MOPC Report to Board of Directors / Members CommitteeJuly 25-26, 2016

Noman Williams - Chair

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• Action Items Staff Z2 Payment Plan

Z2 Waiver Requests

Linwood 115 KV Reactor

Kummer Ridge-Roundup 115Kv

Walkemeyer Phase 1 and Phase 2

• Information Items RARTF – RCAR II Project

MWG – Update on MMU recommendation for ASOM

CMTF – SAWG (CGC)

TPITF – SPP Planning Process Improvement Recommendations

TWG – 2017 ITPNT Scope

ORWG – 2017 Variable Generation Integration Study II

Agenda

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Action Items

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Staff

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Attachment Z2 Implementation

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Background – What is Z2• Z2 is a process under SPP’s tariff to

compensate Upgrade Sponsors who pay for upgrades that are subsequently used by Transmission Customers

• The types of eligible upgrades include: Generator Interconnection Sponsored Transmission Service

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Background – FERC DocketOriginal Obligation

• ER05-109: Created Revenue Credits (Today known as Z2)

CLARIFYING FILINGS AT FERC

• ER08-746: Attachment Z was separated into Z1 - Aggregate Study Procedures and Z2 –Revenue Crediting Procedures (Credits) Credits will be based upon NITS & PTP service that could not be provided “but for” the

existence of the upgrade.

Expanded Credits to Project Sponsors.

The “but for” test recognizes that a network upgrade may also provide benefits in the opposite direction.

Changes became effective May 2008

• ER13-1914: Clarifications to Revenue Crediting Clarify the determination of credits, the funding of credits, and the distribution of credit

revenue for Creditable Upgrades under the Tariff

Include provisions that are designed to simplify and streamline the crediting process

Changes became effective September 2013

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Background – FERC Docket (Cont.)

SPP WAIVER FILING

• ER16-1341: SPP filed for a waiver relating to several provisions of SPP’s tariff to allow SPP bill dating back to 2008 FERC Approved the Waiver Request as requested (July

7, 2016).

• Waiver included: Lifted 1 Year Billing limitation No requirement to Reallocate Balanced Portfolio Waiver of Safe Harbor Cost Limit (SHCL)

notice/posting requirements

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Creditable Upgrades

10

Type of Creditable Upgrade Number of Creditable Upgrades

Directly Assigned Amount

Generator Interconnection 128 $567,065,914

Sponsored 3 $229,807,252

Transmission Service 27 $51,928,569

Total Directly Assigned Upgrade Amounts 158 $848,801,735

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Creditable Upgrades By Year

11

Year Number of Creditable Upgrades

Directly Assigned Amount

2006 2 $10,492,864

2007 1 $475,857

2008 4 $1,231,374

2009 4 $688,475

2010 11 $244,908,980

2011 15 $39,348,154

2012 27 $152,715,793

2013 14 $36,796,684

2014 17 $66,808,478

2015 21 $107,380,940

2016 25 $99,985,736

2017 15 $73,084,307

2018 2 $14,884,092

Total 158 $848,801,73510 of 101

Z2 Project Status

• Historical data processing Phase 1 (long-term credit payment obligations) has been completed for Network service

• Adjustment of Base Plan funding amounts is underway to address issues identified in the direct assignment review process

• Historical data processing Phase 2 (detailed settlements) is underway

• Crediting Stacking System overview provided to stakeholders on June 28-29

• Historical results scheduled to be available for stakeholder review prior to the October MOPC

• Invoicing of Z2 settlements is scheduled to begin early November 2016

• Payment plan approved by Board 10 months: Nov. 2016 to Aug. 2017

• Development to be completed: Output to Settlement Statements 1211 of 101

Project Schedule

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Project Schedule Risks

• Delay of processing schedule due to data validation

• Dependency on changes to staff’s waiver recommendation regarding Base Plan funding Any further addition to Base Plan funding

amounts will require reprocessing all months affected by such change

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Status of Z2 Calculations

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Attachment Z2 Calculations

16

Revenue Credits to Upgrade Sponsors

PTP Revenue Claw-back

Credit Payment Obligation

Base Plan Funding

Directly Assigned Costs

In ProgressCompleted Preliminary

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Schedule for Historical Z2 Results

Completion Date

Preliminary Final

Network Service:

Credit Payment Obligation April

Waiver Request Process June July

Base Plan Funded Amount April Sept

Directly Assigned Amount April Sept

PTP Service:

