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SOUTHWEST POWER POOL Z2 TASK FORCE MEETING

November 29, 2016 Kansas City Power & Light Offices, Kansas City, Missouri

9:00 a.m. – 3:00 p.m. DRAFT MINUTES

Agenda Item 1 – Call to Order, Introductions and Welcome Z2 Task Force Chair, Denise Buffington, welcomed everyone to Dallas, TX and started the meeting at 9:02 am. There were 25 in attendance (Attachment 1 – Attendance List) and several on the phone and webex. The primary purpose of this meeting is to obtain background on the SPP processes that are part of the Z2 crediting effort. The Z2TF will focus of specific process enhancements at the January meeting.

Bruce Rew reviewed the agenda and provided the Z2TF with a couple of changes. Jim Flucke, with KCP&L, will present a member’s perspective on the TCR markets. This will be done under agenda item 2. The agenda did not include an approval item for the November 1, 2016 meeting minutes. The meeting minutes were distributed on November 4, 2016 but not posted. Bruce will get the prior minutes posted and the Z2TF will approve those at the January meeting. No other agenda item changes were noted. Bruce Rew reviewed the actions items from the November 1, 2016 meeting. Four prior action items were identified and provided below along with the responses. November 1, 2016 Action Items:

· Agenda Item 4 – SPP Staff will provide a summary of the Tariff requirements of Attachment Z2 and why SPP has included those in the Tariff. The Task Force is looking to determine where the requirements generated from and are they FERC mandated or something that was developed by SPP. This is an agenda item for the current meeting.

· Agenda Item 5 – SPP staff will research to determine if other regions provide credits like SPP does in the wide variety of areas such as generation interconnection, sponsored upgrades, and network transmission service. This was covered in a high level from the memo from SPP outside council. Staff will do some additional review do determine specific credits provided in the three upgrade types.



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· Agenda item 5 – Staff to develop a base line cost estimate to support the Z2 effort on an annual going forward basis and provide this to the Z2TF. This is an agenda item for the current meeting.

· Agenda item 5 – Staff to document process for including creditable upgrades in the aggregate

study process. This is an agenda item for the current meeting.

Charles Locke presented information from a prior meeting action item (Attachment 2 – Subsequent Sponsorship paid to date). Subsequent sponsors of projects have DAUC paid of $15.3 million and received credits to date of $0.6 million. Paul Malone requested that there be transparency in the payback of upgrades in the Z2 process. Agenda Item 3 – Z2 Legal Basis Denise Buffington requested that Tess Kentner present the Z2 legal basis presentation first before going into the other presentations. Tessie reviewed the three primary FERC policies related to why we have Z2 reimbursement for sponsored upgrades (Attachment 3 – FERC Polices related to Z2). The “and” pricing policy was part of the FERC acceptance on SPP’s Base Plan funding in the Tariff. This pricing policy is associated with transmission service requests. FERC Order 2003 dictated many of the requirements related to the generation interconnections. FERC’s policy on generation interconnections was to have customers “receive valuable transmission rights in return” for paying for network upgrades. FERC Order 681 specified requirements for participant funded projects. The Order also provided requirements for SPP to provide long-term congestion rights for Project Sponsors pursuant to Guideline 3 of Order No. 681. Overall SPP would need to do an assessment of any proposed changes to Z2 to ensure continued compliance with prior FERC requirements. Agenda Item 2 – ARR/TCR review Charles Cates presented an overview of the SPP ARR/TCR process (Attachment 4 – ARR/TCR Review). Charles reviewed the SPP processes for obtaining and using ARR/TCR’s in the market. He also reviewed the incremental Long-Term Congestion Rights (ILTCR). The Z2TF had



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significant discussion on the use of ARR/TCRs in SPP and how they specifically are related to generation interconnections, sponsored upgrades and transmission service. Staff has an action item to review how other markets are handling capacity and non-capacity upgrades in a ARR/TCR process. Next Jim Flucke, with KCP&L, presented a member’s view of the benefits of the TCR process (Attachment 5 – Congestion Hedging in the Integrated Marketplace). Jim discussed KCP&L’s experience with TCR market in the Integrated Marketplace. They believe that TCR’s have served their purpose and that there are opportunities for improvement. The Z2TF had significant discussion on the benefits and use of ILTCR’s in SPP and the potential for them to be a replacement for current Z2 processes. Z2 should be considered a reimbursement mechanism and not an incentive for transmission construction. Agenda Item 4: Generation Interconnection Steve Purdy presented the SPP generation interconnection process review (Attachment 6 – GI Process). The SPP generation interconnection queue has a large number of requests with approximately 23,000 MW. The majority of the requests are wind which account for almost 20,000 MW. Generation interconnection customers have upgrades that are considered capacity and non-capacity. A capacity upgrade is one that is considered to expand the transmission capacity of the system such as upgrading an existing transmission line. Non-capacity upgrades are facilities which do not expand the transmission capacity such as tapping into an existing transmission line to add a substation. The Z2TF had significant discussion on how to treat these facilities under Z2. The other concern mentioned was the uncertainty on the generation interconnection construction. GI customers have the ability to withdraw after and interconnection agreement has been signed. This may call into question whether facilities in the agreement will actually get constructed affected Z2 credits.

