibility Period applies except as described in (1) below;

(1) As described under Section 4.5.9.8(3)(h), to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the adjacent RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the adjacent Day-Ahead Make-Whole Payment Eligibility Period.

(1)(2) Start-Up Offers associated with manual commitments as described under Sections 4.2.6.2 and 4.3.1.2(1)(b) are eligible for recovery.

(ii) Any DA Market Make-Whole Payment Eligibility Period resulting from a DA Market Commitment Period that contains a DA Market Self-Commit Hour; and

(iii) Any DA Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s DA Market Commit Time less the Resource’s Sync-To-Min


Time unless such time is within a contiguous RUC Make-Whole Payment Eligibility Period that is created subsequent to the DA Market Make-Whole-Payment Eligibility Period.

(c) For each DA Market Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s DA Market Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time rounded down to the nearest hour or (2) 24 Hours, and that portion of the Start-Up Offer is included as a cost in each hour of the DA Market Make-Whole Payment Eligibility Period until the sum of these hourly costs are equal to the DA Market Start-Up Offer or until the end of the DA Market Make-Whole Payment Eligibility Period, whichever occurs first.

(d) To the extent that the full amount of the DA Market Start-Up Offer is not accounted for in the last DA Market Make-Whole Payment Eligibility Period in the Operating Day, any remaining DA Market Start-Up Offer costs are carried forward for recovery in the first DA Market Make-Whole Payment Eligibility Period of the following Operating Day. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $10,000. The DA Market Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For DA Market Make-Whole Payment calculation purposes, the DA Market Commitment Period is split into two separate DA Market Make-Whole Payment Eligibility Periods as described in (2).b above. The first DA Market Make-Whole Payment Eligibility Period will include $1000/hour of Start-Up Offer costs ($10,000 / 10 Hours) in hours 23 and 24. The second DA Market Make-Whole Payment Eligibility Period will include $1000/hour of Start-Up Offer costs in hours 1 through 8.

(e) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at an average Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, such cost is not due to any independent action of the Market Participant and such cost is not incurred during a RUC Make-Whole Payment Eligibility Period. In such cases, the additional costs are equal to the difference between the Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs is limited to the time period defined as the Transition State Time submitted in the Resource Offer.[MPRR101.2]

…


…

Variable Unit Settlement Interval

Definition

DaStartUpAmt a s, c



Day-Ahead Start-Up Cost Amount per AO per Settlement Location per DA Market Make-Whole-Payment Eligibility Period - The DA Market Start-Up Offer used in the commitment decision, which includes the impacts of mitigation and the expected state of the Resource prior to the DA Market Commitment Period, associated with AO a’s eligible Resource at Settlement Location s for DA Market Make-Whole-Payment Eligibility Period c.

…


4.5.9.8 RUC Make-Whole-Payment Amount

(1) The RUC Make-Whole-Payment Amount is a credit or charge2 to a Resource Asset Owner and is calculated for each Resource with a RUC Commitment Period that was committed by SPP with an RTBM Resource Offer Commitment Status of “Market” or “Reliability” as defined under Section 4.2.2.2.1. Asset Owners of Resources committed by a local transmission operator to address a Local Emergency Condition are eligible to receive a RUC make whole payment, except that, if the Market Monitor determines such Resources were selected in a discriminatory manner by the local transmission operator, as determined pursuant to Section 6.1.2.1 of Attachment AE to the Tariff, and such Resources were affiliated with the local transmission operator, then such Resources are not eligible to receive a RUC make whole payment. For such eligible local transmission operator commitments, a manual process is employed for the calculations and the make-whole-payments will appear in the Miscellaneous Amount charge type defined in Section 4.5.11. The RUC Make-Whole-Payment Amount is also calculated for combined cycle Resources with a RUC Commitment Period during which the Resource is moved into a configuration that incurs additional costs over the Resource configuration used in the DA Market Commitment Period for the corresponding time period[MPRR101.3]. A payment is made to the Resource Asset Owner when the sum of the Resource’s eligible RTBM Start-Up Offer costs, No-Load Offer costs, Energy Offer Curve, Transition State Offer costs[MPRR101.4] and Operating Reserve Offer costs associated with actual MWh amounts for Energy and cleared RTBM Operating Reserve is greater than the Energy and Operating Reserve RTBM revenues received for that Resource over the Resource’s RUC Make-Whole-Payment Eligibility Period. Recovery of such compensation shall be collected in accordance with Section 8.6.7 of Attachment AE.

(2) A Resource’s RUC Make-Whole-Payment Eligibility Period is equal to the Resource’s RUC Commitment Period except as described below:

(a) As shown in Exhibit 4-25, for Resources with a RUC Commitment Period that begins in one Operating Day and ends in the next Operating Day, two RUC Make-Whole-Payment Eligibility Periods are created. The first period begins in the first Operating Day in the Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last Dispatch Interval of the first Operating Day. The second period begins in the first Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated with the Resource’s RUC De-Commit Time.

Exhibit 4-1: RUC Make-Whole Payment Eligibility Period – Multiple Operating Days


Operating Day 1 Operating Day 2 Real-Time Make-Whole Payment Eligibility Period

Real-Time Make-Whole Payment Eligibility Period


(b) If the Resource is a combined cycle Resource committed in the DA Market and then, during an RTBM hour within the DA Market Commitment Period, the Resource is moved into a configuration that is different from the configuration used in the DA Market Commitment period and such configuration incurs a Transition State Offer cost and/or a No-Load Offer cost that is higher than the No-Load Offer cost associated with the configuration used in the DA Market, that RTBM hour will be considered the start of a RUC Make-Whole-Payment Eligibility Period. The end of this RUC Make-Whole-Payment Eligibility Period will be defined by the RTBM hour when the configuration in that RTBM hour is the same configuration as the configuration used in the corresponding DA Market Commitment Period hour, the Resource’s De-Commit Time or the end of the Operating Day, whichever is less.[MPRR101.5]

(3) The following cost recovery eligible rules apply to each RUC Make-Whole-Payment Eligibility Period. Resource production costs are calculated using the RTBM Offer prices in effect at the time the commitment decision was made for start-up, no-load, and minimum-energy; and the RTBM Offer prices in effect at the solving of a dispatch interval for incremental energy, Regulation-Up, Regulation-Down, Spin, and Supplement Reserves.

(a) If SPP cancels a start-up order prior to the start of the associated RUC Make-Whole-Payment Eligibility Period and the Resource is not a Synchronized Resource, the Asset Owner will receive reimbursement for a time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset Owners may request additional compensation through submittal of actual cost documentation to the SPP. SPP will review the submitted documentation and confirm that the submitted information is sufficient to document actual costs and that all or a portion of the actual costs are eligible for recovery.

(b) In order to receive Start-Up Offer recovery within a RUC Make-Whole-Payment Eligibility Period, the Resource must be a Synchronized Resource for at least one Dispatch Interval in the RUC Make-Whole Payment Eligibility Period.

(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in the RUC Make-Whole Payment Eligibility Period, the Resource must be a Synchronized Resource in that Dispatch Interval.

RUC Commitment

Period

Time


(d) There may be more than one RUC Make-Whole Payment Eligibility Period for a Resource in a single Operating Day for which a credit or charge is calculated. A single RUC Make-Whole Payment Eligibility Period is contained within a single Operating Day.

(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the following RUC Make-Whole Payment Eligibility Periods:

(i) Any RUC Make-Whole Payment Eligibility Period for which the RUC SCUC did not consider the Resource’s Start-Up Offer in the commitment decision except that RTBM Start-Up Offers associated with manual commitments as described under Sections 4.3.2.2(3)(c), 4.3.2.2(3)(d), 4.4.1.2(3)(c) and 4.4.1.2(3)(d) are eligible for recovery. that is adjacent to the end of a DA Market Make-Whole Payment Eligibility Period;

(ii) Any RUC Make-Whole Payment Eligibility Period for which a Resource is a Synchronized Resource prior to this commitment period at a time one hour prior to that Resource’s RUC Commit Time less the Resource’s Sync-To-Min Time; and

(iii) Any RUC Make-Whole Payment Eligibility Period resulting from a RUC Commitment Period that contains an hour for which the Resource Commitment Status is Self-Commit.

(f) For each RUC Make-Whole Payment Eligibility Period within an Operating Day, a Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s Minimum Run Time multiplied by 12 rounded down to the nearest whole interval or (2) 24 Hours multiplied by 12, and that portion of the Start-Up Offer is included as a cost in each interval of the RUC Make-Whole Payment Eligibility Period until the sum of these interval costs are equal to the RTBM Start-Up Offer or until the end of the RUC Make-Whole Payment Eligibility Period, whichever occurs first.

(g) To the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the last RUC Make-Whole Payment Eligibility Period in the Operating Day, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the first RUC Make-Whole Payment Eligibility Period of the following Operating Day provided that the Resource has not been committed in the DA Market in any hour of the first RUC Make-Whole Payment Eligibility Period as described in (h) below. For example, consider a Resource that is committed starting at 10:00 PM in Operating Day 1 that has a Minimum Run Time of 10 hours and a Start-Up Offer of $12,000. The RUC Commitment Period is from 10:00 PM in Operating Day 1 through 8:00 AM of Operating Day 2. For RUC Make-Whole Payment calculation purposes, the RUC Commitment Period is split into two separate RUC Make-Whole Payment Eligibility Periods as described in (2).a above. The first RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs ($12,000 / 120 intervals) in hour 23 and 24 intervals. The second RUC Make-Whole Payment Eligibility Period will include $100/interval of Start-Up Offer costs in hours 1 through 8 intervals.


(h) If the Resource has been committed in the DA Market in a period adjacent to and following a RUC Make-Whole Payment Eligibility Period to the extent that the full amount of the RTBM Start-Up Offer is not accounted for in the RUC Make-Whole Payment Eligibility Period, any remaining RTBM Start-Up Offer costs are carried forward for recovery in the Day-Ahead Make-Whole Payment Eligibility Period.

(i) If the Resource is a combined cycle Resource, additional costs associated with situations in which the Resource has cleared Operating Reserve in the Day-Ahead Market and must buy back that position in Real-Time at a Real-Time MCP that is greater than the Day-Ahead MCP, the Market Participant may be eligible for a make-whole payment. To be eligible, these costs must be incurred during a time period in which the Resource is transitioning between configurations, at the direction of SPP, and such cost is not due to any independent action of the Market Participant. In such cases, the additional costs are equal to the difference between the average Real-Time MCP and the Day-Ahead MCP multiplied by the Day-Ahead Market cleared Operating Reserve MW amounts. Recovery of these costs associated with Contingency Reserve is limited to the time period defined as the Transition State Time submitted in the Resource Offer. Recovery of these costs associated with Regulation-Up and/or Regulation-Down is limited to all Dispatch Intervals within the transition hour.[MPRR101.6]

…


…

Variable

Unit

Settlement Interval

Definition

RtStartUpAmt a s, c



Real-Time Start-Up Cost Amount per AO per Settlement Location per RUC Make-Whole-Payment Eligibility Period - The RTBM Start-Up Offer used in the commitment decision, which includes the impacts of mitigation and the expected state of the Resource prior to the RUC Commitment Period, associated with AO a’s eligible Resource at Settlement Location s for RUC Make-Whole-Payment Eligibility Period c.

…



Attachment AE

8.5.9 Day-Ahead Make Whole Payment Amount

(1) The Day-Ahead make whole payment amount is a payment to an Asset Owner and is

calculated for each Resource with an associated Day-Ahead Market Commitment Period

that was committed by the Transmission Provider with a Day-Ahead Market Resource

Offer commitment status as defined under Sections 4.1(10)(b) and (c) of this Attachment

AE, or was committed as part of the Multi-Day Reliability Assessment as defined under

Section 4.5.3 of this Attachment AE. A payment is made to the Asset Owner when the

sum of the Resource’s costs is greater than the Day-Ahead Market revenues received for

that Resource over the Resource’s Day-Ahead Market make whole payment eligibility

period. The make whole payment is equal to this difference between these costs and

revenues.

(2) A Resource’s Day-Ahead Market make whole payment eligibility period is equal to a

Resource’s Day-Ahead Market Commitment Period except as defined herein. For

Resources with an associated Day-Ahead Market Commitment Period that begins in one

Operating Day and ends in the next Operating Day, two (2) Day-Ahead Market make

whole payment eligibility periods are created. The first period begins in the first

Operating Day in the hour that the Day-Ahead Market Commitment Period begins and

ends in the last hour of the first Operating Day. The second period begins in the first

hour of the next Operating Day and ends in the last hour of the Day-Ahead Market

Commitment Period.

(3) The following cost recovery rules apply to each Day-Ahead Market make whole payment

eligibility period. Offer costs are calculated using the Day-Ahead Market Offer prices in

effect at the time the commitment decision was made except under the situation described

under Section (b)(i) below.

(a) There may be more than one Day-Ahead Market make whole payment eligibility

period for a Resource in a single Operating Day for which a charge or payment is

calculated. A single Day-Ahead Market make whole payment eligibility period is

contained within a single Operating Day.


(b) A Resource’s Day-Ahead Market Start-Up Offer costs are not eligible for

recovery in the following Day-Ahead Market make whole payment eligibility

periods except Day-Ahead Start-Up Offer costs described under Section

8.6.5(3)(h) and Day-Ahead Start-Up Offer costs associated with commitments

made under Sections 4.5 and 5.1.2(1)(b):

(i) For any Day-Ahead Market make whole payment eligibility period for

which the Day-Ahead Market SCUC algorithm did not consider the

Resource’s Start-Up Offer in the commitment decision or any Day-Ahead

Market make whole payment eligibility period that is adjacent to the end

of a RUC make whole payment eligibility period that was created

subsequent to the Day-Ahead Market make whole payment eligibility

period during the day prior to the Operating Day to which the Day-Ahead

Market make whole payment eligibility period applies; where RUC make-

whole payment eligibility period is as defined under Section 8.6.5(2).

except as described under Section 8.6.5(3)(h);

(ii) For any Day-Ahead Market make whole payment eligibility period

resulting from a Day-Ahead Market Commitment Period that contains a

Day-Ahead Market self-commit hour; or

(iii) For any Day-Ahead make whole payment eligibility period for which a

Resource is a Synchronized Resource prior to this commitment period at a

time one (1) hour prior to that Resource’s Day-Ahead Market Commit

Time less the Resource’s Sync-To-Min Time unless such time is within a

contiguous RUC make-whole payment eligibility period that was created

subsequent to the Day-Ahead make whole payment eligibility period;

where RUC make-whole payment eligibility period is as defined under

Section 8.6.5(2).

(c) For each Day-Ahead Market make whole payment eligibility period within an

Operating Day, a Resource’s Day-Ahead Market Start-Up Offer is divided by the

lesser of (1) the Resource’s Minimum Run Time rounded down to the nearest

hour or (2) twenty-four (24) hours, and that portion of the Start-Up Offer is

included as a cost in each hour of the Day-Ahead Market make whole payment

eligibility period until the sum of these hourly costs are equal to the Day-Ahead


Market Start-Up Offer or until the end of the Day-Ahead Market make whole


(d) To the extent that the full amount of the Day-Ahead Market Start-Up Offer is not

accounted for in the last Day-Ahead Market make whole payment eligibility

period in the Operating Day, any remaining Day-Ahead Market Start-Up Offer

costs are carried forward for recovery in the first Day-Ahead Market make whole

payment eligibility period of the following Operating Day.

(4) The payment to each Asset Owner for each eligible Settlement Location for a given Day-

Ahead Market make whole payment eligibility period is calculated as follows:

Day-Ahead Make Whole Payment Amount =

Maximum of [Either Zero or Sum of ((Day-Ahead Make Whole Payment Cost

Amount in the Day-Ahead Market Make Whole Payment Eligibility Period) +

(Day-Ahead Make Whole Payment Revenue Amount in the Day-Ahead Market

Make Whole Payment Eligibility Period))] * (-1)

(a) An Asset Owner’s Day-Ahead Make Whole Payment Cost Amount for each

eligible Resource is equal the sum for all hours in the Day-Ahead Market Make


(i) Day-Ahead Market Start-Up Offer,

(ii) Day-Ahead Market No-Load Offer,

(iii) Energy cost associated with cleared Resource Energy from Resource

Energy Offers as described under Section 5.1.3 of this Attachment AE, as

calculated by multiplying cleared Resource Energy by the cost of such

Energy as calculated from the Resource’s Day-Ahead Market Energy

Offer Curve,

(iv) Regulation-Up Service cost associated with cleared Regulation-Up Service

from Regulation-Up Service Offers as described under Section 5.1.3 of

this Attachment AE, as calculated by multiplying Regulation-Up Service

by the cost of such Regulation-Up Service as calculated from the

Resource’s Day-Ahead Market Regulation-Up Service Offer,

(v) Regulation-Down Service cost, associated with cleared Regulation-Down

Service from Regulation-Down Service Offers as described under Section

5.1.3 of this Attachment AE, as calculated by multiplying Regulation-


Down Service by the cost of such Regulation-Down Service as calculated

from the Resource’s Day-Ahead Market Regulation-Down Service Offer,

(vi) Spinning Reserve cost, associated with cleared Spinning Reserve from

Spinning Reserve Offers as described under Section 5.1.3 of this

Attachment AE, as calculated by multiplying Spinning Reserve by the cost

of such Spinning Reserve as calculated from the Resource’s Day-Ahead

Market Spinning Reserve Offer, and

(vii) Supplemental Reserve cost, associated with cleared Supplemental Reserve

from Supplemental Reserve Offers as described under Section 5.1.3 of this

Attachment AE, as calculated by multiplying Supplemental Reserve by the

cost of such Supplemental Reserve as calculated from the Resource’s Day-

Ahead Market Supplemental Reserve Offer

(b) An Asset Owner’s Day-Ahead Make Whole Payment Revenue Amount for each

eligible Resource is equal to the sum for all hours in the Day-Ahead Market Make


(i) Energy revenue associated with cleared Resource Energy from Resource

Energy Offers as described under Section 5.1.3 of this Attachment AE,

calculated by multiplying Resource Energy by Day-Ahead LMP at that

Resource Settlement Location, and

(ii) The sum of the revenues calculated under Section 8.5.2, 8.5.3 and 8.5.4

for that eligible Resource.

8.6.5 Reliability Unit Commitment Make Whole Payment Amount

(1) Asset Owners of Resources committed by the Transmission Provider with an RTBM

Resource Offer commitment status as defined under Sections 4.1(10)(b) and (c) of this

Attachment AE, are eligible to receive a RUC make whole payment. Asset Owners of

Resources committed by a local transmission operator to address a Local Emergency

Condition are eligible to receive a RUC make whole payment, except that, if the Market

Monitor determines such Resources were selected in a discriminatory manner by the local

transmission operator, as determined pursuant to Section 6.1.2.1 of this Attachment AE,

and such Resources were affiliated with the local transmission operator, then such

Resources are not eligible to receive a RUC make whole payment. A RUC make whole


payment is made to the Asset Owner when the sum of a Resource’s eligible RTBM Start-

Up Offer costs, No-Load Offer costs, Energy Offer Curve and Operating Reserve Offer

costs associated with actual Energy and cleared RTBM Operating Reserve is greater than

the Energy and Operating Reserve RTBM revenues received over the Resource’s RUC

make whole payment eligibility period. Recovery of such compensation shall be

collected in accordance with Section 8.6.7 of this Attachment AE.

(2) A Resource’s RUC make whole payment eligibility period is equal to that Resource’s

RUC Commitment Period. For Resources with a RUC Commitment Period that begins in

one Operating Day and ends in the next Operating Day, two RUC make whole payment

eligibility periods are created. The first period begins in the first Operating Day in the

Dispatch Interval associated with the Resource’s RUC Commit Time and ends at the last

Dispatch Interval of the first Operating Day. The second period begins in the first

Dispatch Interval of the next Operating Day and ends in the Dispatch Interval associated

with the Resource’s RUC De-Commit Time.

(3) The following cost recovery rules apply to each RUC make whole payment eligibility

period. Resource production costs are calculated using the RTBM Offer prices in effect

at the time the commitment decision was made for start-up, no-load, and minimum-

energy; and the RTBM Offer prices in effect at the solving of a dispatch interval for the

Energy above minimum energy, Regulation-Up, Regulation-Down, Spinning Reserve, and

Supplemental Reserve.

(a) If the Transmission Provider cancels a Commitment Instruction prior to the start

of the associated RUC make whole payment eligibility period and the Resource is

not a Synchronized Resource, the Asset Owner will receive reimbursement for a

time-based pro-rata share of the Resource’s RTBM Start-Up Offer. Asset Owners

may request additional compensation through submittal of actual cost

documentation to the Transmission Provider. The Transmission Provider will

review the submitted documentation and confirm that the submitted information is

sufficient to document actual costs and that all or a portion of the actual costs are

eligible for recovery.

(b) In order to receive the full amount of Start-Up Offer recovery within a RUC make

whole payment eligibility period, the Resource must be a Synchronized Resource

in at least one Dispatch Interval in the RUC make whole payment eligibility

period.


(c) In order to receive recovery of No-Load Offer costs in any Dispatch Interval in

the RUC make whole payment eligibility period, the Resource must be a

Synchronized Resource in that Dispatch Interval.

(d) There may be more than one RUC make whole payment eligibility period for a

Resource in a single Operating Day. A single RUC make whole payment

eligibility period is contained within a single Operating Day.

(e) A Resource’s RTBM Start-Up Offer costs are not eligible for recovery in the

following RUC make whole payment eligibility periods:

(i) Any RUC make whole payment eligibility period for which the RUC

SCUC did not consider the Resource’s Start-Up Offer in the commitment

decision except that RTBM Start-Up Offer costs associated with

commitments made under Sections 5.2.2(3), 5.2.2(4), 6.1.2(3) and 6.1.2(4)

shall be eligible for recovery. that is adjacent to the end of a Day-Ahead

Market make whole payment eligibility period;

(ii) Any RUC make whole payment eligibility period for which a Resource is

a Synchronized Resource prior to this commitment period at a time one (1)

hour prior to that Resource’s RUC Commit Time less the Resource’s

Sync-To-Min Time; and

(iii) Any RUC make whole payment eligibility period resulting from a RUC

Commitment Period that contains an hour for which the Resource was

self-committed.