Credit Payment Obligation April Sept

Revenue Claw-back from TOs Sept

Directly Assigned Amount July Sept

Distribute Credits to Sponsors Sept

Note: Schedule assumes no additional FERC filing other than payment plan 1716 of 101

Sample Calculations (including Netting)

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Attachment Z2 Settlement Impact on Network Zonal Cost

Schedule 11 Region-wide Z2 Charge *

+ Schedule 11 Zonal Z2 Charge

___________________________

= Total Impact on the Zone

* Based on the total Region-wide Load Ratio Share of all Resident Load in the Zone

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Attachment Z2 Settlement Impact on an Upgrade Sponsor with Network Load and Transmission Ownership

Schedule 11 Region-wide Z2 Charge

+ Schedule 11 Zonal Z2 Charge

+ Direct Assignment Charge (Network and/or PTP)

+ Point-To-Point Revenue Claw-back

- Revenue Credits Received

________________________________________

= Net Financial Impact

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Z2 Calculations & Historical Breakdown(Still in Process & incomplete)

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CALCULATIONS DO NOT INCLUDE:• Credits Paid to Upgrade Sponsors

• Reduction of CPOs if Prior Upgrade Sponsors become Fully Compensated

• Directly Assigned Costs to Fund CPOs (Network and PTP)

• Point-To-Point Rate Increases Due to Funding CPOs

• Claw-back of Point-To-Point Revenue

• HENCE THESE NUMBERS ARE INCOMPLETE 2221 of 101

ATRRs compared to Annual CPOs (historical through 8/31/2016)

23

$571,785,436

$697,372,346$771,789,386

$855,092,324

$1,022,541,937

$1,175,006,647

$1,341,569,615

$1,708,520,125

$1,834,154,459

$76,726 $979,478 $5,490,341 $10,545,511$18,196,696$27,201,769$38,211,261$50,895,028$43,221,636

$0

$200,000,000

$400,000,000

$600,000,000

$800,000,000

$1,000,000,000

$1,200,000,000

$1,400,000,000

$1,600,000,000

$1,800,000,000

$2,000,000,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Yearly ATRRs compared to Yearly Credit Payment Obligations

Total ATRR $ Credit Payment Obligation ("CPO") for Creditable Upgrade $

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24

ATRRs compared to Annual CPOs (2008-2016)

Year ATRR*CPO for

Creditable Upgrade $

% CPO of ATRR

2008 $571,785,436 $76,726 0.01%

2009 $697,372,346 $979,478 0.14%

2010 $771,789,386 $5,490,341 0.71%

2011 $855,092,324 $10,545,511 1.23%

2012 $1,022,541,937 $18,196,696 1.78%

2013 $1,175,006,647 $27,201,769 2.32%

2014 $1,341,569,615 $38,211,261 2.85%

2015 $1,708,520,125 $50,895,028 2.98%

2016 $1,834,154,459 $65,136,664 3.55%23 of 101

25

Overall Annual Transmission Revenue Requirement (ATRR) as Billed Compared to the Z2 Base Plan Funding Offset (BPFO)*

Year ATRR** BPFO % Increase of ATRR due to BPFO

2008 $571,785,436 $76,726 0.01%2009 $697,372,346 $812,264 0.12%2010 $771,789,386 $4,670,403 0.61%2011 $855,092,324 $8,760,686 1.02%2012 $1,022,541,937 $14,349,218 1.40%2013 $1,175,006,647 $17,814,645 1.52%2014 $1,341,569,615 $23,135,743 1.72%2015 $1,708,520,125 $29,349,470 1.72%

2016*** $1,834,154,459 $26,307,120 1.43%

Total $9,977,832,275 $125,276,275 1.26%

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26

ATRRs compared to Annual CPOs (2008-2024)

ATRR for 2017 – 2024 based on the 10 Year Cost Allocation Forecast presented to RTWG (2/2016)

Year ATRR* CPO for Creditable Upgrade $ % CPO of ATRR

2008 $571,785,436 $76,726 0.01%2009 $697,372,346 $979,478 0.14%2010 $771,789,386 $5,490,341 0.71%2011 $855,092,324 $10,545,511 1.23%2012 $1,022,541,937 $18,196,696 1.78%2013 $1,175,006,647 $27,201,769 2.32%2014 $1,341,569,615 $38,211,261 2.85%2015 $1,708,520,125 $50,895,028 2.98%2016 $1,834,154,459 $65,136,664 3.55%2017 $2,019,866,282 $69,357,911 3.43%2018 $2,100,411,267 $68,906,920 3.28%2019 $2,178,278,048 $62,407,625 2.86%2020 $2,189,251,987 $50,919,273 2.33%2021 $2,190,677,922 $44,454,267 2.03%2022 $2,168,239,560 $40,667,485 1.88%2023 $2,129,297,725 $38,943,779 1.83%2024 $2,100,928,238 $38,681,631 1.84%

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Attachment Z2 Settlement Impact on Network Cost for the Razorback Zone

Sch. 11 Region-wide Z2 Charge * 6.0 Mill.