Agenda Item 5: Planning Studies The next topic discussed was the Aggregate Planning Study process by Charles Cates (Attachment 7 – Aggregate Study Planning Process). Charles reviewed the open season process SPP uses to aggregate transmission service requests. Starting in 2016-AG1 Transmission Customers are now receiving CPO estimates on their study reports. Steve Purdy



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stated that it is still possible GI projects pending in the queue may be missing from these estimates. Transmission customers will pay AND pricing for network upgrades and OR pricing for point-to-point service. Antoine Lucas discussed the SPP planning process. Nothing the in ITP10 or ITP20 planning is affected by Z2 crediting of upgrades.

Agenda Item 6: Operational Impacts to Short Term requests Charles Locke presented the staff’s work on operational impacts from short term requests under Z2 (Attachment 8 – Credits from Short-Term Service). Short term requests are evaluated for impacts on creditable upgrades. These short-term requests are also evaluated in the reverse direction. Short-term TSR’s only stay in the stack for the duration of their term. Charles also discussed the reduction in short-term requests since the start of the Integrated Marketplace on March 1, 2014. Long-term transmission revenue has increased after the Integrated Marketplace started.

Agenda Item 7: Base Line Assumptions Bruce Rew presented the base line estimated ongoing annual costs to operate the existing Z2 process (Attachment 9 – Staff Z2 Base Line). SPP Staff has estimated the long-term expected costs to support the Z2 crediting process. These assumptions are based on the current experience as staff is not currently in what it considers the long-term state. Staff estimates are that it will take approximately 5 FTE’s to perform the work required in support of this effort. Databases have initially been sized to last at least 5 years and up to 10 years. SPP uses a virtual server technology and expects to continue that going forward. Bruce expects the total annual costs to support Z2 to be between $500,000 and $1,000,000. Agenda Item 8 – Next Steps The Task Force will meet on January 16, 2017, at the AEP offices in Dallas. The meeting will focus on potential options for improving the Z2 process. The Z2TF requested that the SPP Staff focus on the potential ILTCR option or reverse engineering. Staff will cover those in detail and do a review of the four other proposals to potentially use parts of those as well. Grant Wilkerson and Richard Ross volunteered to present other options as well at the January



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meeting. Anyone interested in presenting a proposal please contact Denise or Bruce to get on the agenda.

Agenda Item 9 – Action Items The following action items were noted from the meeting. Action Items:

· Agenda Item 2 – SPP to review how other markets are handling capacity and non-capacity upgrades in a ARR/TCR process.

Agenda Item 10 – Next Meeting Future Z2TF Meeting: Z2TF Meeting – Monday, January 16, 2017 (10:00 a.m. – 5:00 p.m.) Location: AEP Offices- Dallas, TX Room: 8th Floor Agenda Item 7 – Adjournment With no other business Denise Buffington adjourned the meeting at approximately 2:41 p.m. Respectfully Submitted – Bruce Rew, Z2TF Staff Secretary

Subsequent Sponsorship: Paid/Received To Date

Reason

Constructed DAUC Paid Credits Rec’d Percent

GI $ 7.9 mill. $ 0.3 mill. 3.5%

Service $ 2.4 $ 0.3 11.9%

Sponsored $ 5.0 $ 0.0 0.0%

All $ 15.3 mill. $ 0.6 mill. 3.7%

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Congestion Hedging in the Integrated Marketplace(A Market Participant’s Perspective)

Jim FluckeKansas City Power & Light

SPP Board Education WorkshopJune 14, 2016

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KCP&L Overview

• Investor-owned utility under two state regulatory bodies with four unique rate structures

• Current territory established with when KCP&L purchased Aquila in 2008; now named GreaterMissouri Operations (KCP&L GMO)

• KCP&L and GMO are located onthe seam between SPP and MISO,which is a North-to-Southtransmission corridor for generationin Iowa and Nebraska

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KCP&L Benefits from the TCR Market

• Reimbursement of Congestion between Generation and Load– $11M in congestion from generation to load in the 2015-2016 TCR

Year

• KCP&L Generation – Coal and Gas-Fired Peaking Facilities

surrounding the Kansas City Metro area– Nuclear facility in eastern Kansas– Contracts for Hydro Generation in central

Nebraska– Wind facilities in western and central

Kansas (Both Network and Point-to-Point Transmission)– Small solar and biomass generation facilities