(f) For each RUC make whole payment eligibility period within an Operating Day, a

Resource’s RTBM Start-Up Offer is divided by the lesser of (1) the Resource’s

Minimum Run Time multiplied by twelve (12), rounded down to the nearest

whole interval, or (2) twenty-four (24) hours multiplied by twelve (12), and that

portion of the Start-Up Offer is included as a cost in each interval of the RUC

make whole payment eligibility period until the sum of these interval costs are

equal to the RTBM Start-Up Offer or until the end of the RUC make whole


(g) To the extent that the full amount of the RTBM Start-Up Offer is not accounted

for in the last RUC make whole payment eligibility period in the Operating Day,

any remaining RTBM Start-Up Offer costs are carried forward for recovery in the

first RUC make whole payment eligibility period of the following Operating Day


provided that the Resource has not been committed in the Day-Ahead Market in

any hour of the first RUC make whole payment eligibility period as described in

(h) below.

(h) If the Resource has been committed in the Day-Ahead Market in a period adjacent

to and following a RUC make whole payment eligibility period to the extent that

the full amount of the RTBM Start-Up Offer is not accounted for in the RUC

make whole payment eligibility period, any remaining RTBM Start-Up Offer

costs are carried forward for recovery in the Day-Ahead make whole payment

eligibility period.

(i) If a Resource has operated outside of its Operating Tolerance in any Dispatch

Interval, any cost associated with energy output above the Resource’s economic

operating point is not eligible for recovery for that Dispatch Interval where such

cost is calculated as described under Subsection 4(c) below.

(j) If a Resource becomes non-dispatchable in any Dispatch Interval, any cost

associated with energy output above the Resource’s economic operating point is

not eligible for recovery for that Dispatch Interval where such cost is calculated as

described under Subsection 4(c) below.

(k) If a Resource’s minimum operating limit is increased above the Resource’s

minimum operating limit that was used to make the commitment decision, the

increase is greater than the Resource’s Operating Tolerance and the Resource

remains dispatchable in any Dispatch Interval, any cost associated with energy

output above the Resource’s economic operating point is not eligible for recovery

for that Dispatch Interval where such cost is calculated as described under

Subsection 4(c) below.

(4) The payment to each Asset Owner for each eligible Settlement Location for a given RUC

make whole payment eligibility period is calculated as follows:

RUC Make Whole Payment Amount =

Maximum of [Either Zero or (RUC Make Whole Payment Cost Amount in the RUC

Make Whole Payment Eligibility Period + RUC Make Whole Payment Revenue Amount

in the RUC Make Whole Payment Eligibility Period – Uninstructed Resource Deviation

Cost Disallowance – Non-Dispatchable Cost Disallowance – Minimum Limit Cost

Disallowance)]


(a) An Asset Owner’s RUC Make Whole Payment Cost Amount for each eligible


Payment Eligibility Period of (i) Start-Up Offer used to make commitment

decision, (ii) No-Load Offer used to make commitment decision, (iii) Energy cost

at minimum output as calculated from the Energy Offer Curve used to make

commitment decision, (iv) Energy cost above minimum output as calculated from

the Energy Offer Curve that applied to the current Dispatch Interval, and (v)

Operating Reserve cost associated with cleared Real-Time Operating Reserve as

calculated from the Operating Reserve Offers except that Operating Reserve costs

associated with self-scheduled Operating Reserve where such self-schedules are

less than or equal to the amount of Operating Reserve cleared shall be set equal to

zero.

(b) An Asset Owner’s RUC Make Whole Payment Revenue Amount for each eligible


Payment Eligibility Period of (i) revenue associated with Energy calculated by

multiplying actual Energy by Real-Time LMP (ii) the sum of the revenues

calculated under Section 8.6.2, 8.6.3 and 8.6.4 of this Attachment AE for that

eligible Resource (iii) Energy revenue associated with payments made under

Section 8.6.6 of this Attachment AE (iv) amounts associated with settlement

made under Section 8.6.15 of this Attachment AE (v) Unused Regulation-Up

Mileage Make Whole Payment as calculated under Section 8.6.19 of this

Attachment AE and (vi) Unused Regulation-Down Mileage Make Whole Payment

as calculated under Section 8.6.20 of this Attachment AE.

(c) An Asset Owner’s Uninstructed Resource Deviation Cost Disallowance, Non-

Dispatchable Cost Disallowance, or Minimum Limit Cost Disallowance is equal

to the positive difference between the Resource’s Energy cost at actual output as

calculated from the Resource’s current Dispatch Interval Energy Offer Curve and

the Resource’s Energy cost at the Resource’s economic operating point as

calculated from the Resource’s current Dispatch Interval Energy Offer Curve.

(d) A Resource’s economic operating point is the MW output where the cost on the

Resource’s current Dispatch Interval Energy Offer Curve first exceeds the Real-

Time LMP for that Resource.


Proposed Criteria Language Revision

N/A


Southwest Power Pool, Inc. Market and Operations Policy Committee

Recommendation to the Board of Directors TRR 125, 126 127, and 133

July 29, 2014

Organizational Roster The following persons are members of the Regional Tariff Working Group:

Dennis Reed, WR (Chair) Richard Andrysik, LES Luke Haner, OPPD Tom Hestermann, Sunflower Rob Janssen, Dogwood David Kays, OGE (Vice Chair) Lloyd Kolb, Golden Spread Tom Littleton, OMPA Bernie Liu, Xcel

Paul Malone, NPPD Walt Cecil, 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 125, 126, 127 and 133 that were included in the MOPC July 15 – 16, 2014 background materials.

Analysis Please see the TRR Recommendation Reports for TRRs 125, 126, 127 and 133 that were included in the MOPC July 15 – 16, 2014 background materials.

Recommendation The MOPC recommends that the BOD approve its request regarding Tariff Revision Requests 125, 126, 127 and 133

Action Requested: Approval of RTWG’s request on TRRs 125, 126, 127 and 133

3.b.ii.1 - RTWG TRR Recommendations to MOPC July 15 - 16, 2014 Page 1 of 2

APPROVED: MOPC July 15-16, 2014

TRR’s 125, 126, 127 and 133 Passed Unanimously

TRR Number Description RTWG Meeting Vote

125 Tariff revisions revising Attachment V to implement the changes to the small generator interconnection procedures in accordance with Order 792.

June 26, 2014

Approved unanimously

126 Order 1000 Aggregate Study Tariff Revisions - Attachment Y

June 25, 2014

Motion Passed Unanimously

127 Tariff revisions replacing the language “Notification to Construct” with “approved for construction” to eliminate challenges and provide clarification pursuant to Order 1000.

May 21, 2014

Approved unanimously

133

Tariff revisions to remove requirements to pay interest at the rate specified in 18 CFR § 35.19a(a)(2)(iii) in sections where such a requirement could impose a financing burden on the SPP membership.

June 26, 2014

Motion Passed with One Abstention (AECC)

3.b.ii.1 - RTWG TRR Recommendations to MOPC July 15 - 16, 2014 Page 2 of 2

Tariff Revision Request (TRR)

TRR Number 125 TRR Title Order 792 Compliance

Cross Reference Number MPRR BRR Other (Specify) ___________

Sponsor Name Charles Hendrix E-mail Address [email protected] Company SPP Phone Number 501-614-3546 Date September 12, 2013

Tariff Section(s) Requiring Revision Sections 1, 2 and 14 of Attachment V

Requested Resolution Normal Urgent

Provide explanation if Urgent is selected:

Revision Description Revising Attachment V to implement the changes to the small generator interconnection procedures in accordance with Order 792

Reason for Revision Revising Attachment V to implement the changes to the small generator interconnection procedures in accordance with Order 792

Stakeholder Approval Required (Record date and outcome of vote; N/A for those stakeholders not required)

RTWG— 6/26/2014 - Approved MWG— N/A BPWG—(N/A) TWG—(N/A) ORWG—(N/A) Other (specify)—(N/A) MOPC— Board of Directors—


Legal Review Completed

Yes—(Include any comments from the review)

No

Market Protocols Implications or Changes

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

No

Business Practices Implications or Changes


No

Criteria Implications or Changes


No

Other Corporate Documents Implications or Changes (i.e., SPP Bylaws, Membership Agreement, etc.)


No

Credit Implications

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

No

Impact Analysis Required Yes

No

Proposed Tariff Language Revision (Redlined)

Section 1. Definitions

Adverse System Impact shall mean the negative effects due to technical or operational limits on conductors or equipment being exceeded that may compromise the safety and reliability of the electric system.

Affected System shall mean an electric system other than the Transmission System that may be affected by the proposed interconnection.

Affected System Operator shall mean the entity that operates an Affected System.

Affiliate shall mean, with respect to a corporation, partnership or other entity, each such other corporation, partnership or other entity that directly or indirectly, through one or more intermediaries, controls, is controlled by, or is under common control with, such corporation, partnership or other entity.

Ancillary Services shall mean those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the Transmission System in accordance with Good Utility Practice.

Applicable Laws and Regulations shall mean all duly promulgated applicable federal, state and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or administrative orders, permits and other duly authorized actions of any Governmental Authority.

Applicable Reliability Council shall mean the reliability council applicable to the Transmission System to which the Generating Facility is directly interconnected.

Applicable Reliability Standards shall mean the requirements and guidelines of NERC, the Applicable Reliability Council, and the Control Area of the Transmission System to which the Generating Facility is directly interconnected.

Base Case shall mean the base case power flow, short circuit, and stability data bases used for the Interconnection Studies by the Transmission Provider.

Breach shall mean the failure of a Party to perform or observe any material term or condition of the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable.

Breaching Party shall mean a Party that is in Breach of the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable.

Business Day shall mean Monday through Friday, excluding Federal Holidays.

Calendar Day shall mean any day including Saturday, Sunday or a Federal Holiday.

Clustering shall mean the process whereby a group of Interconnection Requests is studied together, instead of serially, for the purpose of conducting the Interconnection Studies.

Commercial Operation shall mean the status of a Generating Facility that has commenced generating electricity for sale, excluding electricity generated during Trial Operation.

Commercial Operation Date of a unit shall mean the date on which the Generating Facility commences Commercial Operation as agreed to by the Parties pursuant to Appendix E to the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable.

Confidential Information shall mean any confidential, proprietary or trade secret information of a plan, specification, pattern, procedure, design, device, list, concept, policy or compilation relating to the present or planned business of a Party, which is designated as confidential by the Party supplying the information, whether conveyed orally, electronically, in writing, through inspection, or otherwise.

Control Area shall mean an electrical system or systems bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedule with other Control Areas and contributing to frequency regulation of the interconnection. A Control Area must be certified by an Applicable Reliability Council.

Default shall mean the failure of a Breaching Party to cure its Breach in accordance with Article 17 of the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable.

Definitive Interconnection System Impact Study shall mean an engineering study that evaluates the impact of the proposed interconnection on the safety and reliability of Transmission System and, if applicable, an Affected System. The study shall identify and detail the system impacts that would result if the Generating Facility were interconnected without project modifications or system modifications, focusing on the Adverse System Impacts identified in a Preliminary Interconnection System Impact Study or that may be caused by the withdrawal or addition of an Interconnection Request, or to study potential impacts, including but not limited to those identified in the Scoping Meeting as described in the Generator Interconnection Procedures.

Definitive Interconnection System Impact Study Agreement shall mean the form of agreement contained in Appendix 3A of the Generator Interconnection Procedures for conducting the Definitive Interconnection System Impact Study.

Definitive Interconnection System Impact Study Queue shall mean a Transmission Provider separately maintained queue for valid Interconnection Requests for a Definitive Interconnection System Impact Study.

Dispute Resolution shall mean the procedure in Section 12 of the Tariff for resolution of a dispute between the Parties in which they will first attempt to resolve the dispute on an informal basis.

Distribution System shall mean the Transmission Owner’s facilities and equipment that are not included in the Transmission System. The voltage levels at which Distribution Systems operate differ among areas.

Distribution Upgrades shall mean the additions, modifications, and upgrades to the Distribution System at or beyond the Point of Interconnection to facilitate interconnection of the Generating Facility and render the transmission service necessary to effect Interconnection Customer's wholesale sale of electricity in interstate commerce. Distribution Upgrades do not include Interconnection Facilities.

Effective Date shall mean the date on which the Generator Interconnection Agreement becomes effective upon execution by the Parties subject to acceptance by FERC, or if filed unexecuted, upon the date specified by FERC.

Emergency Condition shall mean a condition or situation: (1) that in the judgment of the Party making the claim is imminently likely to endanger life or property; or (2) that, in the case of a Transmission Provider, is imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to the Transmission System, or the electric systems of others to which the Transmission Provider's Transmission System is directly connected; or (3) that, in the case of Transmission Owner, is imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to Transmission Owner’s Interconnection Facilities; or (4) that, in the case of Interconnection Customer, is imminently likely (as determined in a non-discriminatory manner) to cause a material adverse effect on the security of, or damage to, the Generating Facility or Interconnection Customer's Interconnection Facilities. System restoration and black start shall be considered Emergency Conditions; provided that Interconnection Customer is not obligated by the Generator Interconnection Agreement to possess black start capability.

Energy Resource Interconnection Service shall mean an Interconnection Service that allows the Interconnection Customer to connect its Generating Facility to the Transmission System to be eligible to deliver the Generating Facility's electric output using the existing firm or nonfirm capacity of the Transmission System on an as available basis. Energy Resource Interconnection Service in and of itself does not convey transmission service.

Engineering & Procurement (E&P) Agreement shall mean an agreement that authorizes the Transmission Owner to begin engineering and procurement of long lead-time items necessary for the establishment of the interconnection in order to advance the implementation of the Interconnection Request.

Environmental Law shall mean Applicable Laws or Regulations relating to pollution or protection of the environment or natural resources.

Fast Track Process – The procedure for evaluating an Interconnection Request for a certified Small Generating Facility that meets the eligibility requirements of section 14.1 and includes the section 14 screens, customer options meeting, and optional supplemental review.

Federal Power Act shall mean the Federal Power Act, as amended, 16 U.S.C. §§ 791a et seq.

FERC shall mean the Federal Energy Regulatory Commission (Commission) or its successor.

Force Majeure shall mean any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities, or any other cause beyond a Party's control. A Force Majeure event does not include acts of negligence or intentional wrongdoing by the Party claiming Force Majeure.

Generating Facility shall mean Interconnection Customer's device for the production of electricity identified in the Interconnection Request, but shall not include the Interconnection Customer's Interconnection Facilities.

Generating Facility Capacity shall mean the net capacity of the Generating Facility and the aggregate net capacity of the Generating Facility where it includes multiple energy production devices.

Generator Interconnection Agreement (GIA) shall mean the form of interconnection agreement applicable to an Interconnection Request pertaining to a Generating Facility that is included in Appendix 6 to these Generator Interconnection Procedures.

Generator Interconnection Procedures (GIP) shall mean the interconnection procedures applicable to an Interconnection Request pertaining to a Generating Facility that are included in the Transmission Provider's Tariff.

Good Utility Practice shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted in the region.

Governmental Authority shall mean any federal, state, local or other governmental regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, tribunal, or other governmental authority having jurisdiction over the Parties, their respective facilities, or the respective services they provide, and exercising or entitled to exercise any administrative, executive, police, or taxing authority or power; provided, however, that such term does not include Interconnection Customer, Transmission Provider, Transmission Owner or any Affiliate thereof.

Hazardous Substances shall mean any chemicals, materials or substances defined as or included in the definition of "hazardous substances," "hazardous wastes," "hazardous materials," "hazardous constituents," "restricted hazardous materials," "extremely hazardous substances," "toxic substances," "radioactive substances," "contaminants," "pollutants," "toxic pollutants" or words of similar meaning and regulatory effect under any applicable Environmental Law, or any other chemical, material or substance, exposure to which is prohibited, limited or regulated by any applicable Environmental Law.

Initial Queue Position shall mean the order of a valid Interconnection Request, relative to all other pending valid Interconnection Requests. The Initial Queue Position is established based upon the date and time of receipt of the valid Interconnection Requests by Transmission Provider.

Initial Synchronization Date shall mean the date upon which the Generating Facility is initially synchronized and upon which Trial Operation begins.

In-Service Date shall mean the date upon which the Interconnection Customer reasonably expects it will be ready to begin use of the Transmission Owner’s Interconnection Facilities to obtain back feed power.

Interconnection Customer shall mean any entity, including the Transmission Owner or any of the Affiliates or subsidiaries of either, that proposes to interconnect its Generating Facility with the Transmission System.

Interconnection Customer's Interconnection Facilities shall mean all facilities and equipment, as identified in Appendix A of the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable, that are located between the Generating Facility and the Point of Change of Ownership, including any modification, addition, or upgrades to such facilities and equipment necessary to physically and electrically interconnect the Generating Facility to the Transmission System. Interconnection Customer's Interconnection Facilities are sole use facilities.

Interconnection Facilities shall mean the Transmission Owner’s Interconnection Facilities and the Interconnection Customer's Interconnection Facilities. Collectively, Interconnection Facilities include all facilities and equipment between the Generating Facility and the Point of Interconnection, including any modification, additions or upgrades that are necessary to physically and electrically interconnect the Generating Facility to the Transmission System. Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades, Stand Alone Network Upgrades or Network Upgrades.

Interconnection Facilities Study shall mean a study conducted by the Transmission Provider or a third party consultant for the Interconnection Customer to determine a list of facilities (including Transmission Owner's Interconnection Facilities and Network Upgrades as identified in the Definitive Interconnection System Impact Study), the cost of those facilities, and the time required to interconnect the Generating Facility with the Transmission System. The scope of the study is defined in Section 8 of the Generator Interconnection Procedures.

Interconnection Facilities Study Agreement shall mean the form of agreement contained in Appendix 4 of the Generator Interconnection Procedures for conducting the Interconnection Facilities Study.

Interconnection Facilities Study Queue shall mean a Transmission Provider separately maintained queue for valid Interconnection Requests for an Interconnection Facilities Study.

Interconnection Feasibility Study shall mean a preliminary evaluation of the system impact and cost of interconnecting the Generating Facility to the Transmission System, the scope of which is described in Section 6 of the Generator Interconnection Procedures.

Interconnection Feasibility Study Agreement shall mean the form of agreement contained in Appendix 2 of the Generator Interconnection Procedures for conducting the Interconnection Feasibility Study.

Interconnection Feasibility Study Queue shall mean a Transmission Provider separately maintained queue for valid Interconnection Requests for an Interconnection Feasibility Study.

Interconnection Queue Position shall mean the order of a valid Interconnection Request within the Interconnection Facilities Study Queue, relative to all other pending valid Interconnection Requests within the Interconnection Facilities Study Queue, which is established based upon the requirements in Section 4.1.3.

Interconnection Request shall mean an Interconnection Customer's request, in the form of Appendix 1 to the Generator Interconnection Procedures, in accordance with the Tariff, to interconnect a new Generating Facility, or to increase the capacity of, or make a Material Modification to the operating characteristics of, an existing Generating Facility that is interconnected with the Transmission System.

Interconnection Service shall mean the service provided by the Transmission Provider associated with interconnecting the Interconnection Customer's Generating Facility to the Transmission System and enabling it to receive electric energy and capacity from the Generating Facility at the Point of Interconnection, pursuant to the terms of the Generator Interconnection Agreement and, if applicable, the Tariff.

Interconnection Study shall mean any of the following studies: the Interconnection Feasibility Study, the Preliminary Interconnection System Impact Study, the Definitive Interconnection System Impact Study, the Interim Availability Interconnection System Impact Study, and the Interconnection Facilities Study described in the Generator Interconnection Procedures.

Interconnection Study Agreement shall mean any of the following agreements: the Interconnection Feasibility Study Agreement, the Preliminary Interconnection System Impact Study Agreement, the Definitive Interconnection System Impact Study Agreement, the Interim Availability Interconnection System Impact Study Agreement, and the Interconnection Facilities Study Agreement described in the Generator Interconnection Procedures.

Interim Availability Interconnection System Impact Study shall mean an engineering study that evaluates the impact of the proposed interconnection on the safety and reliability of the Transmission System and, if applicable, an Affected System for the purpose of providing Interim Interconnection Service. The study shall identify and detail the system impacts that would result if the Generating Facility were interconnected without project modifications or system modifications on an interim basis.

Interim Availability Interconnection System Impact Study Agreement shall mean the form of agreement contained in Appendix 5 of the Generator Interconnection Procedures for conducting the Interim Availability Interconnection System Impact Study.

Interim Generator Interconnection Agreement (Interim GIA) shall mean the form of interconnection agreement applicable to an Interconnection Request pertaining to a Generating

Facility to allow interconnection to the Transmission System prior to the completion of the Interconnection Study process.

Interim Interconnection Service shall mean the service provided by the Transmission Provider associated with interconnecting the Interconnection Customer's Generating Facility to the Transmission Provider's Transmission System and enabling it to receive electric energy and capacity from the Generating Facility at the Point of Interconnection, pursuant to the terms of the Interim Generator Interconnection Agreement and, if applicable, the Tariff.

IRS shall mean the Internal Revenue Service.

Joint Operating Committee shall be a group made up of representatives from Interconnection Customer, Transmission Owner and the Transmission Provider to coordinate operating and technical considerations of Interconnection Service.

Limited Operation Interconnection Facilities Study Agreement shall mean the form of agreement contained in Appendix 4A of the Generator Interconnection Procedures for conducting the Interconnection Facilities Study.

Loss shall mean any and all losses relating to injury to or death of any person or damage to property, demand, suits, recoveries, costs and expenses, court costs, attorney fees, and all other obligations by or to third parties, arising out of or resulting from another Party's performance, or non-performance of its obligations under the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable, on behalf of the indemnifying Party, except in cases of gross negligence or intentional wrongdoing by the indemnifying Party.

