Southwest Power Pool EXPORT PRICING TASK FORCE … minutes 20161019.pdfSouthwest Power Pool EXPORT PRICING TASK FORCE MEETING Wednesday, October 19, 2016 American Airlines Admiral’s

Export Pricing Task Force Meeting No. 1 October 19, 2016

Southwest Power Pool EXPORT PRICING TASK FORCE MEETING

Wednesday, October 19, 2016

American Airlines Admiral’s Club, DFW Airport, Dallas, Texas • M I N U T E S •

Agenda Item 1 – Call to Order and Administrative Items

Mike Wise (GSEC) called the meeting to order at 8:00 AM. Members present included: Dennis Florom (LES); Graham Edwards (Director); Blaine Erhardt (BEPC), by phone; Greg McCauley (OGE); Richard Ross (AEP); and, Wes Berger (Xcel). SPP Staff included Michael Desselle, Jay Caspary, Antoine Lucas, Casey Cathey, David Kelley and Sam Loudenslager. Other guests participated in person or via phone (Attendance – Attachment 1 and 2).

Agenda Item 2 – Review of Scope of Work of the Task Force

Sam Loudenslager reviewed the scope of the Task Force (Export Pricing Task Force presentation – Attachment 3). He reminded the participants that SPP has an abundance of variable energy resources in the region and that such resources represent a strategic opportunity for SPP and its members, if possible, to capitalize on the ability to export this resource. In response to a question about the genesis of the Task Force (i.e., is the premise that, or has it been determined, that the current export pricing is somehow incorrect), it was explained that 15.8 GW of renewable resources (wind) are currently installed and all syncing in the footprint, so SPP needs to look at the cost and barriers to entry. Sam further noted that the TF will:

• evaluate mechanisms to establish equitable and not unduly discriminatory prices for exports and imports of electricity, including:

o Considerations of existing provisions in the tariff; o Reviewing FERC policies; o Consideration of impacts on planning, operations, reliability, market design, and seams;

and finally, o Recommend a rate design.

• Evaluate business case for export.

Agenda Item 3 – Status of Wind by State

Sam discussed the current and potential wind supply by state (Attachment 3, pages 7-8).

Agenda Item 4 – Wind Transfer Analysis

Antoine Lucas described the results of SPP’s Wind Transfer Analysis (Wind Transfer Analysis – Attachment 4). The analysis indicates the amount of wind and solar resources in SPP’s Generation Interconnection Queue. Antoine noted that since 2013 a lot of wind is “staying in the queue”. It was noted that 90-95% of the queue is comprised of wind and solar and that it was only primarily located in the western part of the SPP footprint. Steve Gaw (Wind Coalition) noted that in the last couple of cycles wind has been proposed to be added in synchronization with the Production Tax Credit (PTC). Now that the five-year rampdown of the PTC is occurring, capital costs are also decreasing. However, as Mike Wise noted the concern is that the wind is not dropping out of the queue. Steve Gaw noted that developers are avoiding the congestion in the west and they are seeking more proposed wind resources in the east of SPP’s footprint, or said another way “exchanging location with capacity factor”. Antoine informed the Task Force that over 22GW of renewables is already connected or on schedule to be connected over next 26 months. Further he noted that the wind in the study queues would add to this 22GW and potentially SPP will be faced with 43 GW, which is higher than SPP’s actual 2016 Minimum load. Antoine further described observations (Attachment 3, pages 6-7). Specifically, it was noted that this year alone SPP has already seen 146 hours of negative Marginal Energy Costs (MEC)s, so from an operational standpoint we are already at a saturation point. That is driving siting further east in Oklahoma to avoid the higher interconnection costs, but not avoiding the negative MECs. Not only does this create

Export Pricing Task Force Meeting No. 1 October 19, 2016 operational limitations, but the amount of wind is challenging how SPP even studies it. Further, from a planning perspective, SPP is facing system limitations exporting the wind. The First Contingency Incremental Transfer Capability studies are identifying 230KV and above constraints as well as limits on the lower level voltages. Studies are indicating that 1469 MW is the maximum wind export before hitting the first constraint. As an aside, Mike Wise noted that SPP members should feel good about the fact that the system hasn’t been overbuilt.