• KCP&L Load centered in the Kansas City metro area

Factors Impacting TCR Strategy for MPs

• Regulatory agencies can have a wide variety of views of hedging programs including TCRs

• Corporate risk management philosophy

• Level of congestion risk

• Types of generation

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5

Market Experiences

• Congestion uncertainties including unit output, partial month and unplanned generation and transmission outages, fuel and market prices, load uncertainty, and temporary flowgates

• Transmission addition impact on congestion– KCP&L no longer in Frequently Constrained Area

• Disconnect between Generator Interconnection/Transmission Studies and TCR market analysis for ARR Allocations

• Reductions in ARR Allocations

Congestion Pattern Change

6

Market Inception Current

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Potential Market Improvements

• Objectives include market funding and liquidity– First step was reducing ARR Allocation percentages in Annual

Auction which took effect with the recent auction– Impacts will not start to be realized until July with most significant

impacts in winter and spring periods

• Presentation by SPP on potential market changes to the Market Working Group in September 2015– Auction Schedule Modifications– Transmission Outage Coordination

• Netting of TCR Credit Portfolio (RR 126/ER16-1086)– Rejected by FERC but rehearing requested by both SPP and KCP&L

• More frequent refund of ARR Surplus (currently annual)

8

Potential Auction Schedule Changes

• Revisit current annual and monthly auctions schedules

• “Multi-Month Auctions” could be implemented to cover three months at a time with no annual auction, only annual LTCR allocations

• Benefits– Less transmission outage uncertainty leads to less TCR underfunding (5-

month vs. up to 15-month lead time) – Greater liquidity with three auction opportunities for each month– Shortens auction schedule with only one round each month– Allows for the shifting of the auction a week later in months with two auction

rounds which would improve outage modeling– More beneficial than adding second round to annual auction– Eliminates seasonal TCR/ARR periods– More consistent workload for SPP Staff and TCR professionals

• Extensive Market and software modification (Time and money)

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Outage Coordination Improvements

• Recent market changes (RR96 – Transmission Outage Timing Requirements) increased the notice to be provided to SPP for transmission system outages

• This change provided zero benefit to the TCR market because the notice time is less than the time it takes to complete the monthly TCR auction process

• Analysis of the impact and timing of outages needs to continue to determine appropriate actions

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Summary

• TCR Market has served its purpose well for now more than two years

• Opportunities for market improvement should continue to be monitored and evaluated

ARR/TCR reviewCharles CatesManager, Transmission Service

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Understanding Congestion

2

No Congestion:

• Same prices

• Net revenue = $0

20 $/MW99MW

20 $/MW0MW 20 $/MW

99MW

3

GEN2

GEN1

LOAD

*All Prices = LMP

Congestion and Pricing

Binding Constraint:

• Prices separate

20 $/MW99MW

20 $/MW0MW 20 $/MW

99MW

20 $/MW*100MW

50 $/MW1MW 50 $/MW

101MW

Congestion and Pricing

4

GEN2

GEN1

LOAD

100MW

MP SettledGEN1 $20 x -100MW = -$2,000

GEN2 $50 x -1MW = -$50

LOAD $50 x 101MW = $5,050

TOTAL +$3,000

*All Prices = LMP

Example:

Why Congestion Rights?

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30 Seconds of History

• 1995 - Bill Hogan (Harvard economist) poses need for rights

• 1998 - PJM allocates financial transmission rights ñ Initial need for transportability of firm transmission rights as load

changes providers

• 2005 – Congress passes Energy Policy Act with long-term congestion rights

• 2007 – SPP starts Energy Imbalance Service (EIS) market with physical transmission rights

• 2009 – SPP Congestion Hedge Task Force recommends financial transmission rights for Integrated Marketplace (Marketplace)

• 2014 – Implementation of Marketplace with financial transmission rights

• 2015 – Implementation of Long-Term Congestion Rights

• 2016 – Implementation of Incremental Long-Term Congestion Rights 6

1995 2000 2005 2010 20151995 2000 2005 2010 20151995 2000 2005 2010 20151995 2000 2005 2010 20151995 2000 2005 2010 20151995 2000 2005 2010 20151995 2000 2005 2010 20151995 2000 2005 2010 2015

Why the marketplace?

• Goal of congestion rights at SPPñ “…to create a hedge against transmission congestion costs

that encourages the Market Participant to offer resources into the centralized commitment and Day Ahead market with a reasonable assurance that they will derive a benefit”

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Why congestion rights?

• Integrated Marketplace objective was to incrementally benefit stakeholders by over $100 million/year net of costsñ These benefits are primarily due to centralized unit

commitmentñ Unit commitment decision primarily occurs day-ahead of

operating day

SPP’s Congestion Hedging Market

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Transmission Congestion Right

“Your right to congestion revenue (or charges) from the Day Ahead Market”

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What is a TCR?