Material Modification shall mean those modifications that have a material impact on the cost or timing of any Interconnection Request with a later Queue priority date.

Metering Equipment shall mean all metering equipment installed or to be installed at the Generating Facility pursuant to the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable, at the metering points, including but not limited to instrument transformers, MWh-meters, data acquisition equipment, transducers, remote terminal unit, communications equipment, phone lines, and fiber optics.

NERC shall mean the North American Electric Reliability Corporation or its successor organization.

Network Resource shall mean any designated generating resource owned, purchased, or leased by a Network Customer under the Network Integration Transmission Service Tariff. Network Resources do not include any resource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be called upon to meet the Network Customer's Network Load on a non-interruptible basis.

Network Resource Interconnection Service shall mean an Interconnection Service that allows the Interconnection Customer to integrate its Generating Facility with the Transmission System in a manner comparable to that in which the Transmission Owner integrates its generating facilities to serve Native Load Customers as a Network Resource. Network Resource Interconnection Service in and of itself does not convey transmission service.

Network Upgrades shall mean the additions, modifications, and upgrades to the Transmission System required at or beyond the point at which the Interconnection Facilities connect to the Transmission System to accommodate the interconnection of the Generating Facility to the Transmission System.

Notice of Dispute shall mean a written notice of a dispute or claim that arises out of or in connection with the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable, or its performance.

Party or Parties shall mean Transmission Provider, Transmission Owner, Interconnection Customer or any combination of the above.

Point of Change of Ownership shall mean the point, as set forth in Appendix A to the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable, where the Interconnection Customer's Interconnection Facilities connect to the Transmission Owner's Interconnection Facilities.

Point of Interconnection shall mean the point, as set forth in Appendix A to the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable, where the Interconnection Facilities connect to the Transmission System.

Preliminary Interconnection System Impact Study shall mean an engineering study that evaluates the impact of the proposed interconnection on the safety and reliability of Transmission System and, if applicable, an Affected System. The study shall identify and detail the system impacts that would result if the Generating Facility were interconnected without project modifications or system modifications, focusing on the Adverse System Impacts identified in an Interconnection Feasibility Study or that may be caused by an Interconnection Request, or to study potential impacts, including but not limited to those identified in the Scoping Meeting as described in the Generator Interconnection Procedures.

Preliminary Interconnection System Impact Study Agreement shall mean the form of agreement contained in Appendix 3 of the Generator Interconnection Procedures for conducting the Preliminary Interconnection System Impact Study.

Preliminary Interconnection System Impact Study Queue shall mean a Transmission Provider separately maintained queue for valid Interconnection Requests for a Preliminary Interconnection System Impact Study.

Previous Network Upgrade shall mean a Network Upgrade that is needed for the interconnection of one or more Interconnection Customers’ Generating Facilities, where the Interconnection Customer is not responsible for the cost and which is identified in Appendix A of the Generator Interconnection Agreement.

Queue shall mean the Interconnection Feasibility Study Queue, the Preliminary Interconnection System Impact Study Queue, the Definitive Interconnection System Impact Study Queue, or the Interconnection Facilities Study Queue, as applicable.

Reasonable Efforts shall mean, with respect to an action required to be attempted or taken by a Party under the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable, efforts that are timely and consistent with Good

Utility Practice and are otherwise substantially equivalent to those a Party would use to protect its own interests.

Scoping Meeting shall mean the meeting between representatives of the Interconnection Customer, Transmission Owner and Transmission Provider conducted for the purpose of discussing alternative interconnection options, to exchange information including any transmission data and earlier study evaluations that would be reasonably expected to impact such interconnection options, to analyze such information, and to determine the potential feasible Points of Interconnection.

Shared Network Upgrade shall mean a Network Upgrade listed in Appendix A of the Generator Interconnection Agreement that is needed for the interconnection of multiple Interconnection Customers’ Generating Facilities where such Interconnection Customers share the cost.

Site Control shall mean documentation reasonably demonstrating: (1) ownership of, a leasehold interest in, or a right to develop a site of sufficient size for the purpose of constructing the Generating Facility; (2) an option to purchase or acquire a leasehold site of sufficient size for such purpose; or (3) an exclusivity or other business relationship between Interconnection Customer and the entity having the right to sell, lease or grant Interconnection Customer the right to possess or occupy a site of sufficient size for such purpose

Small Generating Facility shall mean the Interconnection Customer's device for the production and/or storage for later injection of electricity identified in the Interconnection Request that meets the requirements of Section 14, but shall not include the Interconnection Customer's Interconnection Facilities.a Generating Facility that has an aggregate net Generating Facility Capacity of no more than 2 MW.

Stand Alone Network Upgrades shall mean Network Upgrades that an Interconnection Customer may construct without affecting day-to-day operations of the Transmission System during their construction. The Transmission Provider, Transmission Owner and the Interconnection Customer must agree as to what constitutes Stand Alone Network Upgrades and identify them in Appendix A to the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable.

System Protection Facilities shall mean the equipment, including necessary protection signal communications equipment, required to protect (1) the Transmission System from faults or other electrical disturbances occurring at the Generating Facility and (2) the Generating Facility from faults or other electrical system disturbances occurring on the Transmission System or on other delivery systems or other generating systems to which the Transmission System is directly connected.

Tariff shall mean the Transmission Provider's Tariff through which open access transmission service and Interconnection Service are offered, as filed with FERC, and as amended or supplemented from time to time, or any successor tariff.

Transmission Owner shall mean an entity that owns, leases or otherwise possesses an interest in the portion of the Transmission System at the Point of Interconnection and may be a Party to the Generator Interconnection Agreement to the extent necessary.

Transmission Provider shall mean the public utility (or its Designated Agent) that owns, controls, or operates transmission or distribution facilities used for the transmission of electricity in interstate commerce and provides transmission service under the Tariff. The term Transmission Provider should be read to include the Transmission Owner when the Transmission Owner is separate from the Transmission Provider.

Transmission Owner's Interconnection Facilities shall mean all facilities and equipment owned, controlled, or operated by the Transmission Owner from the Point of Change of Ownership to the Point of Interconnection as identified in Appendix A to the Generator Interconnection Agreement or Interim Generator Interconnection Agreement, as applicable, including any modifications, additions or upgrades to such facilities and equipment. Transmission Owner's Interconnection Facilities are sole use facilities and shall not include Distribution Upgrades, Stand Alone Network Upgrades or Network Upgrades.

Transmission System shall mean the facilities owned, controlled or operated by the Transmission Provider or Transmission Owner that are used to provide transmission service under the Tariff.

Trial Operation shall mean the period during which Interconnection Customer is engaged in on-site test operations and commissioning of the Generating Facility prior to Commercial Operation.

Section 2. Scope and Application

2.1 Application of Generator Interconnection Procedures.

These Generator Interconnection Procedures apply, as specified in this Section 2, to the processing of Interconnection Requests for interconnections to the Transmission System that are subject to FERC jurisdiction. 2.1.1 Sections 2 through 13 apply to processing an Interconnection Request pertaining to a Generating Facility except for Small Generating Facilities that meet the requirements of Section 14 of the GIP or Appendix 11. 2.1.2 Section 14 of the GIP applies to a request to interconnect a certified Small Generating Facility meeting the certification criteria in Appendix 9 and Appendix 10.

2.1.3 A request to interconnect a certified inverter-based Small Generating Facility no larger than 10 kW shall be evaluated under Appendix 11.

2.2 Pre-Application Process for Interconnection Requests equal to or less than 20MW

2.2.1 The Transmission Provider shall designate an employee or office from which information on the application process and on an Affected System can be obtained through informal requests from the Interconnection Customer presenting a proposed project for a specific site. The name, telephone number, and e-mail address of such contact employee or office shall be made available on the Transmission Provider's Internet web site. Electric system information provided to the Interconnection Customer should include relevant system studies, interconnection studies, and other materials useful to an understanding of an interconnection at a particular point on the Transmission Provider's Transmission System, to the extent such provision does not violate confidentiality provisions of prior agreements or critical infrastructure requirements. The Transmission Provider shall comply with reasonable requests for such information.

2.2.2 In addition to the information described in section 2.2.1, which may be provided in response to an informal request, an Interconnection Customer may submit a formal written request form along with a non-refundable fee of $300 for a pre-application report on a proposed project at a specific site. The Transmission Provider shall provide the pre-application data described in section 2.2.3 to the Interconnection Customer within 20 Business Days of receipt of the completed request form and payment of the $300 fee. The pre-application report produced by the Transmission Provider is non-binding, does not confer any rights, and the Interconnection Customer must still successfully apply to interconnect to the Transmission Provider’s system. The written pre-application report request form shall include the information in sections 2.2.2.1 through 2.2.2.8 below to clearly and sufficiently identify the location of the proposed Point of Interconnection.

2.2.2.1 Project contact information, including name, address, phone number, and email address.

2.2.2.2 Project location (street address with nearby cross streets and town)

2.2.2.3 Meter number, pole number, or other equivalent information identifying proposed Point of Interconnection, if available.

2.2.2.4 Generator Type (e.g., solar, wind, combined heat and power, etc.)

2.2.2.5 Size (alternating current kW)

2.2.2.6 Single or three phase generator configuration

2.2.2.7 Stand-alone generator (no onsite load, not including station service – Yes or No?)

2.2.2.8 Is new service requested? Yes or No? If there is existing service, include the customer account number, site minimum and maximum current or proposed electric loads in kW (if available) and specify if the load is expected to change.

2.2.3. Using the information provided in the pre-application report request form in section 2.2.2, the Transmission Provider will identify the substation/area bus, bank or circuit likely to serve the proposed Point of Interconnection. This selection by the Transmission Provider does not necessarily indicate, after application of the screens and/or study, that this would be the circuit the project ultimately connects to. The Interconnection Customer must request additional pre-application reports if information about multiple Points of Interconnection is requested. Subject to section 2.2.4, the pre-application report will include the following information:

2.2.3.1 Total capacity (in MW) of substation/area bus, bank or circuit based on normal or operating ratings likely to serve the proposed Point of Interconnection.

2.2.3.2 Existing aggregate generation capacity (in MW) interconnected to a substation/area bus, bank or circuit (i.e., amount of generation online) likely to serve the proposed Point of Interconnection.

2.2.3.3 Aggregate queued generation capacity (in MW) for a substation/area bus, bank or circuit (i.e., amount of generation in the queue) likely to serve the proposed Point of Interconnection.

2.2.3.4 Available capacity (in MW) of substation/area bus or bank and circuit likely to serve the proposed Point of Interconnection (i.e., total capacity less the sum of existing aggregate generation capacity and aggregate queued generation capacity).

2.2.3.5 Substation nominal distribution voltage and/or transmission nominal voltage if applicable.

2.2.3.6 Nominal distribution circuit voltage at the proposed Point of Interconnection.

2.2.3.7 Approximate circuit distance between the proposed Point of Interconnection and the substation.

2.2.3.8 Relevant line section(s) actual or estimated peak load and minimum load data, including daytime minimum load as described in section 14.4.4.1.1 below and absolute minimum load, when available.

2.2.3.9 Number and rating of protective devices and number and type (standard, bi-directional) of voltage regulating devices between the proposed Point of Interconnection and the substation/area. Identify whether the substation has a load tap changer.

2.2.3.10 Number of phases available at the proposed Point of Interconnection. If a single phase, distance from the three-phase circuit.

2.2.3.11 Limiting conductor ratings from the proposed Point of Interconnection to the distribution substation.

2.2.3.12 Whether the Point of Interconnection is located on a spot network, grid network, or radial supply.

2.2.3.13 Based on the proposed Point of Interconnection, existing or known constraints such as, but not limited to, electrical dependencies at that location, short circuit interrupting capacity issues, power quality or stability issues on the circuit, capacity constraints, or secondary networks.

2.2.4 The pre-application report need only include existing data. A pre-application

report request does not obligate the Transmission Provider to conduct a study or other analysis of the proposed generator in the event that data is not readily available. If the Transmission Provider cannot complete all or some of a pre-application report due to lack of available data, the Transmission Provider shall provide the Interconnection Customer with a pre-application report that includes the data that is available. The provision of information on “available capacity” pursuant to section 2.2.3.4 does not imply that an interconnection up to this level may be completed without impacts since there are many variables studied as part of the interconnection review process, and data provided in the pre-application report may become outdated at the time of the submission of the complete Interconnection Request. Notwithstanding any of the provisions of this section, the Transmission Provider shall, in good faith, include data in the pre-application report that represents the best available information at the time of reporting.

2.32 Comparability.

Transmission Provider shall receive, process and analyze all Interconnection Requests in a timely manner as set forth in this GIP. Transmission Provider will use the same Reasonable Efforts in processing and analyzing Interconnection Requests from all Interconnection Customers, whether the Generating Facilities are owned by Transmission Provider, its subsidiaries or Affiliates or others.

2.43 Base Case Data.

Transmission Provider shall provide current base power flow, short circuit and stability databases, including all underlying assumptions, and contingency list upon request subject to confidentiality provisions in GIP Section 13.1, that the Transmission Provider is using to perform Definitive Interconnection System Impact Studies. Transmission Provider is permitted to require that Interconnection Customer sign a confidentiality agreement before the release of commercially sensitive information or Critical Energy Infrastructure Information in the Base Case data. Such databases and lists, hereinafter referred to as Base Cases, shall include all (1) generation projects and (ii) transmission projects, including merchant transmission projects that are proposed for the Transmission System for which a transmission expansion plan has been submitted and approved by the applicable authority.

2.54 No Applicability to Transmission Service.

Nothing in this GIP shall constitute a request for transmission service or confer upon an Interconnection Customer any right to receive transmission service.

Section 14. Fast Track Process

14.1 Applicability The Fast Track Process is available to an Interconnection Customer proposing to interconnect its Small Generating Facility with the Transmission Distribution System if the Small Generating Facility ’s capacity does not exceed the size limits identified in the table below. Small Generating Facilities below these limits are eligible for Fast Track review. However, Fast Track eligibility is distinct from the Fast Track Process itself, and eligibility does not imply or indicate that a Small Generating Facility will pass the Fast Track screens in section 14.2.1 below or the Supplemental Review screens in section 14.4.1 below. is no larger than 2 MW and Fast Track eligibility is determined based upon the generator type, the size of the generator, voltage of the line and the location of and the type of line at the Point of Interconnection. All Small Generating Facilities connecting to lines greater than 69 kilovolt (kV) are ineligible for the Fast Track Process regardless of size. All synchronous and induction machines must be no larger than 2 MW to be eligible for the Fast Track

Process, regardless of location. For certified inverter-based systems, the size limit varies according to the voltage of the line at the proposed Point of Interconnection. Certified inverter-based Small Generating Facilities located within 2.5 electrical circuit miles of a substation and on a mainline (as defined in the table below) are eligible for the Fast Track Process under the higher thresholds according to the table below. In addition to the size threshold, if the Interconnection Customer's proposed Small Generating Facility must meets the codes, standards, and certification requirements of Appendices 9 and 10 of these procedures, or the Transmission Owner has to have reviewed the design or tested the proposed Small Generating Facility and is satisfied that it is safe to operate.

1 For purposes of this table, a mainline is the three-phase backbone of a circuit. It will

typically constitute lines with wire sizes of 4/0 American wire gauge, 336.4 kcmil, 397.5 kcmil, 477 kcmil and 795 kcmil.

2 An Interconnection Customer can determine this information about its proposed interconnection location in advance by requesting a pre-application report pursuant to section 1.2.

Fast Track Eligibility for Inverter-Based Systems

Phase to Phase Line Voltage Fast Track Eligibility Regardless of Location

Fast Track Eligibility on a Mainline1 and ≤ 2.5 Electrical Circuit Miles from Substation2

< 5 kV ≤ 500 kW ≤ 500 kW

≥ 5 kV and < 15 kV ≤ 2 MW ≤ 3 MW

≥ 15 kV and < 30 kV ≤ 3 MW ≤ 4 MW

≥ 30 kV and ≤ 69 kV ≤ 4 MW ≤ 5 MW

14.1.1 For purposes of Section 14.1, the Interconnection Request shall be evaluated using the maximum capacity that the Small Generating Facility is capable of injecting into the Transmission Provider’s electric system. However, if the maximum capacity that the Small Generating Facility is capable of injecting into the Transmission Provider’s electric system is limited (e.g., through use of a control system, power relay(s), or other similar device settings or adjustments), then the Interconnection Customer must obtain the Transmission Provider’s agreement, with such agreement not to be unreasonably withheld, that the manner in which the Interconnection Customer proposes to implement such a limit will not adversely affect the safety and reliability of the Transmission Provider’s system. If the Transmission Provider does not so agree, then the Interconnection Request must be withdrawn or revised to specify the maximum capacity that the Small Generating Facility is capable of injecting into the Transmission Provider’s electric system without such limitations. Furthermore, nothing in this section shall prevent a Transmission Provider from considering an output higher than the limited output, if appropriate, when evaluating system protection impacts.

14.2 Initial Review

Interconnection Customer shall submit an application in the form of Appendix 1 along with a deposit of $1000. Within 15 Business Days after the Transmission Provider notifies the Interconnection Customer it has received a complete Interconnection Request, the Transmission Provider shall have the Transmission Owner perform an initial review using the screens set forth below. The Transmission Provider shall notify the Interconnection Customer of the results, and include with the notification copies of the analysis and data underlying the Transmission Owner’s determinations under the screens.

14.2.1 Screens

14.2.1.1 The proposed Small Generating Facility’s Point of Interconnection

must be on a portion of the Distribution System that is subject to the Tariff.

14.2.1.2 For interconnection of a proposed Small Generating Facility to a

radial distribution circuit, the aggregated generation, including the proposed Small Generating Facility, on the circuit shall not exceed 15% of the line section annual peak load as most recently measured at the substation. A line section is that portion of a Transmission Owner’s electric system connected to a customer

bounded by automatic sectionalizing devices or the end of the distribution line.

14.2.1.3 For interconnection of a proposed Small Generating Facility to the

load side of spot network protectors, the proposed Small Generating Facility must utilize an inverter-based equipment package and, together with the aggregated other inverter-based generation, shall not exceed the smaller of 5% of a spot network's maximum load or 50 kW.

14.2.1.4 The proposed Small Generating Facility, in aggregation with other generation on the distribution circuit, shall not contribute more than 10% to the distribution circuit's maximum fault current at the point on the high voltage (primary) level nearest the proposed point of change of ownership.

14.2.1.5 The proposed Small Generating Facility, in aggregate with other

generation on the distribution circuit, shall not cause any distribution protective devices and equipment (including, but not limited to, substation breakers, fuse cutouts, and line reclosers), or Interconnection Customer equipment on the system to exceed 87.5% of the short circuit interrupting capability; nor shall the interconnection be proposed for a circuit that already exceeds 87.5% of the short circuit interrupting capability.

14.2.1.6 Using the table below, determine the type of interconnection to a

primary distribution line. This screen includes a review of the type of electrical service provided to the Interconnecting Customer, including line configuration and the transformer connection to limit the potential for creating over-voltages on the Transmission Owner’s electric power system due to a loss of ground during the operating time of any anti-islanding function.

Primary Distribution Line Type

Type of Interconnection to Primary Distribution Line

Result/Criteria

Three-phase, three wire 3-phase or single phase, phase-to-phase

Pass screen

Three-phase, four wire Effectively-grounded 3 phase or Single-phase, line-to-neutral

Pass screen

14.2.1.7 If the proposed Small Generating Facility is to be interconnected

on single-phase shared secondary, the aggregate generation capacity on the shared secondary, including the proposed Small Generating Facility, shall not exceed 20 kW.

14.2.1.8 If the proposed Small Generating Facility is single-phase and is to be interconnected on a center tap neutral of a 240 volt service, its addition shall not create an imbalance between the two sides of the 240 volt service of more than 20% of the nameplate rating of the service transformer.

14.2.1.9 The Small Generating Facility, in aggregate with other generation interconnected to the transmission side of a substation transformer feeding the circuit where the Small Generating Facility proposes to interconnect shall not exceed 10 MW in an area where there are known, or posted, transient stability limitations to generating units located in the general electrical vicinity (e.g., three or four transmission busses from the point of interconnection).

14.2.1.10 No construction of facilities by the Transmission Provider on its

own system shall be required to accommodate the Small Generating Facility.

14.2.1.11 Any study fees shall be based on the Transmission Provider's

actual costs and will be invoiced to the Interconnection Customer after the study is completed and delivered and will include a summary of professional time.

14.2.1.12 The Interconnection Customer must pay any study costs that

exceed the deposit without interest within thirty (30) calendar days on receipt of the invoice or resolution of any dispute. If the deposit exceeds the invoiced fees, the Transmission Provider shall refund such excess within thirty (30) calendar days of the invoice without interest.

14.2.2 If the proposed interconnection passes the screens, the Interconnection Request shall be approved. Transmission Provider will provide the Interconnection Customer a draft GIA within five Business Days after the determination that requires the Interconnection customer to pay the costs of such system modifications prior to interconnection. Interconnection Customer and Transmission Owner shall complete negotiation of the GIA as described in Section 14.2.4

14.2.3 If the proposed interconnection fails the screens, but both the Transmission

Provider and the Transmission Owner determine that the Small Generating Facility may nevertheless be interconnected consistent with safety, reliability, and power quality standards, the Transmission Provider shall provide the Interconnection Customer a draft GIA within five Business Days after the determination that requires the Interconnection customer to pay the costs of such system modifications prior to interconnection. Interconnection Customer and

Transmission Owner shall complete negotiation of the GIA as described in Section 14.2.4.

14.2.4 After receiving a draft GIA from the Transmission Provider, the Interconnection Customer and the Transmission Owner shall have 30 Business Days or another mutually agreeable timeframe to sign and return the GIA, or request that the Transmission Provider file an unexecuted GIA with the Federal Energy Regulatory Commission. If the Interconnection Customer does not sign the GIA, or ask that it be filed unexecuted by the Transmission Provider within 30 Business Days, the Interconnection Request shall be deemed withdrawn. After the GIA is signed by the Parties, the interconnection of the Small Generating Facility shall proceed under the provisions of the GIA.