Agenda Item 5 – Wind and Voltage Stability Casey Cathey presented the results of the Wind Integration- Voltage Stability Study (Wind Integration Study, Voltage Stability – Attachment 5). He noted some overlap of efforts with the Voltage Task Force. While describing the modeling assumptions and parameters utilized in the study effort, Casey responded to questions and clarified elements of the study effort. During this discussion Casey noted that the study is designed to see where the system collapses and assumes continued building of transmission to protect firm. Casey noted in response to pushback that in real time, Operations would curtail such transactions and the question would then become an economic issue. Mike Wise suggested that the communication of that fact is very important to allay the concerns of building more transmission to support exports on the “backs of consumers”. Casey described the results of the study and responded to questions. Additionally, Casey noted some additional study deliverables including: a break-even point at which to curtail or require addition of devices; a reactive power study of wind generation; and an incremental cost associated with operating wind in SPP’s footprint. He noted that the Voltage Task Force is considering a Revision Request for Renewable Generator Real Power (MW) Limits.

Sam Loudenslager reminded participants that all this information ties back to the question of Exporting this wind from SPP footprint, and that based upon the results of these studies it appears that exporting will not necessarily be the solution to all this wind. This led to a discussion about additional areas of analysis and drivers, as well as the identification of barriers to identify.

Agenda Item 6 – FERC Decisions

Sam Loudenslager reviewed FERC decisions having an impact on the subject of Exports (Attachment 3, Pages 12 -16). Sam noted specifically, the FERC’s decisions regarding: Order 1000; MISO Multi Value Projects (MVP)s; and, MISO/ITC Phase Angle Regulator. Sam articulated the Commission’s Orders in these cases can be summarized as indicating that a RTO can’t force something onto their neighbor. Agenda Item 7 – Tariff Provisions Sam also recounted the history of SPP’s “Through and Out” rate history with the FERC (Attachment 3, pages 18 – 20). He additionally cited discount rate provisions applicable to only SPS and AEP.

Agenda Item 8 – Operational Issues

Sam Loudenslager recounted a list of possible operation issues yet to be resolved (Attachment 3, Pages 22 -23).

Agenda Item 9 – Discussion

Sam teed up a series of questions to spur dialogue amongst the participants (Attachment 3, Page 25). In addition to these questions, others were added for further consideration. Mike Wise asked if SPP was sending a price signal, and if so, is it the right price signal (are there barriers in the current tariff like Attachment AE). Greg McCauley noted that the West is potentially a market for this wind. Steve Gaw asked if a merchant model could resolve these concerns. Should SPP advocate a Federal funding concept where SPP is the solution. Greg McCauly asked “why not make this a pure market issue” and develop a market product as a construct. Casey Cathey noted that other markets already have implemented coordinated transaction scheduling. A question was raised about whether there are budgeted dollars in 2017 to study these matters. And Dennis Florom had captured a list of questions resulting from the day’s discussions:

o Is SPP giving an expected capacity factor for wind? o Should there be a penalty/opportunity cost that wind providers should pay? o Should wind subsidize rotating mass? o Subsidize NDEVRS to become DVERS?

Export Pricing Task Force Meeting No. 1 October 19, 2016

o Should resources with firm service deliverability get priority over non-firm? o Should Operations be looking to some wind curtailments more than RUC solutions? o Companies to sponsor wind? o Should there be a transmission cost per MW Mile per voltage? o How much of a transmission developer does SPP want to be?

Agenda Item 10 – Summary of Action Items

Action Items are:

• Schedule follow-up task force meetings; • Determine, if any, export market barriers existing in the SPP OATT; • Antoine to discuss the 2013 ITP20 Future slide at next meeting.

Agenda Item 11 – Discussion of Future Meetings

Michael Desselle discussed future meetings. The next meeting will be November 30, 2016, in Dallas, Texas. Respectfully Submitted, Michael Desselle Secretary

Southwest Power Pool, Inc.