• Financial Instrument

• Settles in the Day-Ahead Market against the Marginal Congestion Components (MCCs)

• Can contribute to large monetary impacts.

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Asset Owner Bugs Bunny

Period June 2016

Time of Use On-Peak

Source Gen_1

Sink Load_4

MW Quantity 100 MW

Why TCRs?• DA prices can be volatileñ This creates high degree of uncertainty for Load Serving Entities

• TCRs reduce exposure in Day-Ahead Market

Example:

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Price with TCR:DA Qty + TCR Qty = Net DA Settlement$5,050 + -$3,000 = $2,050

Price without TCR:DA Qty + TCR Qty = Net DA Settlement$5,050 + $0 = $5,050

Exposure Reduction = $3,000

SPP’s Integrated Marketplace

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Settlements

Day-Ahead Market

Reliability Unit Commitment

(RUC)

Real-Time Balancing

Market (RTBM)

EMS

TCR Markets

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TCR Auction Process

TCR Auction

ARR TCR

BID

Auction Revenue

Right

Transmission Congestion

Right

Auction Revenue Right

“Your right to revenue (or charges) from the TCR Auction”

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What is an ARR?

• Financial Instrument.

• Is an entitlement to a share of revenue generated in the TCR Auction.

• Is how Transmission Customers (TCs) are paid from the TCR Auction.

• Can be a credit/charge based on the TCR Auction Clearing Price (ACP) of the ARR path.

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Asset Owner Daffy Duck

Period October 2016

Time of Use Off-Peak

Source Gen_23

Sink Load_6

MW Quantity 50 MW

Transmission Service Reservation

“Your right to ship power”16

Types of TSRs

17

NITS - Network Integrated Transmission Service

FPTP - Firm Point-to-Point

GFA - Grandfathered Agreements

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ARR Allocation Process

ARR Allocation

ARRTSR

Auction Revenue

Right

Transmission Service

Reservation

What can you do with ARRs?

19

Option Impact/Implication

Self-Convert in TCR Auction

• Co-optimized with other Bids in TCR Auction

• Price modeled as “infinite”• Gives Self-Converts first priority

Self-Bid in TCR Auction

• Results in TCR if “Reserve” not met• Credit implications

No Action • Still settled at system capacity• No Reserve Price• Will never result in TCR for ARR holder

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ARR & TCR Process

TCR Auction

ARR Allocation

ARR TCR

BID

TSR

Auction Revenue

Right


Reservation


Right

Long-Term Congestion Right

“TCRs for the life of your transmission service”21

Long-term Congestion Rights

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• TSR must: 1. Be confirmed2. Cover entire TCR year (June – May)3. Have roll over rights

• Can be renewed annually

• Directly converted to TCRs for annual products

• Baseload into the ARR Allocations and TCR Auctions

Two Round LTCR Allocation

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• Round 1ñ Keep or Surrender existing LTCRsñ No Simultaneous Feasibility Test (SFT)

• Round 2ñ Remaining and new long-term service can be nominatedñ Allocated on 50% system capacityñ No outages appliedñ Solved ‘Option’ style (no counterflow)ñ Two iterations give priority to Load Serving Entities (LSEs)

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LTCR Allocation Process

LTCR Allocation

LTCR

TCR Auction

ARR Allocation

ARR TCR

BID

TSR

Can renew Annually

TSR

Auction Revenue

Right


Reservation

Long-term Congestion

Right


Right

Long-Term Transmission

Service Reservation

ILTCRIncremental Long-Term Congestion Right

“LTCRs for Sponsored Upgrades”25

Incremental Long-term Rights

• In Compliance with FERC Order 681 (EPAct 2005) the option of long-term rights are made available for participant funded transmission upgrades

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ILTCR Process

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Requests candidate ILTCR analysis of up to

three source/sink paths

Determines the minimum increase in

Available Transmission Capacity (ATC) on each path over a 10

year period

Z2 Credits…Selects one of

requested paths for ILTCR candidates or chooses Z2 credits

Gives candidate ILTCRs equal to the amount of increased

ATC on that path

Nominates cILTCRs in Initial ILTCR Allocation

Fully awards an ILTCR for the remainder of

the TCR year

cILTCRs then must be nominated again in Round 2 of the next

LTCR Allocation in the Annual Process

Upgrade Sponsor Action

Transmission Planner Action

KEY

ILTCR Allocation Process

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LTCR Allocation

LTCR

TCR Auction

ARR Allocation

ARR TCR

BID

TSR

Can renew Annually

TSR

Initial ILTCR

AllocationSU ILTCR

Auction Revenue

Right


Reservation

Long-term Congestion

Right


Right

Long-Term Transmission

Service Reservation

Sponsored Upgrade

Incremenal Long-Term Congestion

Right

ILTCRs as an alternative to Z2 Credits

ILTCRs

• Established process

• Incremental capacity based

• No recovery cost cap

• Candidates lost when equipment goes away

• Not available for non-capacity upgrades

• Upgrade → Less congestion → lower value of ILTCR

Z2 Credits

• Process redesign pending

• Flow based

• Recovery cost capped

• Only paid if people are using upgrade

29

FERC Policies related to Z2 crediting

1

FERC policies to consider• “And” pricing

• Order No. 2003- Generator Interconnection

• Order No. 681

2

“and” pricing• Crediting provisions in Attachment Z were part of FERC’s

basis for accepting SPP’s Base Plan Funding filing and finding that the proposal did not violate FERC’s prohibition on “and” pricing.