14.2.5 If the proposed interconnection fails the screens, andbut the Transmission

Provider and Transmission Owner do not or cannot determine from the initial review that the Small Generating Facility may nevertheless be interconnected consistent with safety, reliability, and power quality standards unless the Interconnection Customer is willing to consider minor modifications or further study, the Transmission Provider shall provide the Interconnection Customer with the opportunity to attend a customer options meeting.

14.3 Customer Options Meeting

If the Transmission Provider determines the Interconnection Request cannot be approved without (1) minor modifications at minimal cost; (2) or a supplemental study or other additional studies or actions; or (3) incurringat significant cost to address safety, reliability, or power quality problems., within the five Business Day period after the determination, tTthe Transmission Provider shall notify the Interconnection Customer of that determination within five Business Days after the determination and provide copies of all data and analyses underlying its conclusion. Within ten Business Days of the Transmission Provider's determination, the Transmission Provider shall offer to convene a customer options meeting with the Transmission Provider and the Transmission Owner to review possible Interconnection Customer facility modifications or the screen analysis and related results, to determine what further steps are needed to permit the Small Generating Facility to be connected safely and reliably. At the time of notification of the Transmission Provider's determination, or at the customer options meeting, the Transmission Provider/Transmission Owner shall:

14.3.1 Offer to perform facility modifications or minor modifications to the

Transmission Owner’s electric system(e.g., changing meters, fuses, relay settings) and provide a non-binding good faith estimate of the limited cost to make such modifications to the Transmission Owner’s electric system. If the Interconnection Customer agrees to pay for the modifications to the Transmission Provider’s electric system, the Transmission Provider will provide the Interconnection Customer with a draft GIA within ten Business Days of the customer options meeting. Interconnection Customer and Transmission Owner shall complete negotiation of the GIA described in Section 14.2.4; or

14.3.2 The Transmission Provider will Ooffer to perform a supplemental review in

accordance with Section 14.4 if the Transmission Provider concludes that the supplemental review might determine that the Small Generating Facility could continue to qualify for interconnection pursuant to the Fast Track Process, and provide a non-binding good faith estimate of the costs of such review; or

14.3.3 The Transmsstion Provider will Oobtain the Interconnection Customer's

agreement to continue evaluating the Interconnection Request under Sections 2-13.

14.4 Supplemental Review

14.4.1 If the Interconnection Customer agrees to To accept the offer of a supplemental review, the Interconnection Customer shall agree in writing within 15 Business Days of the offer, and submit a deposit for the estimated costs of the supplemental review in the amount of the Transmission Provider’s good faith estimate of the costs of such review, both within 15 Business Days of the offer. If the written agreement and deposit have not been received by the Transmission Provider within such timeframe, the Interconnection Request shall continue to be evaluated under the study processes in Sections 2-13 of this GIP unless it is withdrawn by the Interconnection Customer.

14.4.2 The Interconnection Customer may specify the order in which the Transmission

Provider will complete the screens in Section 14.4.4. 14.4.3 The Interconnection Customer shall be responsible for the Transmission Provider's

actual costs for conducting the supplemental review. The Interconnection Customer must pay any review costs that exceed the deposit within 30 calendar days of receipt of the invoice or resolution of any dispute. If the deposit exceeds the invoiced costs, the Transmission Provider will return such excess within 30 calendar days of the invoice without interest.

14.4.14Within thirty (30)ten Business Days following receipt of the deposit for a

supplemental review, the Transmission Provider will determine if the Small Generating Facility can be interconnected safely and reliably. shall (1) perform a supplemental review using the screens set forth below; (2) notify in writing the Interconnection Customer of the results; and (3) include with the notification copies of the analysis and data underlying the Transmission Provider’s determinations under the screens. Unless the Interconnection Customer provided instructions for how to respond to the failure of any of the supplemental review screens below at the time the Interconnection Customer accepted the offer of supplemental review, the Transmission Provider shall notify the Interconnection Customer following the failure of any of the screens, or if it is unable to perform the screen in sSection 14.4.4.1, within two Business Days of making such

determination to obtain the Interconnection Customer’s permission to: (1) continue evaluating the proposed interconnection under this sSection 14.4.4; (2) terminate the supplemental review and continue evaluating the Small Generating Facility under Sections 2 through- Section 13; or (3) terminate the supplemental review upon withdrawal of the Interconnection Request by the Interconnection Customer.

14.4.14.1 Minimum Load Screen: Where 12 months of line section

minimum load data (including onsite load but not station service load served by the proposed Small Generating Facility) are available, can be calculated, can be estimated from existing data, or determined from a power flow model, the aggregate Generating Facility capacity on the line section is less than 100% of the minimum load for all line sections bounded by automatic sectionalizing devices upstream of the proposed Small Generating Facility. If minimum load data is not available, or cannot be calculated, estimated or determined, the Transmission Provider shall include the reason(s) that it is unable to calculate, estimate or determine minimum load in its supplemental review results notification under sSection 14.4.4.

If so, the Transmission Provider shall forward a draft GIA to the Interconnection Customer within five Business Days that requires the Interconnection Customer to pay the costs of such system modifications prior to interconnection. Interconnection Customer and Transmission Owner shall complete negotiation of the GIA as described in Section14.2.4.

14.4.4.1.1 The type of generation used by the proposed Small Generating Facility will be taken into account when calculating, estimating, or determining circuit or line section minimum load relevant for the application of screen in Section 14.4.14.1. Solar photovoltaic (PV) generation systems with no battery storage use daytime minimum load (i.e. 10 a.m. to 4 p.m. for fixed panel systems and 8 a.m. to 6 p.m. for PV systems utilizing tracking systems), while all other generation uses absolute minimum load.

14.4.4.1.2 When this screen is being applied to a Small

Generating Facility that serves some station service load, only the net injection into the Transmission Provider’s electric system will be considered as part of the aggregate generation.

14.4.4.1.3 Transmission Provider will not consider as part of the aggregate generation for purposes of this screen generating facility capacity known to be already reflected in the minimum load data.

14.4.41.2 Voltage and Power Quality Screen: In aggregate with existing generation on the line section: (1) the voltage regulation on the line section can be maintained in compliance with relevant requirements under all system conditions; (2) the voltage fluctuation is within acceptable limits as defined by Institute of Electrical and Electronics Engineers (IEEE) Standard 1453, or utility practice similar to IEEE Standard 1453; and (3) the harmonic levels meet IEEE Standard 519 limits.If so, and Interconnection Customer facility modifications are required to allow the Small Generating Facility to be interconnected consistent with safety, reliability, and power quality standards under these procedures, the Transmission Provider shall forward a draft GIA to the Interconnection Customer within five Business Days after confirmation that the Interconnection Customer has agreed to make the necessary changes at the Interconnection Customer's cost. Interconnection Customer and Transmission Owner shall complete negotiation of the GIA described in Section 14.2.4.

14.4.14.3

Safety and Reliability Screen: The location of the proposed Small Generating Facility and the aggregate generation capacity on the line section do not create impacts to safety or reliability that cannot be adequately addressed without application of the Study Process. The Transmission Provider shall give due consideration to the following and other factors in determining potential impacts to safety and reliability in applying this screen.

14.4.4.3.1 Whether the line section has significant

minimum loading levels dominated by a small number of customers (e.g., several large commercial customers).

14.4.4.3.2 Whether the loading along the line section is

uniform or even.

14.4.4.3.3 Whether the proposed Small Generating

Facility is located in close proximity to the substation (i.e., less than 2.5 electrical circuit miles), and whether the line section from the substation to the Point of Interconnection is a Mainline rated for normal and emergency ampacity.


Facility incorporates a time delay function to prevent reconnection of the generator to the system until system voltage and frequency are within normal limits for a prescribed time.

14.4.4.3.5 Whether operational flexibility is reduced by

the proposed Small Generating Facility, such that transfer of the line section(s) of the Small Generating Facility to a neighboring distribution circuit/substation may trigger overloads or voltage issues.


Facility employs equipment or systems certified by a recognized standards organization to address technical issues such as, but not limited to, islanding, reverse power flow, or voltage quality.

14.4.4.3.7 Placeholder for Transmission Owner specs

If so, and minor modifications to the Transmission Owner’s electric system are required to allow the Small Generating Facility to be interconnected consistent with safety, reliability, and power quality standards under the Fast Track Process, the Transmission Provider shall forward a GIA to the Interconnection Customer within ten Business Days that requires the Interconnection Customer to pay the costs of such system modifications prior to interconnection.

14.4.1.4 If not, the Interconnection Request will continue to be evaluated

under Sections 2-13.

14.4.5 If the proposed interconnection passes the supplemental screens in sSections 14.4.4.1, 14.4.4.2, and 14.4.4.3 above, the Interconnection Request shall be approved; provided however, if the Interconnection Request will result in an interconnection to, or modification to, the transmission facilities of Western-UGP, as Transmission Owner, such approval is subject to the completion of the appropriate NEPA level of Environmental Review and issuance of the required NEPA decisional document as will be set forth in the GIA pursuant to Section 14.3.4. The Transmission Provider will provide the Interconnection Customer with an draft GIA within the timeframes established in sSections 14.4.5.1 and 14.4.5.2 below. Interconnection Customer and Transmission Owner shall complete negotiation of the GIA described in Section 14.2.4. If the proposed interconnection fails any of the supplemental review screens and the Interconnection Customer does not withdraw its Interconnection Request, it shall continue to be evaluated under the study process in Section 3 through Section 13 consistent with sSection 14.4.5.3 below.

14.4.5.1 If the proposed interconnection passes the supplemental screens in

sSections 2.4.1.1, 2.4.1.2, and 2.4.1.3 above and does not require construction of facilities by the Transmission Provider on its own system, the GIA shall be provided within ten Business Days after the notification of the supplemental review results. Interconnection Customer and Transmission Owner shall complete negotiation of the GIA described in Section 14.2.4

14.4.5.2 If interconnection facilities or minor modifications to the

Transmission Provider's system are required for the proposed interconnection to pass the supplemental screens in sSections 14.4.1.1, 14.4.1.2, and 14.4.1.3 above, and the Interconnection Customer agrees to pay for the modifications to the Transmission Provider’s electric system, the GIA, along with a non-binding good faith estimate for the interconnection facilities and/or minor modifications, shall be provided to the Interconnection Customer within 15 Business Days after receiving written notification of the supplemental review results. Interconnection Customer and Transmission Owner shall complete negotiation of the GIA described in Section 14.2.4

14.4.5.3 If the proposed interconnection would require more than

interconnection facilities or minor modifications to the Transmission Provider’s system to pass the supplemental screens in sSections 2.4.1.1, 2.4.1.2, and 2.4.1.3 above, the Transmission Provider shall notify the Interconnection Customer, at the same

time it notifies the Interconnection Customer with the supplemental review results, that the Interconnection Request shall be evaluated under the Section 3 through Section 13 Study Process unless the Interconnection Customer withdraws its Small Generating Facility.


TRR Number 126 TRR

Title Order 1000 Aggregate Study Revisions

Cross Reference # MPRR BRR Other (Specify) _ _____________

Sponsor Name Dennis Reed E-mail Address [email protected] Company Westar Energy Phone Number 785-575-1633 Date

Tariff Section(s) Requiring Revision Attachment Y

Requested Resolution Normal Urgent (provided justification below for urgent

request)

Revision Description Tariff revisions to Attachment Y to comply with Order 1000.

Reason for Revision Compliance with Order 1000.

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 – 6-25-2014 – Unanimously Approved MOPC Board of Directors


Yes (Include any comments resulting from the review)

No

Page 1 of 8


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


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

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

Yes (Include which corporate documents)

No

Credit Implications


No

Impact Analysis Required

Yes

No

Page 2 of 8


Proposed Tariff Language Revisions (Redlined)

ATTACHMENT Y

I. OVERVIEW OF TRANSMISSION OWNER DESIGNATION PROCESS

1) The Transmission Provider shall designate a Transmission Owner in accordance with the

process set forth in Section III of this Attachment Y for transmission facilities approved for construction or endorsed by the SPP Board of Directors for which the Transmission Provider issues a Notification to Construct after January 1, 2015 that meet all of the following criteria: a) Transmission facilities that are ITP Upgrades, Service Upgrades, or high priority

upgrades; b) Transmission facilities with a nominal operating voltage of 100 kV or greater; c) Transmission facilities that are not a Rebuild of an existing facility; d) Transmission projects that do not require both a Rebuild of existing facilities and

new transmission facilities; and e) Transmission facilities that are not a Local Transmission Facility.

2) For transmission projects involving both a Rebuild of existing facilities and the

construction of new transmission facilities, the Transmission Provider shall designate the Transmission Owner(s) as follows:

a. If 80% or more of the total cost of a project consists of the Rebuild of existing

facilities, then the Transmission Provider shall designate the Transmission Owner(s) for the project in accordance with Section IV of this Attachment Y; or

b. Otherwise, the Transmission Provider shall divide the project into two or more

segments based upon whether that portion of the project is a Rebuild of existing facilities or new facilities. For those segments that are Rebuilds of existing facilities, the Transmission Provider shall designate the Transmission Owner(s) in accordance with Section IV of this Attachment Y. For those segments that are new facilities, the Transmission Provider shall designate the Transmission Owner(s) in

Page 3 of 8


accordance with Section III of this Attachment Y.

3) For any upgrade meeting the specifications listed in Section I.1 of this Attachment Y, the

Transmission Provider may designate the Transmission Owner(s) in accordance with Section IV of this Attachment Y if such upgrade is required to be in service within 3 years or less and: (i) is needed to address an identified reliability violation;, or (ii) is a Service Upgrade (“Short-Term Reliability Project”). To have a transmission project approved as a Short-Term Reliability Project, the Transmission Provider shall:

a) Separately identify and post either an explanation of the reliability violations

and system conditions for which there is a time-sensitive need, in sufficient detail to allow stakeholders to understand the need and why it is time sensitive,; or the Aggregate Transmission Service Study (“ATSS”) which identifies the need for the Service uUpgrade.

b) Provide to stakeholders and post on its website a full and supported written

description explaining:

i. The decision to designate the Transmission Owner pursuant to Section IV of this Attachment Y, including an explanation of other transmission or non-transmission options that the Transmission Provider considered but concluded would not sufficiently address the immediate reliability need; and

ii. The circumstances that generated the immediate reliability need and

an explanation of why that immediate reliability need was not identified earlier.

c) Permit stakeholders thirty (30) days to provide comments in response to the

description required under Section I.3.b of this Attachment Y and make such comments publicly available.

d) Maintain and post a list of prior year designations of Short-Term Reliability

Projects. The list must include the Short-Term Reliability Project’s need date and the date that the DTO actually energized the project. Such list must be filed with the Commission as an informational filing in January of each calendar year covering the designations of the prior calendar year.

e) Obtain approval by the SPP Board of Directors.

4) For any upgrade not defined in Section I.1 or not meeting the requirements of Sections I.2

or I.3 of this Attachment Y, the Transmission Provider shall designate the Transmission Owner(s) in accordance with the process set forth in Section IV of this Attachment Y.

5) The designation from the Transmission Provider shall be provided pursuant to Section V of

Page 4 of 8


this Attachment Y.

6) The Transmission Provider shall track all projects that are approved for construction in accordance with Section VI of this Attachment Y.

ATTACHMENT Y, Section III.2

f) Transmission Owner Selection Criteria and Scoring

i) The IEP will develop a final score for each RFP proposal and provide its recommended RFP proposal and an alternate RFP proposal to the SPP Board of Directors for each Competitive Upgrade. The IEP evaluation and recommendation shall not be administered in an unduly discriminatory manner. The RFP proposal with the highest total score may not always be recommended. The IEP may recommend that any RFP proposal be eliminated from consideration due to a low score in any individual evaluation category.

ii) The IEP may award up to one thousand (1000) base points for each RFP

proposal. Additional details on each evaluation category are provided in the Transmission Provider’s business practices. An additional one hundred (100) points shall be available to provide an incentive for stakeholders to share their ideas and expertise to promote innovation and creativity in the transmission planning process.

iii) Base Points: The evaluation categories and maximum base points for each

category are listed below.

(1) Engineering Design (Reliability/Quality/General Design), 200 points: Measures the quality of the design, material, technology, and life expectancy of the Competitive Upgrade. Criteria considered in this evaluation category shall include, but not be limited to:

(a) Type of construction (wood, steel, design loading, etc.); (b) Losses (design efficiency); (c) Estimated life of construction; and (d) Reliability/quality metrics.

(2) Project Management (Construction Project Management), 200 points: Measures an RFP respondent’s expertise in implementing construction projects similar in scope to the Competitive Upgrade that is the subject of the RFP. Criteria considered in this evaluation category shall include, but not be limited to:

Page 5 of 8


(a) Environmental; (b) Rights-of-way ownership, control or acquisition; (c) Procurement; (d) Project scope; (e) Project development schedule (including obtaining necessary regulatory approvals); (f) Construction; (g) Commissioning; (h) Timeframe to construct;

(i) RFP respondent’s plan to obtain authorization to construct transmission facilities in the state(s) in which the Competitive Upgrade will be located;

(j) RFP respondent has a right of first refusal granted under relevant law for the Competitive Upgrade; and

(k) Experience/track record. (3) Operations (Operations/Maintenance/Safety), 250 points: Measures

safety and capability of an RFP respondent to operate, maintain, and restore a transmission facility. Criteria considered in this evaluation category shall include, but not be limited to:

(a) Control center operations (staffing, etc.); (b) Storm/outage response plan; (c) Reliability metrics; (d) Restoration experience/performance; (e) Maintenance staffing/training; (f) Maintenance plans; (g) Equipment; (h) Maintenance performance/expertise; (i) NERC compliance-process/history; (j) Internal safety program; (k) Contractor safety program; and (l) Safety performance record (program execution). (4) Rate Analysis (Cost to Customer), 225 points: Measures an RFP

respondent’s cost to construct, own, operate, and maintain the Competitive Upgrade over a forty (40) year period. Criteria considered in this evaluation category shall include, but not be limited to:

(a) Estimated total cost of project; (b) Financing costs; (c) FERC incentives; (d) Revenue requirements;

Page 6 of 8


(e) Lifetime cost of the project to customers; (f) Return on equity; (g) Material on hand, assets on hand, or rights-of-way

ownership, control, or acquisition; and (h) Cost certainty guarantee.

(5) Finance (Financial Viability and Creditworthiness), 125 points:

Measures an RFP respondent’s ability to obtain financing for the Competitive Upgrade. Criteria considered in this evaluation category shall include, but not be limited to:

(a) Evidence of financing; (b) Material conditions; (c) Financial/business plan; (d) Pro forma financial statements; (e) Expected financial leverage; (f) Debt covenants; (g) Projected liquidity; (h) Dividend policy; and (i) Cash flow analysis

iv) Incentive Points: Each RFP respondent that submitted a detailed project proposal

(“DPP”) in accordance with Attachment O Section III. 8(b) of this Tariff that was

selected and approved for construction as a Competitive Upgrade shall receive one hundred

(100) incentive points in the Transmission Owner Selection Process for that Competitive

Upgrade, which shall be added to the total base points awarded by the IEP. To demonstrate

eligibility for the incentive points, the RFP respondent must document in its RFP response

that it submitted a DPP for that Competitive Upgrade. The eligibility for the incentive points

may only be awarded to the RFP respondent if the DPP was submitted during the ITP

assessment from which the Competitive Upgrade was approved. The Transmission Provider

shall confirm such eligibility in accordance with Attachment O Section III.8(b) of this Tariff

and inform the IEP. Incentive points will not be awarded to any Competitive Upgrade

approved for construction from an ATSS. A Competitive Upgrade that has already been

approved for construction by the Transmission Provider as an ITP Upgrade or high priority

upgrade and the results of an ATSS requires an earlier in-service date may be eligible for

incentive points.

Page 7 of 8


Proposed Market Protocol Language Revision (Redlined)

Proposed Business Practices Language Revision (Redlined)

Proposed Criteria Language Revision (Redlined)

Revisions to Other Corporate Documents (Redlined)

Page 8 of 8


TRR Number 127 TRR

Title Attachment J, Section III.D.2 Amending NTC Language

Cross Reference # MPRR BRR Other (Specify) _ _____________

Sponsor Name Gayle Freier E-mail Address [email protected] Company Southwest Power Pool Phone Number 501.482.2192 Date May 2, 2014

Tariff Section(s) Requiring Revision Attachment J, Section III.D.2

Requested Resolution Normal Urgent (provided justification below for urgent

request)

Revision Description Replace the language, “with Notifications to Construct issued” in this section of the Tariff with, “approved for construction” to eliminate challenges with current language and provide clarification pursuant to Order 1000.

Reason for Revision

Because the Order 1000 process could delay the issuance of Notifications to Construct (NTCs) and due to the challenges caused by the phrase “Notifications to Construct” contained in this section, additional clarification is needed in the Tariff as to what projects should be reviewed and when; thus the following amendment is recommended.

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 – 5/21/2014 – Approved (Consent Agenda) MOPC Board of Directors


Yes (Include any comments resulting from the review)

No

Page 1 of 4



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



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

Yes (Include which corporate documents)

No

Credit Implications


No

Impact Analysis Required

Yes

No

Page 2 of 4


Proposed Tariff Language Revisions (Redlined)

Attachment J

III. Base Plan Upgrades

D. Review of Base Plan Allocation Methodology

1. The Transmission Provider shall review the reasonableness of the regional

allocation methodology and factors (X% and Y%) and the zonal allocation

methodology at least once every three years in accordance with this Section III.D.

The Transmission Provider and/or the Regional State Committee may initiate such

review at any time. Any change in the regional allocation methodology and factors

or the zonal allocation methodology shall be filed with the Commission.

2. For each review conducted in accordance with Section III.D.1, the Transmission

Provider shall determine the cost allocation impacts of the Base Plan Upgrades

approved for construction with Notifications to Construct issued after June 19,

2010 to each pricing Zone within the SPP Region. The Transmission Provider in

collaboration with the Regional State Committee shall determine the cost allocation

impacts utilizing the analysis specified in Section III.e of Attachment O and the

results produced by the analytical methods defined pursuant to Section III.D.4(i) of

this Attachment J.