Schedule 11 Zonal Z2 Charge + 4.2

__________

Total Impact on the Zone 10.2 Mill.

* Based on the total Region-wide Load Ratio Share of all Resident Load in the Zone

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Impact of Historical Z2 Settlement on Razorback Power Company

Sch. 11 Region-wide Z2 Charge $ 5.0 Mill.

Sch. 11 Zonal Z2 Charge + $ 3.5

Direct Assignment Network Charge + $ 1.4

Direct Assignment PTP Charge + $ 0.1

Point-To-Point Revenue Claw-back + $ 2.0

Revenue Credits from Long-Term Service - $ 4.0

Revenue Credits from Short-Term Service - $ 2.0______________________________________________________

Net Financial Impact $ 6.0 Mill.

Notes: 1) Credit payment obligations as calculated prior to start of service may be overstated if initial sponsors are fully compensated in the historical period. 2) Under the current schedule, the settlement categories represented by numbers in gold font will not be available until September.

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Concerns Related to Length of the Z2 Payment Plan • The historical credit payment obligation

amounts on the preceding slides are larger than many members expected to result from implementation of Attachment Z2

• In addition to these Network Service costs, there are other elements of historical Z2 settlement that have not yet been calculated

• MOPC members expressed concern about the financial effects of invoicing such amounts over the 10-month period of the payment plan approved in April

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Recommendation to Extend the Z2 Payment Plan• MOPC recommends:

Change the previously approved payment plan by the SPP Board of Directors from ten (10) months to five (5) years.

• MOPC approved, 4 NOs (Duke ATC, Duke Energy, OGE Xsm, OGE), 5 Abstentions (Tenaska, Westar KGE, Westar, Prairie Wind, Springfield)

• Other than term, all other aspects of previously approved payment plan are retained, including company’s option to pay its entire amount due up-front 3029 of 101

Z2 Waivers

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Background• On April 28, SPP sent reports (“DAUC Reports”) to all

customers with Directly Assigned Z2 costs for the purpose of requesting waivers.

• June Meetings Group A: Waivers that are permissible under the tariff

Board of Directors approved 6/13/2016 $56,410,613 added to Base Plan

Group B: Waivers that are not permissible under the tariff All stakeholder groups and the Board deferred to July

• July Meetings Group B

CAWG took no action MOPC approved no motions (see motions considered on later

slide) RSC took no action

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Revision for Load in Multiple Zones

33

Transmission Service Customer

Total Est. DAUC Due

Initial DAUC Report April 28,

2016

Total Est. DAUC DueRevised DAUC Report

July 1, 2016

American Electric Power (in addition to request 1162214)

$21,545,607 $21,053,597

Chanute, Kansas $19,936 $19,936

Golden Spread Electric Coop. $4,313,008 $2,295,765

Kansas Electric Power Coop. $6,195,560 $6,195,560

Westar $10,572,329 $7,352,662

$42,646,440 $36,917,521

• Approximately $17 million of DAUC were re-classified as Base Plan to account for customers with load in multiple zones.

• Waiver Group B DAUC was reduced from $43 million to $37 million.

• Others with DAUCs were reduced from $88 million to $77 million.

• Total DAUC was reduced from $131 million to $114 million.

Waiver Group B Revised

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All: Waiver Group B + Others with Direct Assignments

Summary of Z2 Direct Assignments by Reason

34

Reason $DAUC % of Total

Attachment J Sec III.A.4Wind Upgrades Outside the Point of Delivery (“Wind Rule”) $42,181,519 37%

Attachment J Sec III.B.1(a) Term less than 5 years (“Term”) $1,503,660 1%

(b) Resource/Load Ratio exceeds 125% (“125% Rule”) $11,881,504 11%

(c) Wind/Load Ratio exceeds 20% (“20% Rule”) $58,509,642 51%

$114,076,325 100%

Waiver Group B by Reason

Customer Wind Rule Term 125% Rule 20% Rule Total

AEP $20,447,520 $606,077 $21,053,597

Chanute $19,936 $19,936

Golden Spread $2,295,765 $2,295,765

KEPCO $6,195,560 $6,195,560

Westar $7,352,662 $7,352,662

$30,095,948 $606,077 $6,215,496 $36,917,521

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Staff’s Recommendation on Group B• SPP Staff’s recommendation to deny the Group B waiver

requests is based not on the merits of arguments made by the requestors, but rather on the threshold issue of whether the tariff permits a waiver request to be considered in the first place. Waiver of the “Wind Rule” (Sec. III.A.4) is not permitted under the

tariff. Waiver of the Base Plan eligibility criteria (Sec. III.B.1) is

permitted if-and-only-if the waiver request is made simultaneously with the service request (Section III.C.1), which none of these were.