• Any alterations of Z2 crediting will need to ensure that the resulting cost allocation does not violate these principles.

3

Order 2003• FERC required that interconnection customers “receive

valuable transmission rights in return” for paying for network upgrades.

• Accordingly, if SPP seeks to change its existing Attachment Z2 revenue crediting, it will need to adopt a mechanism that complies with the Order No. 2003 interconnection pricing policy as modified by the independent entity variation standard (such as by providing congestion rights in exchange for requiring interconnection customers to fund network upgrades).

4

Order 681• Order 681, Guideline 3 required that for any participant-

funded transmission projects, the RTO/ISO had to provide long-term congestion rights to the party funding the transmission project.

• SPP complied by revising Attachment Z2 and other portions of the Tariff to provide Project Sponsors a choice between Z2 credits or Incremental Long-Term Congestion Rights.

• While Z2 revenue crediting was not necessary to comply with Order No. 681, any changes to Z2 crediting must not disturb FERC’s requirement that SPP provide long-term congestion rights for Project Sponsors pursuant to Guideline 3 of Order No. 681.

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SPP GI Study ProcessZ2 Task Force

1

Outline

• Current GI Queue Statistics

• Current GI Study Process

• Creditable GI Upgrades and Tracking

• Z2-Related Concerns and Disconnects

2

SPP GI Queue

3

4

DISIS-2013-001

DISIS-2013-002

DISIS-2014-001

DISIS-2014-002

DISIS-2015-001

DISIS-2015-002

DISIS-2016-001

Original Total MW 1,629 2,213 2,211 7,055 5,366 10,028 11,307Latest Restudy Total MW 558 1,490 635 2,205 2,701 7,332Original Wind & Solar Total MW 1,213 1,231 1,361 6,396 4,931 9,963 10,975Latest Restudy Wind & Solar Total

MW 178 903 410 2,170 2,701 7,312

0

2,000

4,000

6,000

8,000

10,000

12,000

MW

Impact Study

GI Studies Since 2013

Pending GI Requests by Generator Type & Study Stage

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Wind85%

Solar13%

CT2% Battery

0%Steam

Turbine0%

FEASIBILITY STUDY STAGE

7%PISIS STAGE

2%

DISIS STAGE54%

FACILITY STUDY STAGE

35%

IA PENDING2%

MW Requested by Generation Type

MW Requested by Study Stage

Pending GI Requests by Generator Type & Study Stage

6

Status Wind Solar Comb. Turbine

Steam Turbine Battery Total

Feasibility Study 596 903 1,499 (6%)

PreliminaryImpact 73 464 537 (2%)

DefinitiveImpact 11,630 872 49 29 12,580 (54%)

FacilitiesStudy 7,061 1,056 20 8,137 (35%)

AgreementPending 461 461 (2%)

TOTAL 19,748(85%)

2,904(13%)

513(2%)

20(<1%)

29(<1%)

23,214

November 17, 2016

Megawatts Requested

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Feasibility PISIS DISIS Facilities

GIA Negotiation

GIA

Entry Exit

Limited Operation

Study

Fast-Track Process

Interim GIA

SPP GI Study Process(simplified)

Re-studies• Turbine Change• Material

Modification• Suspension

DISIS re-study option

Mandatory Process

Optional Process

Interconnection Windows

v Feasibility Study and Preliminary Interconnection System Impact Study (PISIS) are OPTIONAL study phases. DISIS and Facilities Studies are MANDATORY. 8

Feasibility Cluster # 1

Dec 1 to Feb 28


Mar 1 to May 31


Jun 1 to Aug 31


Sept 1 to Nov 30

PISIS/DISIS Cluster # 1

Dec 1 to May 30

PISIS/DISIS Cluster # 2

Jun 1 to Nov 30

• Four Feasibility Study Cluster Windows

• Two Interconnection Impact Study Cluster Windowso Preliminary (PISIS) and Definitive (DISIS)

One Calendar Year

Interconnection Facilities Study and Generator Interconnection AgreementsJan 1 to Dec 31

GI Study Stages• High level impact

analysis• High-level upgrade

estimate

Feasibility

• High-level impact and stability analysis

• High-level upgrade estimate

PISIS

• Detailed impact, stability, and short-circuit analysis

• Mid-level upgrade estimatesDISIS

• Detailed upgrade cost estimates and construction time estimatesFacilities

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GI Upgrades• Interconnection Facilities: All

facilities and equipment between the Generating Facility and the Point of Interconnection. Sole-use facilities that are necessary to physically and electrically interconnect the Generating Facility to the Transmission System.