Proposed Market Protocol Language Revision (Redlined)

Page 3 of 4


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

Page 4 of 4

TRR 133


TRR Number 133 TRR Title Interest on Refunds

Cross Reference Number MPRR BRR Other (Specify) ___________

Sponsor Name Charles Locke E-mail Address [email protected] Company Southwest Power Pool Phone Number 501-482-2276 Date June 20, 2014

Tariff Section(s) Requiring Revision

Requested Resolution Normal Urgent

Provide explanation if Urgent is selected:

Revision Description Removed tariff requirements to pay interest at the rate specified in 18 CFR § 35.19a(a)(2)(iii) in sections where such a requirement could impose a financing burden on the SPP membership. Replaced the requirement to pay interest at the CFR rate with a requirement to pay interest based on actual earnings.

Reason for Revision With this change, the difference between the interest required under 18 CFR § 35.19a(a)(2)(iii) and the interest earned by SPP in the bank accounts where it holds deposit amounts will not have to be funded through membership charges under Schedule 1-A. This will reduce charges to members.

Stakeholder Approval Required (Record date and outcome of vote; N/A for those stakeholders not required)

RTWG—6-26-2014 - Approved with One Abstention (AECC) MWG— BPWG—(N/A) TWG—(N/A) ORWG—(N/A) Other (specify)—(N/A) MOPC— Board of Directors—


Yes—(Include any comments from the review)

No

Page 1 of 11

Market Protocols Implications or Changes


No

Business Practices Implications or Changes


No



No

Other Corporate Documents Implications or Changes (i.e., SPP Bylaws, Membership Agreement, etc.)


No

Credit Implications

Yes—(Include a summary of impact and/or specific changes) Interest for customer refunds will be self-funded through earnings on bank deposits. Alleviates the need for Schedule 1-A to include interest for refunds.

No

Impact Analysis Required Yes

No

Proposed Tariff Language Revision (Redlined)

ATTACHMENT U

RATE SCHEDULE FOR COMPENSATION FOR RESCHEDULED MAINTENANCE COSTS B. Recovery of Compensation Costs by the Transmission Provider

The Transmission Provider shall be entitled to recover all costs associated with the compensation

of generation owners, or Transmission Owners pursuant to this Rate Schedule on a monthly basis. In

order to recover these costs, the Transmission Provider shall add an additional monthly charge to the

base transmission charges under this Tariff calculated using the following formula:

Page 2 of 11

X=Y/Z

Where:

X=Monthly maintenance reschedule charge adder(per kw/month)

Y=Rescheduled Maintenance Costs calculated in accordance with Section A above and any true-

up with interest on the true-up amount.

Z=Transmission System Peak for the same month minus coincident peak usage of all Firm Point-

To-Point Transmission Service plus Reserved Capacity of all Firm Point-To-Point Transmission

Service customers.

The Transmission Provider shall apply this charge to all customers under the Tariff in addition to

the base transmission charge. The charge developed above is the rate for monthly service. The rate for

weekly service will be the product of the monthly rate and 12 divided by 52. The rate for (on-peak)

daily service will be the product of the monthly rate and 12 divided by 260. The rate for (on-peak)

hourly service will be the product of the monthly rate and 12 divided by 4160. The rate for off-peak

daily service will be the product of the monthly rate and 12 divided by 365. The rate for off-peak hourly

service will be the product of the monthly rate and 12 divided by 8760. The on-peak period shall be

6:00 a.m. - 10:00 p.m.

Monday through Friday. The total charge paid by a customer under this Attachment U pursuant

to a reservation for hourly delivery shall not exceed the above on-peak daily rate times the highest

amount of Reserved Capacity in any hour during such day. In addition, the total charge under this

Attachment U in any week, pursuant to a reservation for hourly or daily delivery, shall not exceed the

above rate specified for weekly delivery times the highest amount of Reserved Capacity in any hour

during such week.

Each Transmission Customer taking Point-To-Point Transmission Service shall pay the product

of the applicable charge developed above multiplied by its applicable Point-To-Point Transmission

Service reservations. Each Network Customer shall pay the product of the applicable charge developed

above multiplied by the Network Customer’s load at the time of the monthly peak. For purposes of this

Attachment U, network load includes bundled load and load under Grandfathered Agreements served by

Transmission Owners for which the Transmission Owners are not otherwise paying the Transmission

Provider for Network Integration Transmission Service. The Transmission Provider shall recover the

costs arising under this Attachment U that are not recovered from Point-To-Point Transmission Service

customers or from Network Customers paying the Transmission Provider for Network Integration

Transmission Service by charging the Transmission Owners serving such bundled and grandfathered

Page 3 of 11

loads for such costs. The Transmission Owners shall be allocated these remaining amounts based upon

their relative proportions of these loads.

In deriving the charges, the Transmission Provider may estimate and bill the compensatory costs

it owes or will owe. The Transmission Provider shall true-up that estimate in a later month, as provided

below, with any accrued interest, calculated in accordance with Section 35.19 (a) of the Commission’s

regulations once actuals are available (such interest will be credited to the customer for over-estimates

or to the generation owner or Transmission Owner that has rescheduled maintenance for

underestimates).

The Transmission Provider shall true-up on a monthly basis within two months after receiving

actuals for any part of rescheduled maintenance. Such true-ups will involve changes based upon a

further evaluation of estimates used for opportunity costs or revisions of bills previously received by the

Transmission Provider. The Transmission Provider shall make available upon request the data and

information supporting any rescheduled maintenance costs for a period of one year after the amounts are

billed. If a Transmission Customer disagrees with the amounts charged, it may pursue the matter

through dispute resolution procedures or by complaint.

Page 4 of 11

ATTACHMENT V GENERATOR INTERCONNECTION PROCEDURES (GIP)

3.6 Withdrawal.

Interconnection Customer may withdraw its Interconnection Request at any time by written notice of such withdrawal to Transmission Provider. In addition, if Interconnection Customer fails to adhere to all requirements of this GIP, except as provided in Section 13.5 (Disputes), Transmission Provider shall deem the Interconnection Request to be withdrawn and shall provide written notice to Interconnection Customer of the deemed withdrawal and an explanation of the reasons for such deemed withdrawal. Upon receipt of such written notice, Interconnection Customer shall have fifteen (15) Business Days in which to either respond with information or actions that cures the deficiency or to notify Transmission Provider of its intent to pursue Dispute Resolution.

Withdrawal shall result in the loss of Interconnection Customer's Queue Position. If an Interconnection Customer disputes the withdrawal and loss of its Queue Position, then during Dispute Resolution, Interconnection Customer's Interconnection Request is eliminated from the Queue until such time that the outcome of Dispute Resolution would restore its Queue Position. An Interconnection Customer that withdraws or is deemed to have withdrawn its Interconnection Request shall pay to Transmission Provider all costs that Transmission Provider prudently incurs with respect to that Interconnection Request prior to Transmission Provider's receipt of notice described above. Interconnection Customer must pay all monies due to Transmission Provider before it is allowed to obtain any Interconnection Study data or results.

Transmission Provider shall (i) update the OASIS Queue Position posting and (ii) refund to Interconnection Customer any portion of Interconnection Customer's deposit or study payments that exceeds the costs that Transmission Provider has incurred, including interest earned in the interest-bearing account in which Transmission Provider shall have deposited such amount calculated in accordance with section 35.19a(a)(2) of FERC's regulations. In the event of such withdrawal, Transmission Provider, subject to the confidentiality provisions of Section 13.1, shall provide, at Interconnection Customer's request, all information that Transmission Provider developed for any completed study conducted up to the date of withdrawal of the Interconnection Request.

APPENDIX 2 TO GIP INTERCONNECTION FEASIBILITY STUDY AGREEMENT

14.5 Disputes. In the event of a billing dispute between Transmission Provider and

Interconnection Customer, Transmission Provider shall continue to provide studies for Interconnection Service under the GIP as long as Interconnection Customer: (i) continues

Page 5 of 11

to make all payments not in dispute; and (ii) pays to Transmission Provider or into an independent escrow account the portion of the invoice in dispute, pending resolution of such dispute. If Interconnection Customer fails to meet these two requirements for continuation of service, then Transmission Provider may provide notice to Interconnection Customer of a Default pursuant to Article 16. Within thirty (30) Calendar Days after the resolution of the dispute, the Party that owes money to the other Party shall pay the amount due together with accrued interest in accordance with Section 3.6 of this Attachment V calculated in accord with the methodology set forth in FERC's regulations at 18 CFR § 35.19a(a)(2)(iii).

APPENDIX 3 TO GIP

PRELIMINARY INTERCONNECTION SYSTEM IMPACT STUDY AGREEMENT

14.5 Disputes. In the event of a billing dispute between Transmission Provider and Interconnection Customer, Transmission Provider shall continue to provide studies for Interconnection Service under the GIP as long as Interconnection Customer: (i) continues to make all payments not in dispute; and (ii) pays to Transmission Provider or into an independent escrow account the portion of the invoice in dispute, pending resolution of such dispute. If Interconnection Customer fails to meet these two requirements for continuation of service, then Transmission Provider may provide notice to Interconnection Customer of a Default pursuant to Article 16. Within thirty (30) Calendar Days after the resolution of the dispute, the Party that owes money to the other Party shall pay the amount due together with accrued interest in accordance with Section 3.6 of this Attachment V calculated in accord with the methodology set forth in FERC's regulations at 18 CFR § 35.19a(a)(2)(iii).

APPENDIX 3A TO GIP

DEFINITIVE INTERCONNECTION SYSTEM IMPACT STUDY AGREEMENT

14.5 Disputes. In the event of a billing dispute between Transmission Provider and Interconnection Customer, Transmission Provider shall continue to provide studies for Interconnection Service under the GIP as long as Interconnection Customer: (i) continues to make all payments not in dispute; and (ii) pays to Transmission Provider or into an independent escrow account the portion of the invoice in dispute, pending resolution of such dispute. If Interconnection Customer fails to meet these two requirements for continuation of service, then Transmission Provider may provide notice to Interconnection Customer of a Default pursuant to Article 16. Within thirty (30) Calendar Days after the resolution of the dispute, the Party that owes money to the other Party shall pay the amount due together with accrued interest in accordance with Section 3.6 of this Attachment Vcalculated in accord with the methodology set forth in FERC's regulations at 18 CFR § 35.19a(a)(2)(iii).

APPENDIX 4 TO GIP

INTERCONNECTION FACILITIES STUDY AGREEMENT

14.5 Disputes. In the event of a billing dispute between Transmission Provider and Interconnection Customer, Transmission Provider shall continue to provide studies for

Page 6 of 11

Interconnection Service under the GIP as long as Interconnection Customer: (i) continues to make all payments not in dispute; and (ii) pays to Transmission Provider or into an independent escrow account the portion of the invoice in dispute, pending resolution of such dispute. If Interconnection Customer fails to meet these two requirements for continuation of service, then Transmission Provider may provide notice to Interconnection Customer of a Default pursuant to Article 16. Within thirty (30) Calendar Days after the resolution of the dispute, the Party that owes money to the other Party shall pay the amount due together with accrued interest in accordance with Section 3.6 of this Attachment Vcalculated in accord with the methodology set forth in FERC's regulations at 18 CFR § 35.19a(a)(2)(iii).

APPENDIX 4A TO GIP

LIMITED OPERATION INTERCONNECTION FACILITIES STUDY AGREEMENT


APPENDIX 5 TO GIP

INTERIM AVAILABILITY INTERCONNECTION SYSTEM IMPACT STUDY AGREEMENT


ATTACHMENT AQ DELIVERY POINT ADDITION PROCESS

Page 7 of 11

3.0 Studies: The Transmission Provider and Host Transmission Owner shall conduct all necessary

studies associated with the delivery point change. Such studies shall be conducted at Transmission

Customer’s expense pursuant to the provisions of this section. In the event that such change in delivery

point configuration results in significant impact on the Transmission System, Transmission Provider will

coordinate the studies necessary to evaluate such addition or modification. Otherwise, the Host

Transmission Owner will coordinate the studies.

3.1 Load Connection Study: Host Transmission Owner shall respond within ten (10)

Business Days of receipt of such request and, if necessary, provide a Load Connection Study

(“LCS”) Agreement and a list of any additional information that Host Transmission Owner would

require from the Transmission Customer to proceed with such study. Unless otherwise agreed, the

LCS Agreement shall commit the Transmission Customer to pay Host Transmission Owner the

actual cost to complete the study. The Host Transmission Owner may require an advance deposit

equal to the estimated study cost or $25,000, whichever is less. In conducting the LCS, the Host

Transmission Owner shall assess the feasibility of modifying an existing delivery point or

establishing the new delivery point using power flow and short circuit analyses and any other

analyses that may be appropriate. It shall also determine the details and estimated cost of facilities

necessary for establishing the requested delivery point and any system additions/upgrades needed

to address any problems identified in the LCS.

If the Transmission Customer fails to return an executed LCS Agreement within thirty (30)

Calendar Days of receipt along with the required deposit, or at a later date as the Parties may

mutually agree, Host Transmission Owner shall deem the study request to be withdrawn. The

Transmission Customer may withdraw its study request at any time by written notice of such

withdrawal to Host Transmission Owner. Host Transmission Owner shall complete the LCS and

issue a Load Connection Report to the Transmission Customer and Transmission Provider within

sixty (60) Calendar Days after receipt of an executed LCS Agreement, deposit and necessary data,

or at a later date as the Parties may mutually agree.

Upon completion of the LCS, the Transmission Customer shall reimburse Host Transmission

Owner for the unpaid cost of the LCS if the cost of LCS exceeds the deposit. Host Transmission

Owner shall refund to the Transmission Customer any portion of the deposit that exceeds the cost

Page 8 of 11

of the LCS, with interest earned in the interest-bearing account in which Transmission Owner

hasshall have placed the deposit, or if such account does not exist, with interest calculated in

accordance with 18 C.F.R. § 35.19a(a)(2)., any portion of the deposit that exceeds the cost of the

LCS. The interest rate will be computed in accordance with 18 C.F.R. § 35.19a(a)(2).

3.2 Transmission System Study: Upon receipt of the Request for Change in Local

Delivery Facilities, Transmission Provider shall perform a preliminary assessment of the impact of

the requested delivery point configuration change on the Transmission System. On or before the

20th day of the succeeding month, Transmission Provider shall conclude its preliminary assessment

of the impact of each requested delivery point configuration change on the Transmission System

for all Requests for Change in Local Delivery Facilities received in the current calendar month and

post its findings on the SPP website. For all requests for which the Transmission Provider finds no

significant impact on the Transmission System, Host Transmission Owner will coordinate

completion of such change in local delivery facilities, including all required studies. For all

requests for which the Transmission Provider finds that there is significant impact on the

Transmission System, it shall, within five (5) days of posting of the results of the preliminary

assessment, deliver to the Transmission Customer a Delivery Point Network Study (“DPNS”)

Agreement and a request for any additional information that it requires from the Transmission

Customer to proceed with such study. The study agreement shall commit the Transmission

Customer to pay the Transmission Provider the actual cost to complete the study and to make an

advance deposit equal to the estimated study cost or $25,000, whichever is less. The Transmission

Customer shall execute and deliver the DPNS Agreement and required deposit to the Transmission

Provider as soon as reasonably possible, but not later than thirty (30) Calendar Days following its

receipt or at a later date as the Parties may mutually agree. Upon receipt of the executed study

agreement, study data, and the required deposit, Transmission Provider shall perform the DPNS.

During the conduct of the DPNS, Transmission Provider shall assess the impacts on the

Transmission System caused by modifying an existing delivery point or establishing the new

delivery point using power flow and short circuit analyses and any other analyses that may be

appropriate.

If the Transmission Customer fails to return an executed DPNS Agreement within thirty (30)

Calendar Days of receipt or at a later date as the Parties may mutually agree, Transmission

Provider and Host Transmission Owner shall deem the study request to be withdrawn. The

Page 9 of 11

Transmission Customer may withdraw its study request at any time by written notice of such

withdrawal to the Transmission Provider and the Host Transmission Owner.

Transmission Provider shall issue a study report to the Transmission Customer and Host

Transmission Owner within sixty (60) Calendar Days of the receipt of an executed DPNS

Agreement, or at a later date as the Parties may mutually agree. If Transmission Provider is unable

to complete such study in the allotted time, Transmission Provider shall provide an explanation to

the Transmission Customer and Host Transmission Owner regarding the cause(s) of such delay

and a revised completion date and study cost estimate.

Upon completion of the DPNS, the Transmission Customer shall reimburse Transmission Provider

for the unpaid cost of the DPNS if the cost of the study exceeds the deposit. Transmission

Provider shall refund the Transmission Customer, with interest earned in the interest-bearing

account in which Transmission Provider shall have placed the deposit, any portion of the deposit

that exceeds the cost of the DPNS. The interest rate will be computed in accordance with 18

C.F.R. § 35.19a(a)(2).

3.3 Modifications to Study Request: During the course of a LCS or DPNS, the

Transmission Customer, Host Transmission Owner or Transmission Provider may identify

desirable changes in the planned facilities that may improve the costs and/or benefits (including

reliability) of the planned facilities. To the extent the revised plan and study schedule are

acceptable to Host Transmission Owner, Transmission Customer, and if applicable, Transmission

Provider, such acceptance not to be unreasonably withheld, Host Transmission Owner and if

applicable, Transmission Provider, shall, at Transmission Customer’s Expense, proceed with any

necessary restudy.

Proposed Market Protocols Language Revision (Redlined)

Page 10 of 11

Proposed Business Practices Language Revision (Redlined)

Proposed Criteria Language Revision (Redlined)

Proposed Revisions to Other Corporate Documents (Redlined)

Page 11 of 11

Southwest Power Pool, Inc. MARKETS AND OPERATION POLICY COMMITTEE

Recommendation to the Board of Directors August 29, 2014

CRR – 013

Organizational Roster The following persons are members of the Transmission Working Group:

Mo Awad, Westar Energy, Inc. Scott Benson, LES John Boshears, CUS John Fulton, SPS Joe Fultz, GRDA Travis Hyde, OG&E Dan Lenihan, OPPD Randy Lindstrom, NPPD Jim McAvoy, OMPA Matt McGee, AEP

Nathan McNeil, Midwest Energy Nate Morris, EMDE Michael Mueller, AECC Alan Myers, ITC Great Plains John Payne, KEPCo Jason Shook, GDS Associates for ETEC Tim Smith, WFEC Jeff Stebbins, TCEC Noman Williams, SUNC Harold Wyble, KCP&L

Background Modify the SPP Criteria to allow TOs the ability to rate transmission elements more stringently according to their own facility ratings methodology

Analysis The Transmission Working Group (TWG) created the TWG Criteria Review Task Force (CRTF) to review the portions of the SPP Criteria that are owned by the TWG. During the CRTF review of the SPP Criteria, Criteria 12.2 came up for discussion. This section details a methodology for rating elements of the transmission grid.

The task force realized during its review that SPP Criteria Section 12.2 may need to be updated based on the implementation of NERC Standard FAC-008. This NERC standard, which was approved after the creation of SPP Criteria Section 12.2, requires Transmission Owners (TOs) to maintain their own facility ratings methodology. The task force realized that there could be a discrepancy between the language in SPP Criteria Section 12.2 and an individual TOs methodology when rating certain transmission facilities. In some cases, TOs rate certain facilities more stringently according to their facility ratings methodology. In these situations, there could be questions that arise during an audit. In order to allow TOs the ability to rate certain facilities more stringently as allowed by their own facility ratings methodology, the task force recommended to the TWG that the language be modified. The TWG reviewed the CRTF recommendation and reviewed the language of SPP Criteria 12.2. The TWG voted to approve the attached Criteria Revision Request.

Recommendation The MOPC recommends the BOD approve the modification SPP Criteria 12.2.

Approved: TWG

17 votes for, 2 votes against, 0 abstentions

05/20/2014

MOPC

Passed Unanimously

07/15/2014

Action Requested: Approve Recommendation

Criteria Revision Request

CRR No. 013 CRR

Title Criteria 12.2 Facility Ratings Methodology

Criteria Section(s) Requiring Revision

Section No.: 12.2 Title: Facility Ratings Methodology

Date 7/29/2014

Impact Analysis Required Yes – If yes, estimated cost: TBD No

Requested Resolution Normal Expedited Urgent Action



Policy Change

Revision Description To allow transmission owners the maintain a more stringent facility ratings methodology than described in the SPP Criteria

Reason for Revision

NERC Standard FAC-008 requires Transmission Owners to have their own facility ratings methodology. SPP Criteria 12.2 was written before FAC-008 was approved. Since a facility ratings methodology is required per NERC Standards this revision will allow SPP members to maintain more stringent facility ratings methodology than is required by the SPP Criteria.


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

No

Protocol Implications or Changes

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

No

ORWG Review Date of Vote: Vote: Opposed: Abstained:

TWG Review Date of Vote: 05/20/2014 Vote: Approved Opposed: 2 Abstained: 0

CWG Review Date of Vote: 07/15/2014 Vote: Approved Opposed: 0 Abstained: 0

MWG Review Date of Vote: Vote: Opposed: Abstained:

MOPC Review Date of Vote: Vote: Opposed: Abstained:

Board Review Date of Vote: Vote: Opposed: Abstained:

Sponsor

Name Mo Awad E-mail Address [email protected] Company Westar Energy, Inc. Phone Number Date

Revision Name Kirk Hall E-mail Address [email protected] Company Southwest Power Pool Phone Number Date


Proposed Criteria Language Revision Each SPP member shall rate transmission circuits operated at 69 kV and above in accordance with this criteria. A transmission circuit shall consist of all elements load carrying between circuit breakers or the comparable switching devices. Transformers with both primary and secondary windings energized at 69 kV or above are subject to this criteria. All circuit ratings shall be computed with the system operated in its normal state (all lines and buses in-service, all breakers with normal status, all loads served from their normal source). The circuit ratings will be specified in "MVA" and are taken as the minimum ratings of all of the elements in series. The minimum circuit rating shall be determined as described in this criteria and members shall maintain transmission right-of-way to operate at this rating. However, SPP members may use circuit ratings higher than these minimums. Each element of a circuit shall have a normal and an emergency rating. For certain equipment, (switches, wave traps, current transformers and circuit breakers), these two ratings are identical and are defined as follows:

a. NORMAL RATING: Normal circuit ratings specify the level of power flow that facilities can carry continuously without loss of life to the facility involved.

b. EMERGENCY RATING: Emergency circuit ratings specify the level of power flow that a facility can carry for the time sufficient for adjustment of transfer schedules, generation dispatch, or line switching in an orderly manner with acceptable loss of life to the facility involved.