EXPORT PRICING TASK FORCE MEETING

Wednesday, October 19, 2016

9 AM – 3 PM

American Airlines Admiral’s Club, Terminal C, Conf. Room C9, DFW

• A G E N D A •

1. Call to Order and Administrative Items ................................................................................................... Mike Wise

2. Review of Scope of Work of the Task Force ............................................................................... Sam Loudenslager

3. Status of Wind by State .............................................................................................................. Sam Loudenslager

4. Wind Transfer Analysis ...................................................................................................................... Antoine Lucas

5. Wind and Voltage Stability ................................................................................................................. Casey Cathey

6. FERC Decisions ............................................................................................................................ Sam Loudenslager

7. Tariff Provisions .......................................................................................................................... Sam Loudenslager

8. Operational Issues .............................................................................................................................. Casey Cathey

9. Discussion ............................................................................................................................................................ All

10. Summary of Action Items .............................................................................................................. Michael Desselle

11. Discussion of Future Meetings ...................................................................................................... Michael Desselle

Export Pricing Task ForceOctober 19, 2016

Sam Loudenslager

2

Agenda

• Scope of Work of the Task Force

• Current Information on Wind by State

• Wind Transfer Analysis

• Wind and Voltage Stability

• FERC Decisions

• Tariff Provisions

• Possible Operational Issues to Explore

• Initial Thoughts

3

Scope of Work of the Task Force

4

Scope of TF Work

• The TF will evaluate mechanisms to establish equitable and not unduly discriminatory prices for exports and imports of electricity.

• Will include: Considerations of existing provisions in the tariff Review FERC policies Consider impacts on planning, operations, reliability, market

design, seams Recommend a rate design

• Evaluate business case for export

5

Current Wind Situation

6

Wind Transfer Analysis

9

Wind Integration Analysis: Voltage Stability

10

FERC Decisions

11

FERC Decisions• Order 1000

• MISO MVPs

• MISO/ITC Phase Angle Regulator

12

Order 1000 Decision• FERC addressed what would occur if one region

constructs a project that will export to a neighboring region Found that the exporting region could not do so without a

voluntary agreement with beneficiaries in the importing region

• FERC also addressed the possible scenario whereby two regions develop a facility in both regions to export from one region to the other Found that there must be an interregional cost allocation

method between the two regions and that costs could not be allocated to a third region without that region’s consent

13

MISO Multi-Value Projects Decisions• In Docket No. ER10-1791 (Dec. 16, 2010) FERC initially

approved MISO’s proposal to levy a MVP charge to export transactions except for exports sinking in PJM Found that the “MVP proposal would … improve system

reliability, reduce congestion, satisfy documented energy policy mandates or laws, and enhance market efficiency which would benefit all users of the integrated transmission system.”

Since 2003, FERC has required MISO and PJM eliminate all through and out rates between the two regions On appeal the Court of Appeals remanded this issue to MISO

14

MISO MVP Decisions• On July 13, 2016, FERC on remand reversed itself on

exports sinking in PJM Found that MISO could, on a going forward basis, assess the

MVP usage charge to exports that sink within PJM and noted that “MVPs are not local; they support all uses of the system, including transmission on the system that is ultimately used to deliver to an external load, and “benefit all users of the integrated transmission system, regardless of whether the ultimate point of delivery is to an internal or external load.”

Found that MISO noted the following: the development of large scale wind generation capable of serving

both MISO’s and its neighbors’ energy policy requirements in the western areas of MISO

the reported need of PJM entities to access those resources and

the reported need for MISO to build new transmission facilities to deliver the output of those resources within MISO for export.

15

MISO/ITC Phase Angle Regulator Decision• As part of an initiative to address loop flow issues in the

Lake Erie region, MISO and ITC proposed to allocate a portion of the costs of PARs to PJM and NYISO (Docket No. ER11-1844)

• On September 22, 2016, the FERC rejected the proposal concluding that MISO/ITC failed to demonstrate that PJM and MISO benefit from the PARs The issues before the FERC in this proceeding pre-date Order

1000

16

Tariff Provisions

17

Tariff ProvisionsThrough and Out Rates:

• Exit rates in the original Tariff was the average of all Zones Was changed in 1999 to stimulate more business through SPP

• Point-to-Point service exiting the SPP region (Through and out rates) pricing is done by lowest cost interconnected Zone Schedule 7 or 8 (Lowest cost interconnected Zone); plus Schedule 11 - Zonal (Lowest cost interconnected Zone); plus Schedule 11 – Regional (Regional Average)

• Attempted to change this approach in 2011/2012

18

Tariff ProvisionsThrough and Out Rates (cont.)