• SPP Staff has concluded that because the tariff requirements are not satisfied, there is no authority to approve waivers under the tariff provisions.

• HOWEVER, SPP Staff is sympathetic to customers’ concerns, and would support an effort to identify alternative means of addressing them.

• Customers raise a number of compelling issues…

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Concerns raised in waiver requests• Because the Z2 information listed in the study reports was

incomplete, customers were not fully aware of the potential Z2 costs at the time they committed to the service, which prevented them from making informed decisions.

• Customers made financial commitments based on incomplete information such that Z2 costs now render those commitments un-economic.

• Even though the tariff requires that Z2 costs be charged, it is unfair for customers to be charged for Z2 costs that were not identified in the service agreements.

• Even though customers are required to pay for upgrades committed to on their behalf, customers should not be obligated to pay Z2 costs when resources were un-designated prior to the start of service.

• Costs for Sponsored Upgrades should be allocated based on the rules in effect at the time a CPO is assigned rather than the rules in effect at the time an upgrade becomes creditable.

• The magnitude of Z2 costs is too large to recover over the 10-month term of the approved payment plan.

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MOPC Motions• It was moved that SPP seek a waiver from FERC to allow

KEPCO to be allowed to Base Plan fund their cost associated with Z2 credit payments related to KEPCO's existing transmission requests by waiving the 125% resource to load requirement. The motion failed.

• It was moved that the following proposal be adopted: Waive all Group B & C DAUC with the following

parameters/exceptions: Waived DUAC would be recovered by SPP using the BPF mechanism

appropriate for the creditable facilities as already determined by SPP. Within 30 days, customers with Group B & C DAUC related request could

be indefinitely released, in whole or in part, without penalty. Historical amounts would remain BPF under the waiver.

No new SPP analysis would be provided. Customers with DAUC would have to make decisions based on the information in hand.

After 30 days, parties still exceeding the 20% wind or 25% resource limits would be responsible for the associated DAUC.

The motion failed.

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MOPC Motions• It was moved that the directly assigned upgrade costs for

AEP’s TSR # 1337138 be waived. The motion failed.

• It was moved that the directly assigned upgrade costs allocated to the city of Chanute be waived. The motion failed.

• It was moved that the directly assigned upgrade costs allocated to Golden Spread Electric Cooperative be waived. The motion failed.

• It was moved that the directly assigned upgrade costs allocated to Westar TSR# 75710756 be waived because it had been un-designated prior to the start of service. The motion failed.

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Linwood-Cedar Grove 138 kV Series Line Reactor Re-evaluation

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Background• Project approved in 2016 ITPNT was a line

reactor on Linwood–Cedar Grove 138kV line

• Expedited re-evaluation was requested by AEP and approved by SPP Board

• Engineering Economic Analysis• The Linwood-S. Shreveport Rebuild was

determined to be the best alternative project and was incorporated in the re-evaluation

• Additional Information Received for the Linwood-S. Shreveport Rebuild Study estimate - $5.7 million Updated cost estimate received - $4.2 million Increase in emergency rating from 382 MVA to 511 MVA

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41

Comparison of Alternative Projects

Reactor Only* Rebuild Only Rebuild Only with New Information

Monitored Element

LINWOOD – CEDARGROVE 138kV LINWOOD – CEDARGROVE 138 kV

LINWOOD – CEDARGROVE 138 kV

Contingency ARSENAL HILL - FORT HUMBUG 138 kV

ARSENAL HILL - FORT HUMBUG 138 kV

ARSENAL HILL - FORT HUMBUG 138 kV

Relief Score 11.696 14.531 16.28

Project Cost $3.5 Million $5.7 Million $4.2 Million

Relief Metric($/Relief

Score)302,236.45 392,233.51 258,013.85

Staff Conclusion

Rebuild only with new information represents the better relief metric with the updated cost of $4.2 Million

*Additional loading analysis concluded the reactor defers need for the rebuild until 2026

Best!