At a minimum, each member shall compute summer and winter seasonal ratings for each circuit element. The summer season is defined by the months June, July, August and September.

Southwest Power Pool, Inc. MARKETS AND OPERATIONS POLICY COMMITTEE

Request for Board of Director’s Endorsement July 29, 2014

Endorsement of Misoperations Whitepaper

Organizational Roster The following persons are members of the SPCWG:

Rick Gurley, AEP (Chair) Bud Averill, GRDA (Vice Chair) Tom Miller, ITC Louis Guidry, CLECO Shawn Jacobs, OGE Mathew Thykkuttathil, Sunflower

Heidt Melson, Xcel Energy Steve Wadas, OPPD Brent Carr, AECC Ken Zellefrow, SPRM Lynn Schroeder, Westar Doug Bowman, SPP (Secretary)

Background Due to an increase in relay misoperations in the SPP footprint, the SPCWG was requested to analyze communications related misoperations, and make recommendations on how to prevent future. misoperations.

Analysis The attached whitepaper provides an analysis of causes as well as lessons learned and recommendations to reduce the number of future misoperations.

Recommendation The MOPC requests that the BOD endorse the whitepaper and agree to an additional presentation as part of the SPP RE’s Fall 2014 Compliance Workshop. With MOPC’s permission, the SPCWG will post the whitepaper to the SPCWG Web Page and use the SPCWG exploder list to notify all subscribers of its presence.

Action Requested: Provide Endorsement


Passed Unanimously

201 Worthen Drive Little Rock, AR 72223

www.spp.org

Relay Communication Misoperations

By: System Protection and Control Working Group

July 16, 2014

An SPP White Paper

1

Contents Introduction 3 Purpose 3 Design Considerations 4 Risk Assessment and Operating Considerations 5 Analysis of Communication Related Misoperations 5 Root Causes 8 Lessons Learned 9 Conclusions 9 Reference 9

2

Introduction The fundamental objective of power system protection is to quickly provide isolation of a system problem while leaving the remainder of the system intact. There are times, however, that the protection system operates incorrectly or “misoperates” due to failure, malfunction, or various other reasons which may result in tripping of unfaulted elements.

Purpose In recent years, relay misoperations within the SPP footprint have become a higher concern for SPP, the SPCWG, and for NERC. Analysis, as shown in Figure 1, indicates that misoperations due to communication system failure are a leading cause. This whitepaper discusses these communication misoperations and analyzes data taken over one year to determine their root cause. Lessons learned are then provided that can be translated into field application, thus reducing the number of future misoperations.

Figure 1: Misoperation Causes 1Q 2011 to 3Q 2013

3

Design Considerations Communication assisted protection schemes are applied to provide high speed tripping for faults over 100% of the transmission line length. These schemes are not mandatory from a regulatory perspective unless driven by a transmission planning (TPL) compliance concern such as critical clearing time to maintain stability. These schemes are typically installed to improve power quality and reduce equipment damage due to fault duration. These communication assisted schemes are designed to provide either increased dependability or increased security. These are defined as: Dependability – the assurance that any fault will be cleared. Security – the assurance that a trip occurs only for faults on the protected line. The three (3) common types of communication assisted protection schemes are:

1. Differential – Operates on the principle that the relays at all ends of a line measure the current and communicate to ensure that the amount of current going into the line equals the current going out, or else a fault is assumed.

This scheme is biased more toward security than dependability.

2. Permissive – Operates on the principle that the relays at all ends of a line detect a fault and communicate to agree that the fault appears in the forward looking direction (on the protected line) for which a trip with no intentional time delay will occur. Otherwise, a trip occurs only after a time delay.

This scheme is biased more toward security than dependability.

3. Blocking – Operates on the principle that the relays at all ends of a line each individually detect a fault and that the fault appears in the forward looking direction, for which they trip with no intentional time delay, unless a remote end relay communicates that the fault is in the reverse direction. Only then will they trip after a time delay.

This scheme is biased more toward dependability than security.

Blocking schemes (also referred to as Directional Comparison Blocking or DCB) are typically chosen when a failure to trip will be more detrimental to the system than over-tripping. This scheme is immune to failing to trip for a fault on the protected line if communication is lost in conjunction with that fault, since tripping will occur when

4

no signal (Block) is received. These schemes are designed to reach (to detect faults) past the end of the line and trip with no intentional delay unless a signal is received from the remote end to block the local breaker from tripping. This provides dependability but increases the chance of over-tripping if the block signal is not received for faults beyond the remote end breaker, making the scheme less secure

Risk Assessment and Operating Considerations

Occasionally a deteriorated communication scheme will need to be temporarily left in service due to customer considerations (avoiding prolonged voltage dip). Should this decision be made, there remains a possibility of misoperations until corrective actions can be completed. Stability related issues and risk of equipment damage can also be reasons to keep a deteriorated scheme in service.

Analysis of Communication Related Misoperations To assist in the analysis of the communication related misoperations, the System Protection & Control Working Group (SPCWG) referred to a recently completed (April 2013) analysis by the NERC Protection System Misoperations Task Force (PSMTF). The PSMTF came up with “sub-causes” for misoperations related to communications failures. The SPCWG chose to use these same sub-causes for its analysis, to provide consistency with the PSMTF’s analysis. The PSMTF determined that these misoperations could be broken down into one of the following five sub-causes:

1. Communication Interface Failure (Modulator): Power-line carrier radios, fiber optic interfaces, microwave radios, audio-tone/telecommunications, and pilot wire components.

2. Communication Medium: The external signal path, leased phone circuits, cables, transmission lines, etc.

3. Station Signal Path Failure: All signal carrying components within the substation fence including cables, frequency filters, connectors, etc.

4. Incorrect Logic Settings Issued: Channel timing, dip switches, etc. Protective relay settings were considered as a settings problem and not counted as a logic issue. (This is difficult to determine when digital relays contain both logic and settings).

5. Human Error (Misapplication in field): Incorrect settings both logic and relay reach, as left conditions, etc.

In addition there were some events for which there was insufficient information.

Figure 2 identifies the communication components for a typical power line carrier scheme and related misoperation sub-causes1.

5

Figure 2: Communication Failure Misoperations

The SPCWG added two additional categories for misoperations for events that did not fit within the five PSMTF sub-causes. These are: Limited Investigation Due to Equipment Upgrade, and Other. The SPCWG reviewed 101 misoperations that occurred in SPP for a one year period, from the fourth quarter of 2012 through the third quarter of 2013. The graph shown in Figure 3 shows the results of the analysis. The two sub-causes with the most misoperations were 1.) Communication Interface Failure, and 2.) Station Signal Path Failure. The misoperations data shows that a majority of line protection schemes are designed to use Blocking systems. As described above, Blocking systems are more susceptible to misoperating when the communications system becomes deteriorated; however, blocking schemes are also more secure for clearing of faults when the communications system becomes deteriorated.

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Figure 3: Total Failures By Sub-cause Comparing the SPP analysis with the NERC PSMTF analysis, there were a few differences. The table below shows the percentage of misperations by sub-cause for both SPP and NERC.

Sub-cause SPCWG Analysis NERC Analysis Communication Interface

Failure (Modulator)

29%

32% Communication Medium 3% 16%

Station Signal Path Failure 35% 17% Incorrect Logic Settings

Issued

1%

6% Human Error 1% 3%

Insufficient/No Data 11% 27% Limited Investigation Due To Equipment Upgrade

18%

Other 2% ---

Table 1: SPP/NERC Communication Misoperation Sub-cause Comparison

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Root Causes The following are examples or possible root causes for each of the sub-cause categories.

1. Communication Interface Failure • Shorted surge protection (Transient Voltage Suppressor) • Failed Transceiver

2. Communication Medium

• Failed wave trap (tuning out of adjustment or malfunction) • Loss or degradation of signal (microwave or tone signals) • Lack of wave traps at tapped load locations (results in loss of signal)

3. Station Signal Path Failure

• Protective Gap calibration • Deteriorated spark gaps in the line tuner • Failed component in the line tuner

4. Incorrect Logic Settings

• Incorrect communication settings in the carrier or relay

5. Human Error • Carrier cutoff left off at one terminal and on at the other terminal. • Ground switch on CCVT left in “ground” position

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Lessons Learned

Lessons Learned: • Equipment spark gaps, insulators, and surge arresters are known to cause

carrier holes if not maintained properly • Fiber optic communications provide increased reliability and security over

microwave or power line carrier systems o Power Line Carrier systems are subject to “carrier holes” o Microwave systems have issues with signal fading

• End-to-end testing is advantageous during commissioning to find timing errors and to confirm signal quality

• Deteriorated, older equipment requires increased maintenance activity and is more likely to fail than newer equipment. Diagnostic capabilities are lacking as well.

• Mismatched equipment or differing setting philosophies at opposite ends of the line can create timing issues resulting in misoperation.

Conclusions Communications assisted schemes add sophistication to line protection schemes and provide the advantage of high speed clearing of faults, which improves power quality for our customers. The increased complexity of these schemes also means there are more components that require maintenance and possible replacement when they become deteriorated. Historically, the most prevalent design used by utilities has been Blocking schemes which err on the side dependability, resulting in a tendency to trip unnecessarily rather than failing to trip. As a result, when the communications systems do not work properly, misoperations occur. This document provides information on the background of the misoperations that have occurred in SPP and identifies root causes. Knowing the root causes enables utilities to more accurately trouble shoot problems and take preventive measures to reduce the likelihood of misoperations in the future. The lessons learned provide specific information that can be acted on to help prevent misoperations.

Reference [1] “Misoperations Report, Prepared by: Protection System Misoperations Task Force”, by North American Electric Reliability Corporation (2013).

9

Southwest Power Pool, Inc. Markets and Operations Policy Committee Recommendation to the Board of Directors

Legacy Project Baseline Cost Estimate Report July 29, 2014

Organizational Roster The following persons represent the Southwest Power Pool:

Carl Monroe, Executive Vice President and Chief Operating Officer Lanny Nickell, Vice President, Engineering Antoine Lucas, Director, Planning

Background Business Practice 7060 describes the Notification to Construct (NTC) and cost estimation process for all Projects issued NTCs on or after January 1, 2012. At its October 2013 meeting, the Markets and Operations Policy Committee (MOPC) approved the recommendation made by the Project Cost Working Group to move all Projects with NTCs issued prior to January 1, 2012, called Legacy Projects, from Business Practice 7050 to Business Practice 7060. The change allows the new monitoring process to be applied to Legacy Projects where cost estimates are established as baselines for future cost variance determinations. Previously under Business Practice 7050, cost variances were determined on a quarter by quarter basis.

Revisions to Business Practice 7060 to incorporate the recommendation were approved by the MOPC at its January 2014 meeting.

Analysis The updated Business Practice stipulates in Section 5.2 that baseline cost estimates for Legacy Projects will be established as the cost estimate values within the Project Tracking database, as of January 31, 2014, and require approval by the SPP Board of Directors.

Recommendation MOPC recommends that the Board of Directors approve the Legacy Project Baseline Cost Estimate Report to establish the baseline cost estimate values for Legacy Projects. Action Requested: Approve Legacy Project Baseline Cost Estimate Report as presented.

APPROVED: MOPC July 15-16, 2014 Passed Unanimously

L e g a c y P r o j e c t B a s e l i n e C o s t E s t i m a t e R e p o r t

July 2014


Summary

Business Practice 7060 describes the Notification to Construct (NTC) and cost estimation process for all Projects issued NTCs on or after January 1, 2012. At its October 2013 meeting, the Markets and Operations Policy Committee (MOPC) approved the recommendation made by the Project Cost Working Group to move all Projects with NTCs issued prior to January 1, 2012, called Legacy Projects, from Business Practice 7050 to Business Practice 7060. The change allows the new monitoring process to be applied to Legacy Projects where cost estimates are established as baselines for future cost variance determinations. Previously under Business Practice 7050, cost variances were determined on a quarter by quarter basis. Revisions to Business Practice 7060 to incorporate the recommendation were approved by the MOPC at its January 2014 meeting. The updated Business Practice stipulates in Section 5.2 that baseline cost estimates for Legacy Projects will be established as the cost estimate values within the Project Tracking database, as of January 31, 2014, and require approval by the SPP Board of Directors. The list of Legacy Projects and their cost estimate values as of January 31, 2014, are included in Table 1. The total estimated cost of the Legacy Projects listed in Table 1 is $2,340,685,577. This represents an increase of 28.7% from the sum of the original estimated costs for the same Projects.

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4 136 10174 WFEC HAMMETT - MEEKER 138KV CKT

1 Regional

Reliability 6/1/2015 6/1/2008 $6,674,000

137 10175 WFEC HAZELTON JCT - WAKITA 69KV CKT 1

Regional Reliability 4/1/2009 $8,000,000

138 10176 WFEC WOODWARD - WOODWARD 69KV CKT 1

Regional Reliability 6/1/2015 4/1/2009 $1,050,000

140 10179 WFEC ACME - WEST NORMAN 69KV CKT 1

Regional Reliability 12/1/2014 6/1/2008 $912,000

235 10300 OGE COLONY - FT SMITH 161KV CKT 1 #2


241 10307 WFEC ANADARKO - GEORGIA 138KV CKT 1


242 10308 WFEC ELMORE - PAOLI 69KV CKT 1 Regional Reliability 12/2/2014 6/1/2009 $3,240,000

311 10401 WFEC ACME - FRANKLIN SW 138KV CKT 1


311 10402 WFEC ACME - WEST NORMAN 138KV CKT 1


311 10403 WFEC OU SW - WEST NORMAN 138KV Regional 12/31/2014 6/1/2010 $1,577,000

Legacy Project Baseline Cost Estimate Report 1


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CKT 1 Reliability

361 10471 WFEC FLETCHER - MARLOW JCT 69KV CKT 1


399 10519 WFEC LINDSAY SW - WALLVILLE 69KV CKT 1


402 10522 WFEC GRANDFIELD - INDIAHOMA 138KV CKT 1


402 10523 WFEC CACHE - INDIAHOMA 138KV CKT 1


402 10524 WFEC GRANDFIELD 138/69KV TRANSFORMER CKT 1


450 10582 AEP EAST CENTERTON - SHIPE ROAD 161KV CKT 1


450 10584 AEP Shipe Road 345/161 kV transformer Ckt 1


450 10585 AEP Flint Creek - Shipe Road 345 kV Ckt 1


479 10616 AEP GEORGIA-PACIFIC - KEATCHIE REC 138KV CKT 1


511 10656 AEP Kings River 345/161KV TRANSFORMER CKT 1


511 10659 AEP E Rogers - Shipe Road 345 kV Regional Reliability 6/1/2016 6/1/2016 $24,500,000

511 10660 AEP East Rogers - Kings River 345 kV Ckt 1


615 10792 OGE COTTONWOOD CREEK - CRESENT 138KV CKT 1


633 10828 SPS ARTESIA SOUTH RURAL SUB - ARTESIA TOWN SUB 69KV CKT 1


646 10847 GMO Clinton 161/69 kV transformer Regional Reliability 3/1/2014 6/1/2013 $2,000,000

649 10853 AEP LOCUST GROVE - LONE STAR 115KV CKT 1


653 10858 MKEC PRATT - ST JOHN 115KV CKT 1 Regional Reliability 6/15/2014 6/1/2013 $15,079,303

701 10932 OGE Stateline - Woodward EHV 345 kV Balanced Portfolio 5/19/2014

$120,000,000 701 10933 OGE WOODWARD DISTRICT EHV 345/138KV TRANSFORMER CKT 2

Balanced Portfolio 5/19/2014

701 10937 OGE Stateline 345 kV Balanced Portfolio 5/19/2014

703 50499 TSMO Iatan - Nashua 345 kV Ckt 1 (GMO) Balanced Portfolio 6/1/2015 $51,694,688

703 10935 TSMO Iatan - Nashua 345 kV Ckt 1 (KCPL)

Balanced Portfolio 6/1/2015 $10,741,831

703 10945 TSMO NASHUA 345/161KV TRANSFORMER CKT 1

Balanced Portfolio 6/1/2015 $2,905,550

704 10936 SPS Tuco Interchange - Stateline 345 Balanced 9/30/2014 $182,392,958



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kV Portfolio

715 10952 GMO GLENARE - LIBERTY 69KV CKT 1 #2


764 11007 SPS HAPPY INTERCHANGE 115/69KV TRANSFORMER CKT 1


764 11009 SPS HAPPY INTERCHANGE 115/69KV TRANSFORMER CKT 2


774 11019 SPS CHERRY1 - POTTER COUNTY INTERCHANGE 230KV CKT 1


774 11020 SPS CHERRY1 230/115KV TRANSFORMER CKT 1


774 11021 SPS Hastings Sub 115 kV Regional Reliability 6/30/2014 6/1/2010 $1,048,295

774 11023 SPS EAST PLANT INTERCHANGE - HASTINGS SUB 115KV CKT 1


774 11378 SPS CHERRY SUB - HASTINGS SUB 115KV CKT 1


791 11041 SPS NEWHART 230 - SWISHER COUNTY INTERCHANGE 230KV CKT 1


791 11042 SPS KRESS INTERCHANGE - NEWHART 115KV CKT 1


791 11045 SPS HART INDUSTRIAL - LAMTON INTERCHANGE 115KV CKT 1


795 11052 SPS PLEASANT HILL 230/115KV TRANSFORMER CKT 1


795 11053 SPS OASIS INTERCHANGE - PLEASANT HILL 230KV CKT 1


795 11054 SPS PLEASANT HILL - ROOSEVELT COUNTY INTERCHANGE 230KV CKT 1


819 11082 WR GILL ENERGY CENTER EAST - MACARTHUR 69KV CKT 1 #2


833 11100 SPS NORTHEAST HEREFORD INTERCHANGE 115/69KV TRANSFORMER CKT 2


834 11101 SPS PORTALES INTERCHANGE - ZODIAC 115KV CKT 1


846 11115 WFEC Anadarko - Blanchard 138 kV Ckt 1


846 11116 WFEC BLANCHARD - OU SW 138 KV CKT 1


906 11203 MKEC MEDICINE LODGE - PRATT 115KV CKT 1

Transmission Service 6/15/2014 1/1/2010 $13,645,827

910 11207 OGE BRYANT - MEMORIAL 138KV CKT 1

Transmission Service 6/1/2019 6/1/2019 $225,000

936 11236 AEP NORTHWEST TEXARKANA - High Priority 5/1/2015 $127,995,000



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VALLIANT 345KV CKT 1

938 11238 TSMO Sibley - Mullin Creek 345 kV High Priority 6/1/2017 $241,448,558

938 11239 TSMO Nebraska City - Mullin Creek 345 kV (GMO) High Priority 6/1/2017 $90,750,965

939 11240 OPPD Nebraska City - Mullin Creek 345 kV (OPPD) High Priority 6/1/2017 $75,564,841

940 11241 SPS Hitchland Interchange - Woodward District EHV 345 kV CKT 1 (SPS)

High Priority 6/30/2014

$51,370,321

940 11242 SPS Hitchland Interchange - Woodward District EHV 345 kV CKT 2 (SPS)


941 11244 OGE Hitchland Interchange - WOODWARD DISTRICT EHV 345KV CKT 1 (OGE)


$165,000,000

941 11245 OGE Hitchland Interchange - WOODWARD DISTRICT EHV 345KV CKT 2 (OGE)


940 11243 SPS Hitchland Interchange 345/230 kV Transformer Ckt 2 High Priority 6/30/2014 6/1/2013 $13,649,558

942 11246 OGE Thistle - Woodward EHV 345 kV ckt 1 (OGE) High Priority 12/31/2014

$145,040,000 942 11247 OGE Thistle - Woodward EHV 345 kV

ckt 2 (OGE) High Priority 12/31/2014

943 11248 PW Thistle - Woodward EHV 345 kV ckt 1 (PW) High Priority 12/31/2014 $23,800,000

943 11249 PW Thistle - Woodward EHV 345 kV ckt 2 (PW) High Priority 12/31/2014 $23,800,000

945 11252 ITCGP Ironwood - Clark Co. 345 kV Ckt 1 High Priority 12/31/2014 $51,686,137

945 51029 ITCGP Ironwood - Spearville 345 kV Ckt 1 High Priority 12/31/2014

945 11253 ITCGP Ironwood - Clark Co. 345 kV Ckt 2 High Priority 12/31/2014 $51,686,137

945 50793 ITCGP Ironwood - Spearville 345 kV Ckt 2 High Priority 12/31/2014

945 11254 ITCGP Clark Co 345 kV - Thistle 345 kV ckt 1 High Priority 12/31/2014 $91,618,023

945 11255 ITCGP Clark Co 345 kV - Thistle 345 kV ckt 2 High Priority 12/31/2014 $91,618,023

945 11260 ITCGP Thistle 345/138 kV transformer High Priority 12/31/2014 $6,284,694 945 50384 ITCGP Flat Ridge - Thistle 138 kV High Priority 12/31/2014 $7,106,987

946 11258 PW Thistle - Wichita 345 kV ckt 1 (PW) High Priority 12/31/2014 $61,200,000

946 11259 PW Thistle - Wichita 345 kV ckt 2 (PW) High Priority 12/31/2014 $61,200,000