• Network Upgrades: 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.

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“Capacity” vs “Non-Capacity” Network Upgrades• Capacity Upgrade: Upgrades

that increase the transfer capability of the system. ñ Line re-conductorñ Wave trap replacementñ Uprate of breaker continuous

current ratingñ New line or transformer

• Non-Capacity Upgrades: Upgrades that have no effect on transfer capability. ñ New ring-bus substationñ Upgrade of breaker short-circuit

interrupting capacity

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Credit Tracking Milestones Specific to GI UpgradesTrigger Action

Cash payment made Begin tracking interest

Authorization to proceed with construction received

Begin tracking long-term transmission service impacts

Flowgate defined Model flowgate in EMS

Upgrade in-service notification received

Begin tracking short-term transmission service impacts

Final costs received True-up and re-settle creditpayment obligation and revenue reallocations

12

Concerns/Disconnects• SPP is not a party to the transfer of funds which impairs the

ability to calculate interest correctly.

• Tracking of upgrades is complicated by the fact that Interconnection Customers can withdraw or reduce their

request long after the GIA is signed; even after the authorization to proceed.

• Long-term transmission service requests are not limited to in-service resources or even those with signed GIAs. Tracking of long-term credits may have to be done before the GI study is even complete and upgrades are known, raising the prospect of re-settlements and re-calculation of impacts.

• Short-term impacts may not be captured if SPP does not receive timely notification of facilities going in-service,

raising the prospect of re-calculation and re-settlement.

• Final cost disposition may lag many months/years after credits begin flowing, leading to large re-settlements.

13

Aggregate Studies

1

Charles CatesManager, Transmission Service

Overview

• Aggregate Facilities Study Process

• Funding Mechanisms to Offset Upgrade Cost Allocations

• Network Pricing

• Point-To-Point Pricing

• MISO methodology for Cost Allocation / Recovery

2

Aggregate Facilities Study Flowchart

3

Open Season

Study Iterations #2,

#3, etc. Tender Service

Agreements

165 DaysDay 1 Day 165

Remove andRefuse TSR(s) with exceeded

parameters Confirm TSRs within

parameters

Post study results for all

TSR(s) including removed

Study Iteration

#1

All TSR(s) Parameters

Met?

YES

NO

YES

NO

Customer Increase

Exceeded Parameters?

Remove and Refuse TSR(s) with exceeded

parameters

All TSR(s) Parameters

Met?

YES

NO

4

Open Season

• Open season is 6 months in duration.

• Customers submit completed applications that include:ñ Cost parameters

ñ Start date parameters

ñ Redispatch parameters

Study Iteration #1

5

Study Iteration #1 Flowchart

6

Start of Study Iteration #1

Review CustomerService Applications

Perform ServiceStudy

Determine Request Impacts on Service

Upgrades If Required

Determine Request Impacts onLimitation

Allocate Service Upgrade Cost Based

on Request(s) Impacts

Allocate Creditable Upgrade Cost Based

on Request(s) Impacts

Determine Request(s) Impacts

on Creditable Upgrades

Compile Results In Report Tables

Flag Requests With Exceeded

Parameters

7

Start of Study Iteration #1• The study begins at the close of open season

window.

8

Application Review• For Network Integrated Service Request(s) (NITS):ñ Review NITS Applicationñ Determine eligibility for Base Plan funding (BPF) ñ Calculate Safe Harbor Cost Limit (SHCL) for Network

TSR(s)

• Compile TSR parameters to be used throughout the study for determining whether service can be granted.

9

Perform Service Study• Base Case Model Developmentñ Start with ITPNT modelsñ Include service previously grantedñ Include upgrades approved by BODñ Remove upgrades under re-evaluationñ Add new sources/sinks needed for studyñ Out-of-cycle updates

• Transfer Case Model Developmentñ Start with Base Case modelsñ Dispatch new resources upñ Dispatch existing resources down

10

Determine Request Impacts on Limitations

• Perform TDF analysisñ Apply the service to each limitation to determine

impacts each TSR has on each limitation

• Assess the TDFs of each TSR on each limitation

• If the TDF is 3% or greater impact on any limitation, the limitation is considered valid and evaluated for mitigation

11

Determine Request Impacts on Service Upgrades If Required

• Occasionally, a Service Upgrade is required in order to provide dependable service to the new TSRs.