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$0

$2

$4

$6

$8

$10

$12

Cost

($M

)

Year

Cumulative Cost for Each Option (2016$)Option 3 - Reactor + Rebuild (deferred)

Option 2 - Rebuild

Option 1 - ReactorCrossover Year: 2027Benefit of Option 2 over Option 3: $9.8M - $6.25M = $3.55M

Engineering Economic Analysis

42

$6.25M

$9.80M

$5.25M

Consideration of additional information results in the selection of the rebuild of Linwood-S. Shreveport 138 kV line as a more cost effective solution 41 of 101

Staff Recommendation

• MOPC Approved Unanimously

43

Project Name Recommendation

Series Line Reactor Withdraw NTC

Rebuild Linwood – S. Shreveport Issue NTC

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Roundup – Kummer Ridge 115 kV Re-evaluation

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Background• SPP Board of Directors approved upgrades contained in

the Basin NTC-C No. 200387 from the 2016 ITPNT

• Basin requested an expedited re-evaluation of a new 33-mile 115 kV line between Roundup and Kummer Ridge substations Concerns:

Inaccurate transmission model Long-term viability “one-shot” right-of-way

Proposed alternative:

A 33-mile 345 kV line between the Roundup and Kummer Ridge substations

• A proposal was made during the July MOPC meeting to construct the line for future 345kV operation but initially operate at 115kV

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Roundup – Kummer Ridge Study Area

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Analysis• Load delivery point modification study Evaluated the addition of the Kummer Ridge delivery point Determined no adverse reliability impacts to the SPP System

• Reliability study Included 10-Year model set Updated system topology Evaluated project performance Determined 345 kV solution was more cost effective

• Economic study Annual energy production cost analysis using 2017 ITP10 futures Calculated B/C ratios Determined 345 kV and 115 kV solutions performed comparably

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10-Year Reliability Study• Additional transmission solutions needed to solve all

reliability issues 115 kV line solution set = ~$51M

345 kV line solution set = ~$64M

• 345 kV vs 115 kV (2.5% annual forecasted load growth)* Both address thermal issues, 115kV better metrics

Both address voltage issues, 345kV better metrics

• 345 kV vs 115 kV (3.5% annual load growth) Both address thermal issues, 115kV better metrics

345 kV addresses voltage issues, 115 kV has non-convergent issues

345 kV solution set performs better than the 115 kV solution set over the 10-year planning horizon

*At 2.5% annual load growth, 115 kV solution set is no longer adequate in 2026 based on extrapolation of 10-year study results 4847 of 101

49

Economic Study

• Results for 345 kV solution comparable to 115 kV solution

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Engineering Economic Analysis

50

$115.6M

$89.2M

$82.8M

$51.1M

Crossover Year: 2026

Note: analysis excludes costs of additional solutions needed to address all area reliability needs49 of 101

Engineering Economic Analysis for the 115 kV and 345 kV Solution Sets

51

$121.8M$134.3M

Crossover Year: 2026

$140.7M

$160.3M

$95.8M

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Roundup-Kummer Ridge• Risks of building at 115 kV One shot right of way, would not be able to build another

project along that corridor unless wreck out/re-build Another project could be needed in future

• Risks of building at 345 kV, but operating at 115kV Estimate of 2 weeks would be needed to convert to 345

kV operation

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Staff Recommendation

• MOPC failed to take any action.

• Two motions failed: Approve the staff recommendation Approve building at 345kV but operate at 115kV

53

Project Name Recommendation

Replace Roundup - Kummer Ridge 115 kV transmission line with the Roundup - Kummer Ridge 345 kV transmission line

Modify NTC

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Walkemeyer RFP NTC Re-evaluation

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Background• SPP Board of Directors directed re-evaluations of Phase 1 and

Phase 2 of the Walkemeyer area projects Mid-Kansas Electric Cooperative requested re-evaluation of Phase 2

due to load decreases in April 2016

• Phase 1 (2015 ITPNT and 2015 ITP10) Tap Hitchland - Finney 345kV line near existing Walkemeyer 115 kV

station

New 345/115kV station and transformer at tap point

1 mile line from new station to Walkemeyer 115 kV station

NTC issued for Phase 1 in May 2015

• Phase 2 (2015 ITP10 only) New 21 mile 115 kV line from Walkemeyer - North Liberal