946 11497 WR Wichita 345 kV High Priority 12/31/2014 $14,155,302



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947 11261 AEP BROKEN ARROW NORTH - SOUTH TAP - ONETA 138KV CKT 1 #2


1001 11315 SPS RANDALL COUNTY INTERCHANGE - SOUTH GEORGIA INTERCHANGE 115KV CKT 1


1021 11343 OGE ARCADIA - REDBUD 345KV CKT 3 Transmission Service 6/1/2019 6/1/2019 $18,000,000

1027 11351 WFEC BLUCAN5 4 138.00 - PARADISE 138KV CKT 1


1029 11353 SPS Lynn County Interchange 115 kV Regional Reliability 12/31/2014 6/1/2012 $5,342,685

1036 11372 SPS Soncy Tap 115 kV - New Soncy 115 kV

Regional Reliability 6/1/2015 6/1/2015 $929,500

1042 11383 SPS North Plainview 115 kV Regional Reliability 1/15/2015 6/1/2015 $300,000

1043 11384 SPS Kress Rural 115 lV Regional Reliability 1/15/2015 6/1/2015 $400,000

1073 11411 WR Franklin - Mulberry 69 kV Ckt 1 Regional Reliability 6/1/2014 6/1/2013 $7,719,848

1073 11412 WR Franklin - Sheffield 69KV CKT 1 Regional Reliability 6/1/2014 6/1/2013 $1,695,722

1073 11413 WR Franklin 161 kV Regional Reliability 6/1/2014 6/1/2013 $12,204,315

1073 11444 WR Franklin 161/69KV TRANSFORMER CKT 1


1084 11424 WFEC ALVA - FREEDOM 69KV CKT 1 Regional Reliability 6/1/2014 6/1/2011 $6,243,750

1096 11440 MKEC PRATT - ST JOHN 115KV CKT 1 #2 Regional Reliability 6/15/2014 6/1/2011 $100,000

1134 11496 OGE NORTHWEST 345/138KV TRANSFORMER CKT 3


30039 50045 WFEC ESQUANDALE 69KV Regional Reliability 6/1/2014 6/1/2014 $243,000

30071 50077 GRDA SALLISAW 69KV Regional Reliability 6/1/2011 $374,000

30079 50085 WFEC CARTER JCT 69KV Regional Reliability 6/30/2014 6/1/2010 $324,000

30160 50168 OGE FT SMITH 500/161KV TRANSFORMER CKT 5


30164 50172 OGE VBI - VBI NORTH 69KV CKT 1 Transmission Service 6/1/2017 6/1/2017 $100,000

30201 50208 NPPD CLARKS 115KV Regional Reliability 11/1/2012 $700,000

30202 50209 NPPD Ainsworth 115 kV Cap Bank Regional Reliability 11/1/2012 $50,000

30203 50210 NPPD ONEILL 115KV Regional Reliability 11/1/2012 $700,000

30224 50233 WR BURLINGTON JUNCTION - COFFEY COUNTY NO. 3 WESTPHALIA




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69KV CKT 1

30224 50236 WR COFFEY COUNTY NO. 3 WESTPHALIA - GREEN 69KV CKT 1


30226 50230 WR ALTOONA EAST 69KV transmission service 6/1/2015 6/1/2014 $1,400,000

30285 50319 NPPD OGALLALA 230/115KV TRANSFORMER CKT 1


30290 50328 WR HALSTEAD SOUTH BUS - SEDGWICK COUNTY NO. 12 COLWICH 138KV CKT 1


30296 50334 AEP WINNSBORO 138KV Regional Reliability 6/1/2016 6/1/2016 $1,166,400

30298 50336 AEP LOGANSPORT 138KV Regional Reliability 6/1/2016 6/1/2016 $1,166,400

30299 50337 MKEC JEWELL 3 - SMITH CENTER 115KV CKT 1


30320 50366 WFEC CANTON - TALOGA 69KV CKT 1 Transmission Service 6/1/2015 6/1/2011 $4,800,000

30321 50367 WFEC TALOGA (TALOGA) 138/69/13.8KV TRANSFORMER CKT 1


30326 50372 WR Clay Center Switching Station - TC Riley 115 kV Ckt 1

Zonal Reliability 6/1/2015 10/1/2012 $9,308,090

30328 50374 WR TC RILEY 115KV Zonal Reliability 6/1/2015 10/1/2012 $963,441

Table 1: Legacy Project List


Southwest Power Pool, Inc. Markets and Operations Policy Committee Recommendation to the Board of Directors

July 29, 2014 Re-evaluation of Chamber Springs - Farmington

Organizational Roster The following persons represent the Southwest Power Pool:

Carl Monroe, Executive Vice President and Chief Operating Officer Lanny Nickell, Vice President, Engineering Antoine Lucas, Director, Planning Jody Holland, Manager, Steady State Planning

Background On February 19, 2013, SPP issued Notification to Construct (NTC) No. 200216 to American Electric Power (AEP) to rebuild and reconductor an 11.1-mile 161 kV line from Chamber Springs to Farmington. The project was identified in the 2013 ITP Near-Term Assessment as needed for reliability in 2013.

On December 12, 2013, AEP submitted to SPP an updated cost estimate of $17,810,955 for the project, a 36.8% increase from the established baseline cost estimate of $12,705,537. SPP Business Practice No. 7060 directs SPP to re-evaluate any project for which a Transmission Owner submits an updated cost estimate that is more than a 20% increase from the baseline cost estimate.

In its justification for the cost increase, AEP proposed to rebuild the 161 kV line with double circuit capable structures to 345 kV standards, but only stringing the 161 kV line. The proposed change would accommodate future 345 kV expansion in the existing right-of-way, albeit amended to accommodate 345 kV standards. AEP estimated that the CECPN acquisition for the amended right-of-way would add at least a year to target in-service date of 6/1/2016. AEP’s mitigation plan for the project is effective through 2018.

On January 28, 2014, the SPP Board of Directors approved the MOPC recommendation to suspend NTC No. 200216 for the Chamber Springs – Farmington 161 kV Rebuild project and perform further cost-benefit analysis including a long-term reliability needs assessment.

Analysis

SPP Staff performed an assessment of need for a 345 kV line from Chamber Springs to Farmington. The evaluation included Powerflow, First Contingency Incremental Transfer Capability (FCITC), and load transfer assessments to determine reliability need. A low hydro scenario and reduced emissions sensitivities were also performed. An economic evaluation was also done using the 2013 ITP20 PROMOD model.

The results of the re-evaluation indicated that, based on the assumptions used in the analyses, a need to increase the capacity of the currently planned Chamber Springs - Farmington 161 kV line rebuild beyond the current NTC scope was not identified.

Recommendation MOPC recommends that the suspension of NTC No. 200216 for the project Chamber Springs – Farmington REC 161 kV Rebuild be removed. No NTC modifications should be issued to alter the project scope for Chamber Springs – Farmington 161 kV Rebuild. The baseline cost estimate value should not be reset from its value of $12,705,537 (2013 dollars).


Passed Unanimously

Southwest Power Pool, Inc. SOUTHWEST POWER POOL STAFF

Board of Directors July 29, 2014

Modified Notification to Construct for Cowskin-Hoover

Organizational Roster The following members represent the Southwest Power Pool:

Lanny Nickell, Vice President, Engineering Antoine Lucas, Director, Planning Steve Purdy, Manager, Transmission Service Studies

Background The recently completed Aggregate Study 2012-AG1-AFS-7, identified the need to modify the reliability need date for the Cowskin to Westlink to Tyler to Hoover 69 kV Rebuild (PID: 319) from 6/1/2015 to 6/1/2014. SPP Business Practice 7060 regarding NTC modifications requires SPP staff to inform the Transmission Working Group (TWG), Markets and Operations Policy Committee (MOPC), and Board of Directors of the NTC Project modification for the Board’s approval or endorsement. TWG and MOPC have been informed by email. SPP staff recommends that the NTC Project modification be endorsed.

Analysis The project is needed to support transmission service requests as detailed in Aggregate Study SPP-2012-AG1-AFS-7, some of which start as early as 5/1/2014. The original NTC was issued to and accepted by Westar Energy after being identified in the 2013 ITP Near-Term study with a need date of 6/1/2015. The justification for the project itself is the same as that identified in the 2013 ITP Near-Term study. The earlier reliability need date in the Aggregate Study is most likely driven by small impacts from new transmission service that was granted subsequent to the 2013 and 2014 ITP Near-Term studies, in which the impacts from the new service fell below the threshold for cost allocation. Westar Energy has agreed with SPP’s assessment that the project is needed by the earlier date. Given the projected in-service date of 12/1/2015, the project status is currently delayed with an interim mitigation plan. The modification of the NTC to an earlier need date will establish the need for the interim mitigation to be implemented sooner. The cost allocation for the project will remain fully base plan funded in accordance with the Highway/Byway cost allocation methodology.

Recommendation SPP staff recommends that the Board endorse the modification of the NTC Project with Project ID 319 to identify a need date of 6/1/2014.

Action Requested: Endorse recommendation

Integrated Marketplace UpdateJuly 29, 2014

Bruce Rew, [email protected] 501.614.3214


SPP Integrated Marketplace Update • Integrated Marketplace Continues to perform well

• Summary of first four months

• Marketplace Statistical Information

• Marketplace improvements

2

Integrated Marketplace summary

• High market participant engagement• Systems performing well • Operated through some operations challenges• Improving unit commitment processes and knowledge• Summer Peak loading conditions have not occurred yet

3

Unit Commitment Improvement

4

Unit Commitment Improvement

5

Graph on Real-Time versus DA pricing

6

Graph on Dispatch by Fuel Type

7

Graph on Fuel on the Margin in RT

8

Integrated Marketplace Improvements

• Integrated Marketplace Project Pinnacle– Market-to-Market solution

– Enhanced Combined Cycle

• Operational Review of data– Enough experience now to begin reviews

– Working with former Balancing Authorities to look for ways to improve reliability and economic operations

• SPP working on improvements– Prioritizing desired Market enhancements

9

Integrated Marketplace Summary

• Overall market has worked well– No major system concerns

– Settlements functioning well with minimal disputes

• Financial savings being achieved – Continued energy savings similar to EIS market

– New savings from improved unit commitment

• Continuous improvement– Working with BA’s to improve dispatch

– Market enhancements evaluated

10

Integrated Marketplace:Project PinnacleUpdate

July 29, 2014

M2M – Market-to-Market

• On schedule for 3/1/15 launchSchedule

• Awaiting approval from FERC on JOA filing (anticipated by 1/1/15)Regulatory

• Completed Pre-FAT (Alstom Markets)Accomplishments

• Complete FAT (Alstom Markets)• Expect first delivery of code from Alstom

Markets in AugustNext Steps

• Timely resolution of issues between SPP and MISO (for e.g. repricing procedures, alignment of interval data)

Risks

2

Regulation Compensation


• Responded to FERC Order issued 6/19/14• System changes may be required, though not

significant• No impact to production launch

Regulatory

• Completed Pre-FAT(Alstom Markets)Accomplishments

• Complete FAT (Alstom Markets)• Expect delivery of code from Alstom Markets in

AugustNext Steps

• FERC’s acceptance of SPP approachRisks

3

LTCR – Long-Term Congestion Rights


• Compliance Filing to be filed by 7/30/14Regulatory

• Completed Initial Pre-FAT (Nexant)Accomplishments

• Submit FERC Compliance Filing by end of July• Begin subsequent Pre-FAT sessionNext Steps

• FERC’s acceptance of SPP’s approachRisks

4

Pseudo-Tie Out

• Launched on 6/12/14!Schedule

• N/ARegulatory

• Production implementation on schedule• Resettlement process currently underwayAccomplishments

• Complete resettlement process by August 2014Next Steps

• NoneRisks

5

EBO - Environment Build-Out

• On schedule to begin MP connectivity testing with MTE on 9/2/14

• Fully implemented system by 10/3/14Schedule

• N/ARegulatory

• Completion of all environments’ component buildAccomplishment

• Internal Testing of environments• Prepare for Connectivity testing (SPP / MP)Next Steps

• Internal resource collisions being closely watched and mitigatedRisks

6

Live Track (Post-Launch Efforts)

• Ongoing support and development effortsSchedule

• N/ARegulatory

• Deployed over 150 releases into PROD since launch of Integrated Marketplace

• Minimal impact to customers• No unplanned service outages

Latest Accomplishment

• Wind down Live Track down to steady state• Shift more staff and vendor focus from Live

Track to Project PinnacleNext Steps

• None at this timeRisks

7

ECC – Enhanced Combined Cycle

• Scheduled to launch on 11/1/15Schedule

• $4.6M $9.2MBudget

• Estimated development hours (across all impacted systems) has risen dramatically given the complexity of the solution and the efforts to optimize the Market Clearing Engine (MCE)

• Extension of contracts with experienced Subject Matter Experts (Markets and Settlements)

Budget Increase

8


• N/A at this timeRegulatory

• Continued critical path testing of ECC prototype • Identified some MCE performance

improvements• Completed requirements definition for Alstom

Latest Accomplishment

• Continue prototype testing• Continue to seek MCE performance

improvements• Complete requirements and design for all

impacted systems (non-Alstom)

Next Steps

• Resource constraints at SPP and Alstom• Collisions with mandatory projects• Performance concerns with Market Clearing

Engine

Risks

9


• 11/1/2015Proposed

Timeframe

• ECC will be limited to no more than 3 configurations that can be registered and offered at any given time

• Registered configurations may be updated bi-monthly

• Capability to expand to more configurations in the future without system changes

Scope

• Performance issues can be resolved without major retooling of Market Clearing Engine

Assumptions

10

ECC Target Go-Live November 1, 2015

Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct

2014 2015

Requirements

Design and Build

FAT

Internal Test

MP Test

Prototyping/Performance Optimization

PerfTest

11

12

Q & A

13

2014 Strategic Plan

Michael DesselleVice President, Process Integrity

July 2014

Strategic Planning Process

2013• Strategic scenario exercise

Spring•MOPC/WG RSC/CAWG input• Stakeholder input

April• SPC retreat•Draft plan

2

Strategic Planning Process (cont.)

June• Board strategic session• Revise plan

July• Share final plan with stakeholders• SPC finalize plan

July• Board approval

3

SWOT Analysis

Opportunities

Threats

Weaknesses Strengths

SEAMS

FUELS

AFFORDABILITY

RISKS

SECURITY

COSTS FUNDING

PLANS

EXPORTS

4

Our Vision of the Future

5

Foundational Strategies Pyramid

6

Four Foundational Strategies

7

Initiatives• Capacity Margin Refinement (A)• Regional Resource Need and Value

Assessment (B)• Reliability Assessments of

Environmental Rules (A)• Integration of Variable Energy

Resources (C)• Grid Resiliency (B)

– Cyber and Physical Security

• Reliability Excellence (B)– Relay Misoperations Improvement (RE)– Event Analysis (RE)

Reliability Assurance Strategy

8

Initiatives• Integrated Transmission Planning Check

and Adjust (B) – On-going• Cost Controls on Competitive

Transmission (A)• Flexibility to Address Policy Initiatives

(B) - On-going• Value Pricing (B)

– Import/Export Strategy– Cost Allocation

• Fair and Equitable Cost/Benefit Allocation Policies (A)

Economical, Optimized Transmission System Strategy

9

Initiatives• Transmission (Seams) (A)• Optimize Markets Efficiencies Along

Seams (A)• Optimize Natural Gas Pipeline

System Seams (A)• Optimize Data Seams (C)• Integrated Market Enhancements (B)

Interdependent Systems Strategy

10

Initiatives• Communication Strategy (A)• Fair and Equitable Cost/Benefit

Allocation Policies (A)• PMO Best Practices (B)• Enhanced Market Analytics (B)• Strategic Membership Expansion &

Improved Stakeholder Processes (A)• Communication/Education (C)

Member Value & Affordability Strategy

11

Recommendation

SPC recommends the adoption of the Strategic Plan by the SPP Board of Directors

12

1

MOPC Report to Board of Directors / Members Committee

July 29, 2014Rob Janssen - Chair

• Action Items– Criteria 12.1.5.3.g

• Information Items– SSC

– MWG ECC Update

– TWG Reliability Limits Trigger

CIP-002-5 Update

– ESWG Metrics

ITP10 Update

– PCWG Study Estimate Design Guide

Revision

Minimum Design Standards TF

– SPCWG Hitchland SPS Removal

– Gas Electric CTF

– Staff EPA Update

Scope of Capacity Margin TF

Value of SPP Transmission (VSTA) Conceptual Scope

HPILS Load Growth

Agenda

3

Action Items

4

GWG

CRR-012 Wind and Solar Capacity Accreditation• After Discussion, SPP Board Remanded CRR-012 Back

to MOPC in April 2014:– CRR-012, as approved by MOPC in April 2014, would

result in increased wind capacity accreditation from approximately 1.4% to 10% on average. Board indicated concern regarding this increase and indicated that Confidence Factor that would result in a lower capacity accreditation should be considered.

– Should also add language to allow a load serving member to select a lower capacity accreditation if it desires to do so.

6

CRR-012 Wind and Solar Capacity Accreditation• May 16 - GWG held its monthly WebEx:

– Added language stating “If a member’s desire to use a more restrictive methodology to evaluate the net capability of wind or solar they may do so, however net capability determined by the alternative methodology employed cannot credit the wind or solar with a capability greater than determined with the methodology stated below:”

– GWG chose to re-affirm CRR-012 (wind and Solar Capacity accreditation) with a vote of 6 to 2. Two “no” votes wanted a lower accreditation proposing a

Confidence Factor of 75%, instead of 60%.

7

CRR-012 Wind and Solar Capacity Accreditation• June 19: Face to Face meeting with Operation Reliability WG (ORWG):

– Presented results from GWG recommending 60% Confidence Factor during top 3% load hours of the peak month with Member option for lower accreditation. Solar facility operating data also provided.

– Presentation by Dogwood Energy examining estimated impact of switch to 3% peak load hours for August 2013. Resulted in evaluation of late afternoon hours during 5-6 days of that month.

– ORWG voted to approve the GWG CRR-012 as presented with a 6-5 vote.

• July 2: Presented to Transmission Working Group TWG

– Previously Approved, and not considered for a vote due to time constraints.

8

CRR-012 Wind and Solar Capacity Accreditation• June 20: Conference Call/WebEx with Cost Allocation

Working Group: – Presented results from GWG recommending 60%

Confidence Factor during top 3% load hours of the peak month with Member option for lower accreditation, and result of ORWG Vote.

– CAWG Re-affirmed its previous three items:1. SPP to review Capacity Margin requirements.

2. Will increased wind and solar accreditation increase the need for transmission? We think this is not directly related.

3. GWG plans to prepare a report each year concerning wind and solar generation during peak period.

9

CRR-012 Wind and Solar Capacity Accreditation• July 16: MOPC Meeting:

– GWG Recommended 60% Confidence Factor during top 3% load hours of the peak month with Member option for lower accreditation.

– MOPC approved the recommendation with a 84.1% vote.

– Dissenting parties argued that the resulting capacity values will rely on wind too much for capacity.

10

CRR-012 Wind and Solar Capacity Accreditation• Q2: Will increased wind accreditation drive additional

Transmission Construction? Not Directly.

The majority of Wind Projects are DNR, and most have transmission service for the nameplate output of wind resource. Resources must go through the Aggregate Study Process to become DNR, and Transmission upgrades may be directed assigned to the transmission customer.

MWs ResourcesDesignated Network Resource 6100 49Total Wind Resources 8607 106(from State of Market report 3/14)Percentage 70.9% 46.2%

11

Confidence FactorConfidence Factor Estimate % of Name

Plate% of SPP Peak load (Capacity Margin)

50 – ELCC Method 14.4

60 – GWG Proposed 10.1 1.79%

70 6.6

75 – “No” Votes 4.5 0.89 %

85 1.9

Year Wind % of Name Plate during Peak Hour

2010 22.0

2011 16.1

2012 5.2

2013 5.0

12

Solar Capacity

Amber MetzkerManager, Market Operations

Typical Solar Graph

14

Data Sample – Top 25 Load hours for 2012 & 2013 Actuals

2012 2013 Average39 44 41.529 40 34.542 27 34.539 35 3730 38 3441 37 3940 43 41.539 41 4038 34 3635 33 3441 39 4038 45 41.537 44 40.541 34 37.541 39 4034 40 3742 29 35.540 42 4137 34 35.535 31 3322 27 24.540 44 4240 43 41.543 42 42.539 35 37

Min 22 27 24.5Max 43 45 42.5Average 37.680 37.600 37.640Sdev 4.776 5.470 5.082

99% confidence interval: 35.71467 ≤ x ≤ 39.5653395% confidence interval: 36.19628 ≤ x ≤ 39.0837290% confidence interval: 36.43553 ≤ x ≤ 38.84447

15

July-Aug 2008-2010, 2012

Solar Accreditation, Jul-Aug, 2008-2010,2012Top 10 % Top 3 % Delta to %

AC MW 85th Percentile 60th Percentile Current AC MW

MW 50 0 33 33 66%

16

Sample Statistics for 2011, 2012, & 2013 Top 3% Loads

2010, 2012-2013 Top 3% of HoursAverage 25Stdev 14.6 N 788

99% confidence interval: 23.65705 ≤ x ≤ 26.3429595% confidence interval: 23.97905 ≤ x ≤ 26.0209590% confidence interval: 24.14350 ≤ x ≤ 25.85650

17

Summary of Different MethodsELCC Calculations for Solar2009 = 44% (based off forecasted data)2012 = 66% (based off actual data)

Solar Accreditation, Jul-Aug, 2008-2010,2012Top 10 % Top 3 % Delta to %

AC MW 85th Percentile 60th Percentile Current AC MW

MW 50 0 33 33 66%

SunEdison MW AC MW %2010, 2012, 2013 Data 85%, top 10% 0 50 0%2010, 2012, 2013 Data 60%, top 3% 25 50 50%

July-August Analysis

Full Year Analysis

18

Summary -

• Recommend Approval of CRR-012, Criteria Recommendation for Capacity Accreditation of Wind and Solar Resources.– On average wind projects will increase accreditation

from 1.4% to about 10% of nameplate. Some more and some less depending on their demonstrated performance.