• Stakeholders declined to move to a Through and Out Rate for Schedules 7 and 8

• Stakeholders approved moving to a Through and Out Rate for Schedule 11

• Tariff revisions for Schedule 11 to create a Through and Out Rate (average of Schedule 11 Zonal) were filed in Docket No. ER12-2525 and approved by FERC with an effective date of November 1, 2012.

19

Tariff ProvisionsDiscount Rates:

• There are discount rates in the tariff for SPS and AEP

• However these rates are utilized only when service is to native load customers: Discount is to schedules 7 and 8

20

Possible Operational Issues to Explore

21

Possible Operational IssuesOperational information needed:

• Existing wind PPAs

• Existing wind PTCs

• Minimal pricing differential between SPP and WECC

• Minimal pricing differential between SPP and ERCOT

• Minimal pricing differential between SPP and EI (MISO or further)

22

Possible Operational IssuesOperational information needed:

• Wind having a portion of RUC MWP

• Possible lack of transparency of pricing between markets

• External interface pricing methodology of SPP & MISO leads to 'double-counting' of congestion costs (not exactly double counting, but it is more than should be)

• Comparison or pancake transmission rates

• Physical transmission element limitations, such as DC ties hard ratings, and various AC element limitations (flowgates)

23

Initial Thoughts?

24

Export Pricing Task Force – Wind Transfer AnalysisSPP Staff

October 19, 2016

1

GI Study Data since 2013

Cluster Study Original Total MW Latest Restudy Total MW Original Wind & Solar Total MW Latest Restudy Wind & Solar Total MWDISIS-2013-001 1,629 558 1,213 178DISIS-2013-002 2,213 1,490 1,231 903DISIS-2014-001 2,211 635 1,361 410DISIS-2014-002 7,055 2,205 6,396 2,170DISIS-2015-001 5,366 2,701 4,931 2,701DISIS-2015-002 10,028 7,332 9,963 7,312DISIS-2016-001 11,307 10,975

2

30

2,000

4,000

6,000

8,000

10,000

12,000

DISIS-2013-001 DISIS-2013-002 DISIS-2014-001 DISIS-2014-002 DISIS-2015-001 DISIS-2015-002 DISIS-2016-001

Original Total MW Latest Restudy Total MW Original Wind & Solar Total MW Latest Restudy Wind & Solar Total MW

GI Studies since 2013

Renewables Status• In-Service Wind

Over 14GW on wires

• Wind/Solar on schedule to be connected by end of 2018 (under GIA)

8GW

• Over 22GW of renewables already connected or on schedule to be connected over next 26 months

4

All Wind Status• Existing Wind plus on schedule GIAs =

22GW+

• Wind in DISIS-2015-001/002 = 10GW

• Wind in DISIS-2016-001 = 11GW

• Total potential wind = 43GW+

• SPP WIS Light Load = 24GW

• Actual 2016 Minimum SPP Load < 20GW

5

Observations• Historically, studied areas that show congestion

have little additional interconnection capacity.

Most customer upgrades being assigned in these areas

DISIS 2015-02 First Study had 9.5GW and assigned $2B in updates. Restudy had 7.3GW and assigned $677M in upgrades

• More requests are being made in study areas that are less congested with fewer upgrades assigned.

• Result is that higher wind penetrations are possible in the GI queue, but unknown whether this wind can be integrated into the existing generation fleet (i.e. low load periods, ramping down conventional generation) 6

Observations• DISIS-2016-001 study was previously put on

hold due to higher queue uncertainty. The study started Sept 1st and is currently anticipated to be posted January 31st, 2017.

• 2017 Variable-generation Integration Study (VIS) should help determine requirements for new wind interconnections

• What requirements should be put on wind that makes up a majority of SPP’s generation fleet? Primary frequency response? Dynamic voltage control?

7

Preliminary Analysis• 2017 Integrated Transmission Plan – Near Term (ITPNT)

Year 1 (2017) and 5 (2021) Scenario 5 dispatch

• Transfer study DC First Contingency Incremental Transfer Capability

(FCITC) Existing SPP wind sites to external conventional generation to

east Identify 230 kV and above constraints

8

9

0%

10%

20%

30%

40%

50%

60%

0

10

20

30

40

50

60

SPP RecordWind

Penetration

2017 Light LoadScenario 5

2017 SummerPeak Scenario 5

2021 Light LoadScenario 5

2021 SummerPeak Scenario 5

Win

d P

enetration

GW

SPP WIND PENETRATION

SPP Load (GW) Wind Output (GW) SPP Wind Penetration

Wind Penetration

10

• Wind serving SPP load

• Historical record wind penetration set on April 24, 2016

SPP Load (GW)