• Perform TDF analysisñ Apply the service to each upgrade newly identified Service

Upgrades, if applicable, to determine impacts each TSR has on each upgrade

• TDFs are determined on each upgrade under system intact conditions

• Mega-Watt Impacts (MWI) are developed from the TDFs and the requested capacity

12

Allocated Service Upgrade Costs Based on Request(s) Impacts

• MWIs are determined on each upgrade for each TSR

• TSRs with a positive impact are considered for cost allocation of an upgrade per Attachment Z1ñ TSRs must have a TDF of 3% or greater on the limitation(s)

with the associated upgrade identified as the mitigation

• Cost are allocated on a MWI basis

13

Determine Request(s) Impacts on Creditable Upgrades

• Perform TDF analysisñ Apply the service to each Creditable Upgrades to

determine impacts each TSR has on each upgrade

• Must have greater than +/- 3% TDF

• MWIs are developed from the determined TDFs and the requested capacity

14

Allocated Creditable Upgrade Costs Based on Request(s) Impacts

• MWIs are sent to the Credit Stacking System (CSS) for Credit Payment Obligations (CPO)s, if applicable

15

Compile Results In Report Tables

• Report Table 1:ñ Indicates if request parameters were exceeded

• Report Table 2:ñ Indicates allocated costs for Service upgrades and

Creditable Upgrades

Report Table 1

16

Report Table 2

17

18

Requests With Exceeded Parameters

• If Request Parameters are exceeded, they are flagged in Table 1

• Parameters Include:ñ Amount of Directly Assigned Cost for both:ñ Service Upgradesñ Creditable Upgradesñ Service Start and End Date

Parameter Adjustment Window

• If any study parameters are exceeded, report is posted to SPP OASIS and only customers with exceeded parameters will have 5 Business Days to modify those parameters to remain in the study

• If no parameters are exceeded, Study is deemed complete and results are posted to SPP OASIS at the close of the study window.

19

Study Continues ….• At the close of the parameter adjustment window, the study

will continue until all remaining requests’ parameters are met.

20

Study Completion

Upon completion, SPP will:

• Finalize the solutions for the study and the cost estimates for upgrades necessary to provide the request.

• Determine allocation of the estimated cost to provide the request.

• Post results for all requests, including those that were refused.

21

Service Agreements

Allocated Upgrade costs are added to the customer’s Service Agreement:

• For Service Upgrades:ñ Section 8.10 Network Upgrade Charges

• For Creditable Upgrades:ñ Section 8.12 Other Charges

22

Funding Mechanisms to Offset Upgrade Cost Allocations

23

• Upgrade cost allocations are offset differently for both Network and Point-to-Point service.

• For Network:ñ Allocated upgrade costs can be offset by SHCL (maximum

BPF available)

• For Point-to-Point:ñ The revenue requirements for the allocated upgrade cost

can be offset by the Point-to-Point Base Rate (PTPBR)

• Generally, these costs are covered under the customer’s service plan, exceptions include:ñ DAUC from BPF Metrics Wind Ruleñ Non-Eligible for BPF Initiallyñ Revenue Requirements exceed PTPBR

Network Service Pricing• Customer pays Schedule 9 & 11 AND directly assigned

wind portion of RR if applicable AND the portion of the allocated upgrade that exceeds SHCL.

• SHCL is used to first offset Service Upgrades and the remaining BPF is then used to offset CPOs for creditable upgrades.

• The Revenue Requirement (RR) is determined by the allocated upgrade costs.

24

Safe Harbor Cost Limit

25

The SHCL (max amount of BPF) is calculated as follows for TSR(s) eligible for BPF,:

SHCL = Request MW amount * $180,000

Base Plan Funding Eligibility

26

• A TSR from a Designated Resource is eligible for BPFif:

ñ Sinks in SPP

ñ Service term >= 5 years

ñ In First Year of Service:

ñ Resources/Peak Load <= 125 %

ñ Wind Resources / Total Resources <= 20 %

Current Base Plan Funding Allocation Metrics

27

• NTCs issued dates post June 19, 2010

Point-To-Point Service Pricing• Customer pays higher of either, the PTPBR OR the

total revenue requirements (TRR)

• PTPBR is calculated using Schedules 7, 11R and 11Z.

• PTPBR is first used to offset Service Upgrades and any remaining PTPBR is then used to offset CPOs for Creditable Upgrades.

• If the TRR > PTPBR, ONLY the exceeding portion is considered creditable.