– Solar projects will benefit with as much as 66% accredited capacity during summer months. Old method resulted in zero accreditation due to the number of hours included, (10% versus 3%)

19

MOPC Recommendation

• The Board of Directors should approve CRR-12 modifying SPP Criteria for Wind and Solar Capacity Accreditation

• Working Group Voting Results

– GWG re-approved by 75.0% on May 16, 2014

– ORWG approved by 54.5% on June 19, 2014

– CAWG re-approved its own recommendations on June 20, 2014. RSC approved same on July 28, 2014.

– TWG reviewed changes and took no further action on July 2, 2014

• MOPC approved CRR-12 on July 16 by 84.1% with 8 No votes (EDE, Midwest, KCBPU, IP&L, CUS, Dogwood, LES, MJMEUC) and 4 abstentions

20

CAWG / RSC Conclusions / Recommendations

• SPP should evaluate the current SPP capacity margin to ensure that it is adequate to meet the needs for a reliable system

• SPP should inform RSC and CAWG, on an ongoing basis, if the increase in accredited wind capacity, as a result of the criteria change, is partly or wholly responsible for causing any changes in the need for transmission upgrades in the SPP footprint

21

CAWG / RSC Conclusions / Recommendations

• RSC and CAWG should be presented with the GWG annual report regarding the performance of wind and solar facilities. The report should include a yearly comparison of wind and solar output during peak periods. This would allow the criteria to be reevaluated, if necessary, based on information on actual wind and solar output at peak periods.

These items could be taken as an Action Item to the MOPC if the Board so desires.

22

Information Items

23

• SSC

– Joint Planning

– Market-to-Market

• MWG

– ECC Update

• TWG

– Reliability Limits Trigger

– CIP-002-5 Update

• ESWG

– Metrics

– ITP10 Update

• PCWG

– Study Estimate Design Guide Revision

– Minimum Design Standards TF

• SPCWG

– Hitchland SPS Removal

• Gas Electric Coordination TF

• Staff

– EPA Update

– Scope of Capacity Margin TF

– Value of SPP Transmission (VSTA) Conceptual Scope

– HPILS Load Growth

Review of Items from MOPC

24

SSC

Seams Steering Committee

• SPP-AECI Coordinated System Plan– Draft scope and study schedule (Joint model

development complete)

– Evaluate reliability and robustness

– Potential transmission issues expected in August

• SPP-MISO Coordinated System Plan Study– Final study scope approved

– Jointly evaluate seams issues, identify transmission solutions that benefit of both regions (Economic congestion, Potential reliability violations)

26

Market-to-Market Overview

• M2M provides more efficient dispatch to relieve congestion.

• Schedule– Testing SPP: 7/14/14 – 2/20/15

– MP Testing: 1/5/15 – 1/23/15

• On schedule (1 risk on disagreement of CMP rule for excess flowgate allocations as input to FFE)

• Other discussion topics (5 minute interval data alignment, Process for adding M2M flowgates, Operating procedures under specific scenarios, Commercial model setup, Repricing procedures)

27

MWG

Enhanced Combined Cycle Implementation

• MOPC Discussion In Summary:– ECC Project was agreed-upon as part of approval of

Integrated Marketplace by SPP Membership

– As Staff has indicated previously, ECC Project is taking longer and costing more than originally anticipated

– Anticipated completion date is now Fall 2015 rather than Spring 2015

– Costs are expected to be approximately $9.2 million rather than $4.6 million. Roughly $1 mm spent to date. Number of analyzed configurations will be less than previously planned.

– Significant benefits are expected, but have not been specifically calculated

29

TWG

Reliability Limits Trigger for Expansion• MOPC Action Item 217 - TWG to investigate limits that

trigger reliability upgrades

• Trending analysis– Thermal overloads

– Voltage violations

– Model comparisons

• Analysis provided insufficient support to justify earlier NTC issuance

• TWG approved SPP Staff recommendation to begin monitoring Thermal loading at 90% rather than 95% and Voltage at 95% rather than 90%

31

CIP-002-5 Update• MOPC Action Item 211 - Procedures for identification

of generating resources that are required to avoid Adverse Reliability Impacts

• Effective - April 1, 2016 for High/Medium systems

• Two Planning Coordinator related criteria– Criterion 2.3 - Potential Reliability Must Run (RMR)

identification

– Criterion 2.6 - Potential Interconnection Reliability Operating Limits (IROL) identification

• Final methodology will be presented to the MOPC in October for approval

ESWG

Benefit Metrics Calculatedin RCAR I?

Considered for 2015 ITP10and RCAR II?

Included in ThisAssessment?

MOPC Approved

Adjusted Production Cost (APC) Yes Yes

Emission Rates and Values Yes Yes

Ancillary Service Needs and Production Costs Yes Yes

Avoided or Delayed Reliability Projects Yes Yes

Capacity Cost Savings due to Reduced On-Peak Transmission Losses Yes Yes

A. Marginal Energy Losses Benefits Yes How to include Yes

B. Increased Wheeling Through and Out Revenues Yes How to include Yes

C. Mitigation of Transmission Outage Costs Yes Allocation method No

D. Benefits of Mandated Reliability Projects Yes Allocation method No

E. Benefits from Meeting Public Policy Goals Yes Overall approach Yes

Reducing the Cost of Extreme Events No

Capital Savings due to Reduction of Members’ Minimum Required Margin No

Reduced Loss of Load Probability No34

ESWG METRICS

• In Summary:– Marginal Energy Losses Benefit

MOPC unanimously approved ESWG recommendation with three abstentions

– Increased Wheeling Revenues MOPC approved ESWG recommendation with one no vote

(Midwest Energy) and five abstentions

– Mitigation of Transmission Outage Costs MOPC unanimously approved ESWG’s recommended

calculation of benefits

MOPC did not approve ESWG recommendation for allocation of benefits by Load Ratio Share. Motion failed with 61.1% in favor.

35

ESWG METRICS

• In Summary:– Benefits of Mandated Reliability Projects

MOPC failed to approve ESWG recommendation (blended Load Ration Share and Reconfiguration methods) and three other motions to approve an allocation of benefits– “OPPD Modified Recommendation” Motion – 48.1% approval– “AEP 100% Reconfiguration” Motion – 34.3% approval– ESWG Recommendation Motion – 55.3% approval– “AEP Modified 200kV” Motion – 55.0% approval

– Benefits from Meeting Public Policy Goals MOPC approved ESWG’s recommendation with 86.4%

approval. There were four “No” votes from NPPD, OPPD, SPS, and ITC-GP and 17 abstentions.

36

2015 ITP10 Scope

• MOPC Direction– ESWG/TWG finalize the benefits metrics & allocation

methods for 2015 ITP10 Portfolio analysis

• MOPC Approved unanimously

37

PCWG

Study Estimate Design Guide (SEDG)

• April 8, 2014– PCWG approved changes to SEDG to accommodate the

Transmission Owner Selection Process for Competitive Upgrades

– PCWG also discussed how design standards would be applied for transmission construction across diverse group of potential builders

• May 9, 2014– SPCTF directed PCWG, in conjunction with TWG, to develop

minimum design standards guidelines document

• May 13, 2014– PCWG determined to form the Minimum Design Standards Task

Force (MDSTF) to complete work by October MOPC meeting

39

Minimum Design Standards Task Force

• Kick-off meeting held June 30– Group will evaluate 2 sub-sections of the SEDG to

determine if the existing documentation requires enhancement Transmission Lines

Transmission Substations

• Next meeting scheduled for July 23rd

40

SPCWG

Removal of Hitchland SPS

• Special Protection Scheme (SPS) installed in 2008 to limit outputs of two windfarms until new facilities around Hitchland were in-service

• SPCWG reviewed the impact of removal of the SPS since the Hitchland facilities are in-service

• TWG reviewed and approved removal

• MOPC approved unanimously

42

GECTF

Gas Electric Coordination

• FERC NOPR proposes to change gas nomination times and frequency and the start of the gas day.

• FERC March 20 Order began the NAESB Process involving all facets of the gas/electric industry.

• Schedule:– 9/29 – NAESB files Consensus Standard

– 11/28 – Industry deadline for NOPR Comments

– FERC Issues Final Rules 90 Days later – SPP Compliance to outline changes to the

Integrated Marketplace Day Ahead Market and Reliability Unit Commitment to meet the new timing or Explain why changes are not being made. 44

STAFF

• Current Known Impacts– Retirements

– De-ratings

– Outage Impacts

• Proposed Clean Power Plan– Overview

– Impact Analysis

Topics Covered

46

CURRENT KNOWN IMPACTS

47

5,127

285

0

5,000

(MW

)

Kansas

6380

5,000

(MW

)

Louisiana

3,072

68022

0

5,000

(MW

)

Missouri

3,950

320210

0

5,000

(MW

)

Nebraska

3,818

1,431

122

0

5,000

(MW

)Oklahoma

3,641

528173

0

5,000

(MW

)

Texas

1,100

78

0

5,000

(MW

)

Arkansas

22,863

2,958

890

0

10,000

20,000

30,000

(MW

)

Total Generation and Losses of Coal

Units by 2018

Current Impacts on Coal in SPP(based on recent survey)

1,5180

5,000

(MW

)

Iowa

Comparison with ITP 10 Assumptions

25,459

20,475

22,863

0

5,000

10,000

15,000

20,000

25,000

30,000

Meg

awat

ts

TOTAL CAPACITY OF COAL UNITS

Future 1 2025 Future 2 2025 2018 Projection

0

1,000

2,000

3,000

4,000

5,000

6,000

AR IA KS LA MO NE OK TX

Meg

awat

ts

TOTAL CAPACITY OF COAL UNITS BY STATE

Future 1 Future 2 2018

49

0

10,000

20,000

30,000

40,000

50,000

60,000

Meg

awat

ts

Monthly Peak Load

Required Reserve Margin

Unavailable Capacity

67,678

Outage Impact Study Resource Adequacy 20142014 Weekly Outages

50

Unavailable Capacity

0

10,000

20,000

30,000

40,000

50,000

60,000

Meg

awat

ts

Monthly Peak Load

Required Reserve Margin

Outage Impact Study Resource Adequacy 20152015 Weekly Outages

67,678

51

PROPOSED CLEAN POWER PLAN

52

• EPA’s proposed performance standards to reduce CO2emissions from existing fossil fuel-fired generators

• Promulgated under authority of Section 111(d) of the Clean Air Act

• Achieves nationwide 30% reduction of CO2 from 2005 levels by 2030

• Proposes state-specific emission rate-based CO2 goals– Based on EPA’s interpretation and application of Best System of

Emission Reduction (BSER)

– Must be met by 2030

EPA Clean Power Plan Overview

53

• States goals and flexibility– Interim goals applied 2020-2029 that allows states to

choose trajectory

– Offers guidelines and allows states flexibility to develop and submit State Implementation Plans

– States may adopt an equivalent mass-based goal

• States can develop individual plans or collaborate with other states

• If state does not submit a plan or its plan is not approved, EPA will establish a plan for that state

EPA Clean Power Plan Overview

54

Clean Power Plan Milestones

June 2,2014

Draft rule issued

Oct 16,2014

Comments due to EPA

June2015

Final rule expected

June2016State

ImplentationPlans due

June2017

State plans due (with one-year

extension)

June2018

Multi-state plans due (with

two-year extension)

January2020-29

Interim goal in effect

January2030

Final goal in effect

55

BSER is Based on Four Building Blocks

Block Assumption1. Improve efficiency of

existing coal plants6% efficiency improvement across fleet, assuming best practices and equipmentupgrades

2. Increase reliance on CC gasunits

Re-dispatch of Natural Gas CCs up to a capacity factor of 70%

3. Expand use of renewable resources and sustain nuclear power production

Meet regional non-hydro renewable target, prevent retirement of at-risk nuclear capacity and promote completion of nuclear capacity under construction

4. Expand use of demand-side energy efficiency

Scale to achieve 1.5% of prior year’s annual savings rate

*Uses 2012 data for existing units and estimated data for units under construction. 56

2030 Goals for States in SPP

1771 1783 1714

1499

741

1479 1544

1048910 895 883

791

2439 2368 2331 2320 22562162

2010

17981722

1562 15331420

0

500

1,000

1,500

2,000

2,500

3,000

Mon

tana

N. D

akot

a

Wyo

min

g

Kans

as

S. D

akot

a

Neb

rask

a

Miss

ouri

New

Mex

ico

Arka

nsas

Okl

ahom

a

Loui

siana

Texa

s

Final Goal Energy Efficiency Renewable Nuclear Redispatch CCs Heat Rate Improvement

*Includes Future States with IS Generation in SPP (N. Dakota, S. Dakota, Montana, and Wyoming)

Fossil Unit CO2 Emission Rate Goals and Block Application (lbs/MWh)

SPP State Average 2012 Rate = 1,699

SPP State Average 2030 Rate = 1,045

57

% Emission Reduction Goals for States in SPP

*Includes Future States with IS Generation in SPP (N. Dakota, S. Dakota, Montana, and Wyoming)

0

10

20

30

40

50

60

70

80

S. D

akot

a

Arka

nsas

Texa

s

Okl

ahom

a

Loui

siana

New

Mex

ico

Kans

as

Neb

rask

a

Mon

tana

Wyo

min

g

N. D

akot

a

Miss

ouri

Total CO2 Emission Reduction Goals (%)

Average of SPP States = 38.5%

58

EPA Projected 2016-2020 EGU Retirements(For SPP and Select Neighboring States)

*Excludes committed retirements prior to 2016**AEP provided data extracted from EPA IPM data

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

AR KS MO MT ND NE NM OK SD TX IA LA

MW

Coal Steam Oil/Gas Steam CT

59

• Arkansas– ADEQ stakeholder meetings on June 25th & August 28th

– SPP Staff provided an SPP overview to ADEQ on July 3rd

• Missouri– MoPSC stakeholder meeting on August 18th

• Nebraska– SPP Staff meeting with NDEQ and Nebraska utilities on July 30th

• Oklahoma– Meeting being scheduled in August with stakeholders

• South Dakota– SDPUC forum on July 31st , SPP invited to participate in panel discussion

• Texas– PUCT public workshop on August 15th

SPP Staff Involvement in State Efforts

60

Help educate and work with states

Perform impact analyses

– Inform stakeholder responses that are due October 16

– Inform current planning efforts

– Assist state and member decision making

Facilitate coordinated SPP response to proposed Clean Power Plan

Evaluate and facilitate regional approach

Coordinate with neighbors

Other ways?

How Can SPP Assist?

61

• Initial analysis requested by SPC

– Reliability analysis

– Use existing ITP 2024 models

– Model EPA’s projected EGU retirements

– Replace retired EGUs with a combination of increased output from existing CCs, new CCs, Energy Efficiency, and increased renewables (with input from member utility experts)

– Preliminary results expected by August 1st

• Additional analysis may also be performed upon completion of initial analysis

– Economic analysis, regional approach evaluation

– Scenario based

Impact Analyses

62

CAPACITY MARGIN ASSESSMENT

63

Capacity Margin Task Force

• Need for an update of SPP’s Capacity Margin requirements– SPP is the Consolidated Balancing Authority

– Issues raised with existing SPP Criteria language

• Recent Activity– Need first introduced at April MOPC meeting

– Questions sent out to MOPC for feedback

– Responses and feedback were compiled and a second round of questions were sent to MOPC for additional feedback

64

SPP’s 10 year Reserve Margin Outlook*

*From 2014 NERC LTRA

10.00%

15.00%

20.00%

25.00%

30.00%

35.00%

40.00%

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

SPP Region

Existing Certain + Net Firm Transfers Includes new generation (firm) 13.6% Target Reserve Margin

65

NERC’s Projected Reserve Margins*

*From 2013 NERC LTRA Report

0.00%

10.00%

20.00%

30.00%

40.00%

50.00%

60.00%

70.00%

80.00%

90.00%

100.00%

NERC Assessment Areas

2014 Summer 2018 Summer 2023 Summer Target

66

Reserve Margin Targets*

11.0%12.0% 12.0%

13.6% 13.7% 13.8% 14.2%15.0% 15.0% 15.0% 15.0% 15.0% 15.0% 15.6%

17.0%

19.3% 20.0%

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

NERC Assessment Areas

Target

*From 2013 NERC LTRA 67

Responses to MOPC questions*1. Should Capacity Margin requirement apply to all load serving entities operating within

the electrical boundaries of the SPP Balancing Authority? [20 responses] 100% Yes, 0% No

2. Should we use Coincident Peak loads to calculate each entity's Capacity Margin? [20 responses] 75% Yes, 20% No, 5 % Undecided

3. Penalties for non-compliance? [18 responses] 67% Yes, 11% No, 22% Undecided

4. Any issues with IRP state laws? [17 responses] 65% No, 24% Yes, 11% Undecided

5. Should fuel supply and transportation firmness be documented? [19 responses] 42% Yes, 16% No, 32% Undecided, 10% Unrelated

6. Can anything other than firm transmission be used to demonstrate deliverability? [18 responses] 33% Yes, 22% No, 45% Undecided

7. Which SPP Working Group should own the Capacity Margin process? [18 responses] 31% GWG, 31% ORWG, 10% TWG, 28% Other

8. Do plants need to be available more than a certain percentage of the year? [18 responses] 28% Yes, 16% No, 56% Undecided

9. How do we factor in environmental limits? [19 responses] (Multiple types of responses)

*Additional questions moved to the Appendix due to small sample set 68

Capacity Margin Task Force

• Summary of CMTF Scope– An update to SPP’s Capacity Margin requirements and

methodology is needed to address changes in the SPP marketplace, provide clarification for entities required to maintain a calculated Capacity Margin, and evaluate affects of changing footprint and operations

• Representation– SPP Members nominate one person each

– CAWG/RSC representation encouraged

• Target Completion - July 2015

• MOPC Approved unanimously69

VALUE OF SPP TRANSMISSION

70

Value of SPP Transmission Assessment (VSTA)

• MOPC Action Item 234: Review benefits of SPP approved transmission– Develop conceptual scope by the July MOPC

– Develop detailed scope

– Perform analysis

• Assessment Goal– Determine benefits attributable to transmission

development in the SPP region

71

• CAWG

• ESWG

• TWG

• PCWG

• SSC

Stakeholder Involvement To-date

VSTA

CAWG

PCWG

SSCTWG

ESWG

72

What it is…• …Staff-led with Stakeholder review

• …Informational

• …Holistic value of transmission approved since 2006

• …Regional viewpoint

• …Intended for a broad audience

• …Enrich future decision making

73

What it is not…• …RCAR

• …determining cost allocation

• …assigning benefits to local zones

• …second guessing past decisions

74

Value: Realized and Future• Realized value

– Value already realized

– Historical operational data as inputs

– Utilize real-time/planning models and tools as applicable

• Future Value– Expected value

– Latest available forecast data as inputs

– Utilize planning models and tools

75

Value Reporting Approach• Oriented for a broad audience

• Bandwidth– Multiple sensitivities

– Accounts for limited precision

• Resist project categorization because value can change over time

76

Metrics Considered Adjusted Production Cost **$

Marginal Energy Losses **$

Unit Cycling **$

Avoided or Delayed Reliability Projects **$

Increased Wheeling Through and Out Revenues **$

Assumed Benefit of Mandated Reliability Projects **$

Public Policy Benefits **$

Societal Economic Benefits **$

Losses (capacity) **$

TSR, GI, and Load Enablement ** Reduction of Emission Rates and Values ** Fuel Type Diversity ** Savings Due to Lower Ancillary Service Needs

and Production Costs **

• Reduction of Reserve Zones**• Interconnection Reliability Operation

Limit **• Flowgate Reduction **• Loss-of-Load-Probability **$

• Increased Market Competition **• ARR Benefit *• Voltage Stability **• Transient Stability **• Mitigating RMRs **• Grid Flexibility **• Imperfect Foresight *$

• Market to Market *$

• Impact of Extreme Events *

*Future Value *Realized Value $Monetized Value Sub-set of metrics77

Staff Proposal:• Higher-likelihood sensitivities

– High gas price, low load growth, 111(d)

• Metrics (13) which provide the most value while being more familiar to stakeholders

Adjusted Production CostMarginal Energy LossesUnit CyclingAvoided or Delayed Reliability

Projects Increased Wheeling Through and Out

RevenuesAssumed Benefit of Mandated

Reliability Projects

Public Policy BenefitsSocietal Economic BenefitsLosses (capacity)TSR, GI, and Load EnablementReduction of Emission Rates and

ValuesFuel Type DiversitySavings Due to Lower Ancillary

Service Needs and Production Costs78

HPILS LOAD GROWTH

79

HPILS UpdateOn April 29, 2014 the Board of Directors approved the HPILS Report and directed issuance of NTCs & NTC-Cs as shown in Appendix C of the report. The Board of Directors also directed,

“the members in whose systems the additional HPILS loads and assumed generation additions reside will provide updated forecasts of these loads and generators prior to each subsequent quarterly meeting of the SPP BOD, and in addition, will notify the SPP staff immediately upon receipt of any information that, in their judgment, would impact the need for one or more of the previously issued NTCs.”

80

Related Activities to Date

• 6/10 HPILS TF Meeting - Stakeholder feedback on SPP staff draft procedure which expanded NTC validation beyond HPILS related projects

• Issued HPILS NTCs 6/20 – Commitments due in 90 days

• Minimal feedback to date

• Posted revised NTC Validation Procedure in MOPC background materials

81

Carl A. MonroeEVP & [email protected]

82



Regional State Committee, Board of Directors/Members Committee &

Regional Entity Trustees

Future Meeting Dates & Locations

2014

RET/RSC/BOD October 27-28 Little Rock (Annual Meeting of Members)

** BOD December 9 Little Rock

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 Little Rock

The RET/RSC/BOD meetings are Monday/Tuesday 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 or 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.

Relationship-Based • Member-Driven • Independence Through Diversity

Evolutionary vs. Revolutionary • Reliability & Economics Inseparable