Wind Output (GW)

SPP Wind Penetration

SPP Record Wind Penetration 20.3 10.0 49.2%*

2017 Light LoadScenario 5 22.3 10.0 44.6%

2017 Summer Peak Scenario 5 53.2 10.1 18.9%

2021 Light Load Scenario 5 23.0 10.6 46.2%

2021 Summer Peak Scenario 5 54.9 10.7 19.5%

*Includes economic curtailment

11

8,781 8,898 9,454 9,555

1170 11701170 1170

1,469

-501

1,683550

2017 LIGHT LOAD SCENARIO 5

2017 SUMMER PEAK SCENARIO 5

2021 LIGHT LOAD SCENARIO 5

2021 SUMMER PEAK SCENARIO 5

WIND TRANSFER CAPABILITY (MW)Incremental Wind Transfer Capability for External Load

Base Dispatched Wind for External Load

Base Dispatched Wind for Internal Load

Results

12

• Wichita-Kansas City-St. Louis corridor is most limiting

Base Dispatched Wind (MW)

Modeled WindCapacity (MW)

Incremental Wind Transfer Capability (MW)

Installed WindCapacity Limit* (MW)

2017 Light LoadScenario 5 9,951 13,645 1,469 15,660

2017 Summer Peak Scenario 5 10,068 13,645 -501 12,967

2021 Light Load Scenario 5 10,624 14,045 1,683 16,270

2021 Summer Peak Scenario 5 10,725 14,045 550 14,765

*Capacity factor assumption from initial wind dispatched in associated model

13

2017 Light Load Scenario 5

Incremental Wind Export:

1,469 MW

Limited Corridor

Most Limited Corridor(Wichita-KC-St. Louis)

14

2017 Summer Peak Scenario 5

Incremental Wind Export :

-501 MW

Limited Corridor


15

2021 Light Load Scenario 5


1,683 MW

Limited Corridor


16

2021 Summer Peak Scenario 5


550 MW

Limited Corridor


Additional Analyses• AC Transfer Analysis

• Economic Modeling Evaluate generation dispatch changes due to increased wind Evaluate reduction in production costs

• Leverage longer-term models to understand future needs of system 5-year 10-year 20-year

17

18

$ $10M $20M $30M $40M $50M $60M $70M $80M

Non-Wind

Wind

2015 SCHEDULES BILLED FORPOINT-TO-POINT EXPORTS

Schedule 7 Schedule 8 Schedule 11 (Regional) Schedule 11 (Zonal)

10.2 TWh

19.3 TWh

Wind Integration Study–Voltage Stability

1

2

Current CapacitiesSection 1

3

Current MWs By Fuel Type• Wind Totals 15728 MWs NDVER 6430 MWs DVER 9298 MWs

• Solar 215 MWs

• Nuclear 2636 MWs

• Natural Gas 36594 MWs

• Coal 27318 MWs Generic Coal 20675 MWs Lignite Coal 3006 MWs Subbituminous 3637 MWs

• Hydro 3425 MWs

• Other Fuel Types (Oil, Agricultural Byproducts, Municipal Solid Waste)1719 MWs

0

5000

10000

15000

20000

25000

30000

35000

40000

15728

64309298

2152636

36594

27318

20675

3006 3637 3425 1719

MW's By Fuel Type

4

80438 341 80

626207 266

6441176

837 561

2171

0

1146

3827

3328

80518 859 939

15651772 2038

2682

3858

4695

5256

7427

7427

8573

12400

15728

16354

3954

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Wind Capacity Installed by Year

Wind Installed Wind Capacity Forecasted Wind Capacity Year End Forecasted Wind Capacity

626

626

5

6

Power Transfer and Reactive Reserves

Section 2

7

Voltage Stability -Classification of power system stability

8

AnalysisSection 3

9

Assumptions

• Models Steady State power flowOperations & System IntactWind penetration 30%, 45%, 60% 2016 Spring & Fall peak load

• Model parameters Lock switchable reactive devices

(cap banks, reactors) Enable voltage controlling autotransformer taps Enable Static VAR Compensator (SVC) and

continuous switch shunts Load is constant

10

Power Transfer

• Increase Wind GenerationFrom 30% to 45% penetrationFrom 45% to 60% penetrationFrom 60% to maximum power

or voltage collapse

• Decrease Large Thermal Generation Ignore real power minimum limitsHonor reactive power (MVAR) limitsProvides reactive support at 0 MW

RenewablePenetration Spring Fall

30% 7,168 7,21945% 10,756 10,82860% 14,334 14,438

Transfer Start (MW)

11

Power Transfer (cont.)