28

MISO Methodology for Cost Allocation

29* For additional information see Attachment FF of the Tariff at https://www.midwestiso.org/Library/Tariff/Pages/Tariff.aspx

MISO Methodology for Cost Recovery

30https://www.misoenergy.org/Library/Repository/Communication%20Material/Key%20Presentations%20and%20Whitepapers/Transmission%20Cost%20Allocation%20Overview.pdf

Revenue Credits from Short-Term Service

2

Short-Term Service Credits

3

• Short-term TSRs are less than 1-year term

• All short-term credits are from PTP

• MW impact based on reservation POR/POD and generator source information

• No directly assigned charges for short-term

Stacking – Short-Term• Short-term TSR stacks on the current long-

term stack

• Short-Term TSRs have to meet a 3% threshold in any hour in order to be creditable

• Once in the Credit Stacking System, the reverse impacts, if any, will stack for each hour

• In the event the reverse threshold is breached in any hour, all hours of the TSR term will be reverse creditable for that upgrade

4

Short-Term TSR Capacity Impacts

5

Short-Term Example – Reverse FlowStart of Long and Short-Term Stacks

6

100 MW Monthly request with reverse flow impact = 5 MW

100 MW Monthly request with reverse flow impact = 10 MW

50 MW On-Peak request with reverse flow impact = 10 MW

30 MW one (1) hour request with reverse flow impact = 15 MW

100 MW three (3) hour request with reverse flow impact = 30 MW

Threshold

Hours of Operating Day

MW

Start with long-term stack from ATSS4 (Reverse Flow = 125 MW)

50 MW Off-Peak request with reverse flow impact = 20 MW

Short-Term Example – Reverse FlowNew Short-Term Hourly Request 1

7

Threshold


MW

Short-Term Example – Reverse FlowNew Short-Term Daily Request 1

8

Threshold


MW


9

Threshold


MW


10

Threshold


MW

Short-Term Stack – Other Points

• Short-term TSRs only stay in stack for duration of their term

• Once crediting determination is made for a short-term TSR, that determination does not change due to subsequent reservations

11

Credit Payment Obligations for Point-To-Point Service

• Calculate CPO for each TSR and each upgrade

• Based upon the applicable PTP rates (Schedules 7, 8 and 11)ñFirm PTP Schedules: 7 & 11ñNon-Firm PTP Schedules: 8 & 11

12

CPO Calculation for PTP

13

Total Monthly Schedule Rate ($ per MW-Month)

MW Impact on

Facility

Monthly PTP CPO

CPO Calculation for PTP

Initial Upgrade Costs: $10M

Schedule Rates ($ per MW- Month)

Sch. 7 2,000 Sch. 11 Zonal 1,000Sch. 11 Regional 1,000Total 4,000

TSR Reservation (MW)

MW Impacton Facility

Rate ($)

Monthly CPO

TSRC 5 1.5 4,000 6,000TSRD 10 2.0 4,000 8,000

PTP Activity Before and After Integrated MarketplaceShort-Term Schedule 7 & 8 Revenue:

24-month total before 3/1/2014 $ 35.6 mill.

24-month total after 3/1/2014 $ 13.2 mill.

Change - 63%

Long-Term Schedule 7 Revenue:

24-month total before 3/1/2014 $ 91.0 mill.

24-month total after 3/1/2014 $106.6 mill.

Change + 17%

15

Questions?

16

Z2 Base Line on-going overhead

1

Z2 Base Line• Staff reviewed what the long-term

related costs will be to support Z2

• Estimates are based on current experience which includes bringing existing Z2 implementation current

• Assumptions made for estimate are provided

• Process overview provided on following slide

2

Transmission Services

Transmission Settlements

EMSOASIS

webTrans

Input Tables

Credit Stacking System (CSS)

Invoice

Customers’ Detail XML

Files

• Long-Term Service Impacts

• Service & Sponsored Upgrade & Payments Data

• Funding Offsets

• Generator Interconnection Upgrade & Payments Data

• Reservation Mapping• Rates• PTP Revenue

Short-Term Transfer (STT) App

Transmission Settlements

System

• Short-term Service InfoCredit Stacking System

Process Overview

Generator Interconnection

• Non-Capacity input data

Z2 Staffing Support• Z2 support encompasses multiple

departments across the organization

• Staffing estimates are based on known experience to perform Z2 work to date

• Regulatory and legal support included as part of foundational work

• Departmental Estimates – 5 FTE’sñ IT – 3 FTE’sñ Planning – 1 FTEñ Settlements – ½ FTEñ Operations – ½ FTE

4

Z2 IT Systems• Staff reviewed what the long-term

related costs are for support

• Initial databases sized for future capacity – expected to last 5-10 years

• Used virtual server technology so no new dedicated boxes for Z2 software

• Z2 Software will need to be updated on a periodic basis.

5

Additional Considerations• Z2 systems are included in audit

reviews and additional costs associated with SOC1 review internally and externally

• Systems will need to retain records for life of facilities

• Process does not allow for efficient shadow settlement and expected staff time for periodic support of Market Participants

6

Documents

Relationship-Based • Member-Driven • Independence … minutes and attachments... · The next topic discussed was the Aggregate Planning Study process by Charles Cates ... Evolutionary