RFP awarded for Phase 2 in May 2016

• Analysis Incorporated TO supplied load update

Performed reliability assessment, including load growth analysis

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Area Load Comparison

56

1159

13111290

11471114 1101

950

1000

1050

1100

1150

1200

1250

1300

1350

2013 2014 2015

MW

Sunflower Load Forecast vs Actual Load

Planning Peak Load Actual Load 55 of 101

Observed Oil Load Amounts

57

173

129

250

20

40

60

80

100

120

140

160

180

200

2015 ITP10 2016 ITPNT 2016 MDWG

MW

Forecasted Year 10 Oil Load Amounts

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Analysis Summary• Voltage violations observed with removal of

Phase 1 and Phase 2

• No thermal or voltage violations were observed as a result of Phase 2 being removed from the models

• With Phase 1 in-service, voltage violations occur at approximately 23% load growth in the study area, compared to current projections

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Staff Recommendation

• MOPC approved with 2 Abstentions

59

Project Name Recommendation

Walkemeyer – North Liberal 115 kV line Withdraw NTC

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Information

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Current RARTF Members

61

RARTF MembersChairman Steve Stoll Missouri Public Service Commission

Vice-Chairman Richard Ross American Electric Power

Commissioner Shari Feist Albrecht Kansas Corporation Commission

Commissioner Lamar Davis Arkansas Public Service Commission

Board Member Steve Lichter Nebraska Power Review Board

Bill Grant Southwest Public Service

Bary Warren South Central MCN/GridLiance

Philip Crissup Oklahoma Gas & Electric

Harry Skilton SPP Board of Director

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OATT Requirements

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SPP Tariff Requirement – Reviews.

• The Transmission Provider shall review thereasonableness of the regional allocationmethodology and factors (X% and Y%) and thezonal allocation methodology at least once everythree years in accordance with this Section III.D.

• The Transmission Provider and/or the RegionalState Committee may initiate such review at anytime.

• Any change in the regional allocation methodologyand factors or the zonal allocation methodologyshall be filed with the Commission.

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RCAR II RESULTS

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RCAR II– B/C Ratio

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RCAR I & RCAR II Comparison

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Comparison of Benefit/Cost Ratios

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Comparison of SPP-Wide Benefits by Metric for RCAR I and II

68

Metric RCAR I RCAR II(2013$m) (2016$m)

APC Savings $3,020 $8,974Assumed Benefit of Mandated Reliability Projects $2,475 $5,759Mitigation of Transmission Outage Costs $340 $1,014Capacity Savings from Reduced On-Peak Losses $155 $743Increased Wheeling Through and Out Revenues Not Monetized $641Marginal Energy Losses Benefits Not Monetized $427Avoided or Delayed Reliability Projects $97 $41Benefit from Meeting Public Policy Goals $296 $0Reduced Cost of Extreme Events Not Monetized Not Monetized

Reduced Loss of Load Probability Not Monetized Not Monetized

Capital Savings from Reduced Minimum Required Margin Not Monetized Not Monetized

Total Benefits (PV of 40-yr Benefits for 2015-2054) $6,383 $17,599

Total Portfolio Cost (PV of 40-yr ATRR) $4,581 $7,18067 of 101

Work with Deficient Zone

• City Utilities of Springfield Staff has worked with CUS to address remedy

options CUS has expressed interest in Remedy #2 Issuance of NTCs for selected new upgrades

CUS will be focused on upcoming planning processes 2017 ITP10 (January 2017) Seams Study with AECI (End of 2016) Seams Study with MISO (TBD)

Another option would be for the SPP BOD to direct a High Priority Study for the CUS area

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Other Zones

• Two additional zones are above the 0.8 threshold but below the 1.0 OPPD and Empire RARTF Report and Lessons Learned both stated that

zones above the threshold but below 1.0; “that this analysis should be used and considered as a part of SPP’s transmission planning process in the future.” Staff will work with both in upcoming planning

processes to address needs and solutions for OPPD and Empire

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Motions from SPP Stakeholder Groups• RTWG Motion: Received and reviewed RCRA II Report

and agrees that it meets the terms of the Tariff. (Unanimous)

• RARTF Motion: Approve the report as complying with the requirements of the tariff and approved methodologies. (Unanimous)

• MOPC Motion: Approve the completion of the report as complying with the requirements of the tariff and approved methodologies. (1 Abstention – OPPD)

• RSC Motion: Approve the RCAR II Report as drafted by SPP Staff. (Unanimous)

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MWGUpdate on 2014 ASOM MMU Recommendations

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Closed MMU ASOM RecommendationsQuick Start Logic

• In 2015, MMU observed that over two-thirds of power produced by QSRs corresponded to intervals where LMP was above the market offer, and the RUC MWP trend is down

• RR99 (Short-Term RUC) was implemented 4/25/2016, and Quick-Start (RR116) is approved and scheduled for implementation in Q2 2017

JOU Combined Resource Option Potential MWP Manipulation

• MMU believes approved design changes will fully address the manipulation issue and most of the market efficiency concerns.