• Transfer to Voltage CollapseNormal conditions (N-0)100 MW incrementsReport 5 most limiting contingencies

• Single 345 kV line or autotransformer outage (N-1)

Event Contingency Voltage (kV)

1 Northwest to Tatonga 3452 Holcomb to Buckner 3453 Mingo to Setab 3454 Mingo to Red Willow 3455 Waverly to LaCygne 345

12

Sensitivity - Dynamic Reactive Source

• Static VAR Compensator (SVC)Used for modeling purposes to measure reactive needsSupplies reactive power while maintaining set voltage

(1.0 PU)

• LocationsWashita, Spearville, Thistle, Tatonga, Smokey Hills

• Other considerationsReliabilityCosts

13

WIS ResultsSection 4

14

Operations model – Spring (N-0)

SVC2 locations are Washita, Spearville, Thistle, Tatonga.SVC3 locations are Washita, Spearville, Thistle, Tatonga, Smokey Hills.

[1] Turn on and scale Spring 45% wind generation notin Spring 30% model.


15

Operations model – Spring (N-0)

Spring 45% plus 1,000 MW renewable generation - Voltage Contour.

16

Planning model – Spring (N-0)

SVC1 locations are Washita, Spearville, Thistle.[1] Turn on and scale Spring 45% wind generation not in Spring 30% model.[2] Turn on and scale Spring 60% wind generation not in Spring 45% model.

17

Planning model – Spring (N-0)

Spring System Intact 45% Penetration plus 2,400 MW - Voltage Contour.

18

Operations model – Fall (N-0)


19

Planning model – Fall (N-0)


20

Event 1: Transfer Levels to Voltage Collapse

SVC1 locations are Washita, Spearville, Thistle.SVC2 locations are Washita, Spearville, Thistle, Tatonga.SVC3 locations are Washita, Spearville, Thistle, Tatonga, Smokey Hills.(VC) Voltage Collapse.



21

Event 1: Operation Model Transfer to Voltage Collapse

Spring 30% Penetration Event 1 plus 3,600 MW - Voltage Contour.

22

Event 1: Planning Model Transfer to Voltage Collapse

Spring System Intact 45% Penetration Event 1 plus 500 MW - Voltage Contour.

23

Dynamic Reactive Reserve (MVAR) - Spring

Model Type

Season & Renewable Penetration

Renewable Start

(MW)

Renewable Stop

(MW)

DeltaTransfer

(MW)DRR [1]

(MVAR)SVC

(MVAR)Source

(MVAR)Sink

(MVAR) StateOperation Outages Spring 30% 7,100 10,700 3,600 446 0 278 168 StableOperation Outages Spring 45% 10,700 11,700 1,000 1,148 0 514 634 VCOperation Outages Spring 45% + (SVC2) 10,700 14,300 3,600 3,239 2,000 380 858 StableOperation Outages Spring 60% + (SVC2) 14,300 15,200 900 2,365 2,000 37 328 VCOperation Outages Spring 60% + (SVC3) 14,300 15,400 1,100 3,046 2,100 620 325 StablePlanning Spring 30% 7,100 10,700 3,600 277 0 213 64 StablePlanning Spring 45% 10,700 13,100 2,400 1,722 0 692 1,030 VCPlanning Spring 45% + (SVC1) 10,700 14,300 3,600 2,780 1,300 536 944 StablePlanning Spring 60% + (SVC1) 14,300 15,400 1,100 2,039 1,400 449 190 Stable

SVC1 locations are Washita, Spearville, Thistle.SVC2 locations are Washita, Spearville, Thistle, Tatonga.SVC3 locations are Washita, Spearville, Thistle, Tatonga, Smokey Hills.(VC) Voltage Collapse.

[1] Dynamic Reactive Reserves (MVAR) = Total Reactive Reserves = SVC + Source + Sink.