TCR and ARR System Availability

MMU expects improvements resulting from the implementation of RR91 7372 of 101

Closed MMU ASOM RecommendationsTCR Bidding at Electrically Equivalent Settlement Locations

• MMU continues to monitor this issue pending full implementation of proposed changes

Market Power Mitigation Conduct Thresholds

• MMU observed lower than expected mitigation levels in 2015, and decided to maintain a cautious approach to consider these items as potential issues; MMU is withdrawing this recommendation

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Open MMU ASOM Recommendations

Ramp-Constrained Shortage Pricing

• Evaluating FERC Order on shortage pricing before taking any action

Potential Manipulation of MWP Provisions

• RTO is currently in discussions with the MMU to find best measures for abating risks associated with these issues and will present options at a future MWG meeting

Day-Ahead Must-Offer Requirement

• MMU plans to resubmit a Physical Withholding Revision Request pending impact simulations

• RR125(Removal of DAMKT Limited Must Offer) was tabled at the July 2016 MOPC until July 2017 or until MMU resubmits a Physical Withholding RR

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Open MMU ASOM Recommendations

Transmission Outage Reporting and Modeling

Monthly over-allocation issue is the MMU’s underlying concern and the outage reporting issue is related to this monthly process.

MMU recommends SPP consider alternative approaches to addressing monthly over-allocation concerns

Allocation of Over-Collected Losses to BSSs

• MWG requested staff to determine a way to remove only OCL distribution for BSSs that distort market incentives

• RTO staff developing options for the September 2016 MWG meeting

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CMTFSupply Adequacy Working Group (CGC first)

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CMTF Status Update

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• Developed a proposed charter for its successor group (Supply Adequacy Working Group)

• Approved a structure and guidelines for data submittal to be used for implementation of new policy and NERC compliance efforts (Resource Adequacy Workbook)

• Provided direction regarding clarifications needed in development of Tariff language

• Will continue to be available for guidance until the Supply Adequacy Working Group is in place

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Supply Adequacy Working Group

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• MOPC recommends formation of a new working group that would be responsible for 1) development and implementation of policies and processes to ensure reliable supply of capacity necessary to meet demand and supply adequacy requirements/ methodologies in SPP, and 2) ensuring that these processes and policies meet the compliance obligations of NERC Reliability Standards• Combines the activities of the Generation Working Group and

CMTF• Fuel supply would be assigned to this group from the Gas

Electric Coordination Task Force as well• MOPC recommends the retirement of the GWG

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TPITFSPP Planning Process Improvement Recommendations White Paper

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• Maintain an Economical, Optimized Transmission System– Integrated Transmission Planning Check and Adjust– Cost Controls on Competitive Transmission– Flexibility to Address Policy Initiatives– Value Pricing: Import/Export Strategy, and Cost Allocation– Fair and Equitable Cost/Benefit Allocation Policies

SPP Strategic Plan

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TPITF Members• Brian Gedrich – Chair

o NextEra Energy Transmission

• Jason Atwood- Vice Chairo N. Texas Electric Cooperative

• Antoine Lucas – Secretaryo Southwest Power Pool

• Mo Awado Westar Energy

• Bruce Cudeo Xcel Energy/SPS

• Katy Onneno Kansas City Power & Light

• John Krajewskio Nebraska Power Review Board

• Adam McKinnieo Missouri PSC

• Alan Myerso ITC Holdings

• Steve Sanderso Western Area Power Administration - UGPR

• Wayman Smitho American Electric Power

• Lloyd Kolbo Golden Spread Electric Cooperative

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• Current three-year planning cycle is not timely and is inflexible.• ITP20 is resource intensive with primarily strategic value and no

actionable results.• Stakeholder process approvals and model development are

bottlenecks and can limit the frequency of the planning process.• Duplication and variance of modeling in planning processes and

studies create inefficiencies and add additional time.• Lack of correlation between operational and planning observations.• Lack of economic assessment in the near-term.• NTCs not issued for compliance needs beyond N-1.• Need more enforceable deadlines for meeting schedule milestones.• Lack of process consistency from study to study.

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Key Issues Identified

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Recommendations• Implement annual ITP 10-year planning assessment process

• Develop standardized study scope

• Establish a common reliability planning model

• Utilize a holistic approach to planning

• Create a Staff/Stakeholder accountability program

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SPP 3-Year Planning Cycle Assessments

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Current ITP

Process

New ITP Process

Note: with the new planning process, a 20-year assessment will be performed no less than once every five years. The performance of the 20-year study is not captured above.

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Comparison

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Transition

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• Tariff and Governing Document Revisionso Complete by April 2017

• Current Planning Processo 2017 ITP10 – January 2017o 2017 ITPNT – April 2017o 2018 ITPNT – April 2018

• New Planning Processo 2019 ITP Planning Cycleo Process starts in September 2017 with model build and

completes in October 2019

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TWG2017 ITPNT Scope

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2017 ITPNT Scope Changes• Additional Contingency Events

• Scenario 5 methodology in 2017 ITPNT (MOPC AI 266)

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Additional Contingency Events

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Background• New TPL-001-4 standard imposes tighter

requirements for maintaining service to load under events that involve more than a single contingency

• Members have requested additional contingency event analysis in 2017 ITPNT to improve opportunities to meet these requirements with transmission projects rather than relying solely on SPP’s TPL analysis performed under a separate process

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TWG Approvals• TWG unanimously approved event screening and

analysis process for incorporating the additional contingencies Event screening: Use generation shift factors to remove

non-impacting contingencies Analysis process: Hybrid approach that gives members

opportunity to review and suggest system adjustments Adds 7 weeks to needs assessment with a cost of $112k TPL compliance could be met by project receiving an NTC,

but it is not guaranteed

• Additional TPL events be analyzed on Scenario 0 models only, for 2021 Summer Peak and Off-Peak cases Projects needed only for additional TPL-001-4

contingencies given a need date no earlier than 2021

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Scenario 5 Methodology

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Scenario 5 Background

• Scenario 5 Maximizes all applicable, confirmed, long-term, firm

transmission service with its necessary generation dispatch consistent with SPP OATT, Attachment O, III.6.f

Emphasizes higher wind transfers. Concern has been expressed about unrealistic

assumptions during summer peak conditions

• MOPC Action Item 266 TWG/ESWG investigate the Scenario 5 method in the 2017

ITPNT to incorporate thoughts of the TPITF

• TPITF has proposed in a whitepaper ways to deal with the stakeholder concerns regarding Scenario 5

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• Utilize an SPP Balancing Authority coupled criteria for determination of Scenario 5 needs

Scenario 5 Methodology Option 1

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> 100% loading or < .90 pu

> 95% loading or < .92 pu

Reliability Need

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Scenario 5 Methodology Option 2• Develop a new model scenario which accounts for

long-term firm transmission service but utilizes expected conventional and renewable resource output levels based upon TPITF recommendations subject to TWG review

• Could contain: Non-Coincident Peak load forecasts Assumed Long-term firm transmission service

usage levels in relation to the year & season Expected conventional and renewable resource

output levels

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Approvals• TWG Approved Option 1 unanimously Determining Factors: Schedule/Resource impacts to 2017 ITPNT for Option 2 Potential to incorporate Option 2 in the 2018 ITPNT, prior to

TPITF process completed in 2019

• MOPC Approved changes to the 2017 ITPNT Scope

unanimously

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ORWG2017 Variable Generation Integration Study Scope

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Scope Overview1. Transient Stability Analysis for the Spring MDWG

2017 outlook for the 30%, 45%, and 60% wind cases.

2. Seasonal Voltage Stability Analysis 2017 and 2021 year outlook. Comparison between Thermal and Voltage to determine if Voltage Stability or Thermal limitations are the most limiting. Consider Operations vs Planning topology.

3. Frequency Response Analysis for the spring MDWG 2017 outlook for the 30%, 45% and 60% wind cases.

4. Targeted 5 Minute Analysis Future Ramping 5 Year Outlook.

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Model Build –Scope/Assumptions• 2017/2021 Spring Topology

Light load conditions Historical Spring Transmission and Generation Outages using 2015

light load hour

• Constants SPP interchange, slightly importing DC ties Non-SPP generation and load

• GI Queue Used to add wind resources to achieve 60% wind

penetration On-schedule with Interconnection Agreement

• Powerflow Models 2016 Series MDWG

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Approval Summary• ORWG, TWG, ESWG, and MOPC have approved the 2017

Variable generation Integration Study scope as documented

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Consent Agenda

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