24

Dynamic Reactive Reserve (MVAR) - Fall

Model Type

Season & Renewable Penetration

Renewable Start

(MW)

Renewable Stop

(MW)

DeltaTransfer

(MW)DRR [1]

(MVAR)SVC

(MVAR)Source

(MVAR)Sink

(MVAR) StateOperation Outages Fall 30% 7,200 10,800 3,600 287 0 260 27 StableOperation Outages Fall 45% 10,800 13,000 2,200 934 0 -102 1,035 VCOperation Outages Fall 45% + (SVC1) 10,800 14,400 3,600 2,361 1,700 -240 900 StableOperation Outages Fall 60% + (SVC1) 14,400 15,400 1,000 2,141 1,500 455 186 StablePlanning Fall 30% 7,200 10,800 3,600 257 0 232 25 StablePlanning Fall 45% 10,800 13,100 2,300 922 0 -115 1,037 VCPlanning Fall 45% + (SVC1) 10,800 14,400 3,600 1,976 1,400 -23 599 StablePlanning Fall 60% + (SVC1) 14,400 15,400 1,000 1,976 1,500 319 157 Stable

SVC1 locations are Washita, Spearville, Thistle.(VC) Voltage Collapse.

[1] Dynamic Reactive Reserves (MVAR) = Total Reactive Reserves = SVC + Source + Sink.

25

Renewable generation real power (MW) limits

Model%

ReserveOperations

(N-0)Operations

(N-1)System Intact

(N-0)System Intact

(N-1)Spring 0 11,700 10,700 13,100 11,200 Spring 5 11,100 10,100 12,400 10,600 Fall 0 13,000 10,900 13,100 10,900 Fall 5 12,300 10,300 12,400 10,300

26

Preliminary VIS ResultsSection 5

Power Tech Labs/SPP Load pocket critical generator outages

27

Area Critical Ctg Load Inc. MW

Area 1 - East Nebraska "NEBCTY2G 23.0" | Pgen= 497.6MW 1220

Area 2 - SouthOK "ARBWND11 34.5" | Pgen= 79.4MW 640

Area 3 - SPS South "HOBBS_PLT3 118.0" | Pgen= 199.4MW 420

Area 4 - Woodward "SLEEPING 138." | Pgen= 73.9MW 760

Area 5 - Wichita "WCGS U1 25.0" | Pgen= 1189.6MW 240

Area 6 - KansasCityMetro "IAT G2 1 25.0" | Pgen= 900.0MW 580

Area 7 - Oklahoma City "KNGFSR12 34.5" | Pgen= 158.7MW 1080

Area 8 - Williston “LINDAHLWNDGW0.69" | Pgen= 34.9MW 840

Power Tech Labs/SPP Load pocket critical transmission outages

28

Area Critical Contingency Load Inc. MW

Area 1 - East Nebraska "TATONGA7 345." to "MATHWSN7 345." 300

Area 2 - SouthOK "TATONGA7 345." to "MATHWSN7 345." 60

Area 3 - SPS South "SUNDOWN 6230." to "AMOCO_SS 6230." 400

Area 4 - Woodward "O.K.U.-7 345." to "L.E.S.-7 345." 700

Area 5 - Wichita "TATONGA7 345." to "MATHWSN7 345." 260

Area 6 - KansasCityMetro "TATONGA7 345." to "MATHWSN7 345." 300

Area 7 - Oklahoma City "TATONGA7 345." to "MATHWSN7 345." 100

Area 8 - Williston "BELDEN -MW7115." to "RBNSNLAK-MW7115." 180

• Pre-contingencybase case

29

Power Tech Labs/SPP Contour map – bus voltages

• Post-contingencybase caseTatonga-Matthewson

30


Post-contingencylimiting pointTatonga-Matthewson

East NebraskaLoad Pocket

31


• Post-contingencybase caseWolf Creek outage

32



• Post-contingencylimiting pointWolf Creek outage

Wichita load pocket

33


• Post-contingencylimiting pointHobbs 3 gen. outage

SPS South loadpocket

34

[email protected] · 501.614.3229

Southwest Power Pool EXPORT PRICING TASK FORCE … minutes 20161019.pdfSouthwest Power Pool EXPORT PRICING TASK FORCE MEETING Wednesday, October 19, 2016 American Airlines Admiral’s

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