definitive interconnection system impact study manual

Southwest Power Pool, Inc.

DEFINITIVE INTERCONNECTION SYSTEM IMPACT STUDY MANUAL

By Generator Interconnection Department

Published August 2021

Version 1.4


DISIS Manual August 2021/Version 1.4 1

CONTENTS REVISION HISTORY ......................................................................................................................................................... 4

OVERVIEW ......................................................................................................................................................................... 5

DEFINITIONS ..................................................................................................................................................................... 7

TARIFF DEFINITIONS ............................................................................................................................................. 7

GENERAL DEFINITIONS ........................................................................................................................................ 8

DISIS METHODOLOGY .................................................................................................................................................. 9

DEVELOPMENT OF BASE STUDY MODELS ............................................................................................................ 9

POWER FLOW MODEL SET ............................................................................................................................... 10

DYNAMIC STABILITY MODEL SET .................................................................................................................. 10

SHORT CIRCUIT MODEL SET............................................................................................................................ 10

TYPES OF UPGRADES INCLUDED IN THE BASE MODELS ............................................................................. 11

BASE CASE UPGRADES ...................................................................................................................................... 11

CONTINGENT UPGRADES................................................................................................................................. 11

POTENTIAL UPGRADES NOT IN THE BASE CASE ..................................................................................... 11

CLUSTER SCENARIO ............................................................................................................................................ 12

REGIONAL GROUPINGS ............................................................................................................................................. 13

POWERFLOW STUDY .................................................................................................................................................. 14

POWER FLOW MODELS ............................................................................................................................................. 14

POWER FLOW ANALYSIS .......................................................................................................................................... 15

CONSTRAINT IDENTIFICATION .............................................................................................................................. 15

CONTINGENCY ANALYSIS ................................................................................................................................ 16

THERMAL OVERLOADS ...................................................................................................................................... 17

VOLTAGE VIOLATIONS ...................................................................................................................................... 17

LIMITED OPERATION .......................................................................................................................................... 18

SOLUTION PROCESS AND METHODOLOGY ............................................................................................. 18

LOADFLOW SOLUTION PARAMETERS ......................................................................................................... 19

DETERMINATION OF COST ALLOCATION FOR NETWORK UPGRADES .................................................. 20

SPP DISIS RESULTS ...................................................................................................................................................... 21



SPP DISIS RESULTS WORKBOOK TABS (POWERFLOW) ................................................................................ 21

EXECUTIVE SUMMARY ....................................................................................................................................... 21

REVISION HISTORY ............................................................................................................................................. 22

REVISION DETAILS ............................................................................................................................................... 22

REQUESTS ............................................................................................................................................................... 23

CONSTRAINT SUMMARY .................................................................................................................................. 23

ASSIGNED UPGRADE COSTS ........................................................................................................................... 24

UPGRADE SUMMARY ......................................................................................................................................... 24

ALL THERMAL ........................................................................................................................................................ 25

ALL VOLTAGE ......................................................................................................................................................... 25

SHORT-CIRCUIT RATIO ...................................................................................................................................... 26

STABILITY STUDY .......................................................................................................................................................... 27

STABILITY MODELS ...................................................................................................................................................... 27

STABILITY ANALYSIS ................................................................................................................................................... 28

STABILITY FAULT EVENTS ................................................................................................................................. 28

MITIGATIONS ........................................................................................................................................................ 29

LIMITED OPERATION .......................................................................................................................................... 29

SHORT CIRCUIT ANALYSIS ....................................................................................................................................... 29

SPP DISIS RESULTS WORKBOOK TABS (STABILITY AND SHORT CIRCUIT) ............................................ 30

EXECUTIVE SUMMARY ....................................................................................................................................... 30

REVISION HISTORY ............................................................................................................................................. 30

REQUESTS ............................................................................................................................................................... 30

STABILITY ANALYSIS ........................................................................................................................................... 30

SENSITIVITY DISPATCH ...................................................................................................................................... 30

SHORT-CIRCUIT ANALYSIS .............................................................................................................................. 30

AFFECTED SYSTEMS COORDINATION ................................................................................................................. 31

FIRST-TIER EXTERNAL AREAS FACILITIES 115 KV AND GREATER .............................................................. 31

RE-STUDY ........................................................................................................................................................................ 32

CURTAILMENT AND SYSTEM RELIABILITY .......................................................................................................... 32

FREQUENTLY ASKED QUESTIONS ......................................................................................................................... 33

REFERENCE DOCUMENTS ......................................................................................................................................... 35



GLOSSARY OF TERMS ................................................................................................................................................ 36



REVISION HISTORY

DATE AUTHOR VERSION CHANGE DESCRIPTION

12/2019 SPP 1.0 DISIS Manual

6/2020 TSM 1.1 Model Acquisition Process & Location

11/2020 GI 1.2 Outdated Information Removed/GIS Dispatch

Map Updated

4/2021 GI 1.3 ERIS Removed from NR Dispatch (DIS1701 P2 &

Forward) Model Reduction

DISIS Report Guide DISIS FAQs

TPL-004-1 Contingency Guide

Solve Parameters and Generator Outage

Exception

4/2021 GI 1.3.1 Stability Dispatch Revision

8/2021 GI 1.4 Updated Study Schedule Status page

link Updated REGIONAL GROUPINGS from 16 groups to 5 Regions

Updated Dispatch table



OVERVIEW Definitive Interconnection System Impact Studies (DISIS) identify the system constraints, transient instabilities, and over-dutied equipment associated with connecting generation to the transmission system. The impact study and other subsequent interconnection studies identify required transmission owner interconnection facilities, network upgrades and other direct assignment facilities needed to inject power into the grid at each specific point of interconnection.

This manual describes the process SPP uses for its DISIS reports. The study process is operated in accordance with Attachment V of the SPP Open Access Transmission Tariff and applicable SPP business practices.

This DISIS process results in studies posted to SPP.org and distributed to generator interconnection customers and impacted transmission owners. For specific study results, visit http://opsportal.spp.org/Studies/Gen (or use this path: SPP.org > Engineering > Generator Interconnection > Study Results and Report postings).

A notification of the DISIS posting is sent to the GI Exploder email. Instructions on how to register are located at https://www.spp.org/stakeholder-center/exploder-lists/

To determine when a study is scheduled for posting, visit https://www.spp.org/engineering/generator-interconnection/ and look for the “GI Study Cluster Weekly Status” link.

http://opsportal.spp.org/Studies/Gen

https://www.spp.org/stakeholder-center/exploder-lists/

https://www.spp.org/engineering/generator-interconnection/



If you have questions regarding the DISIS process or a specific DISIS report, please contact the generator interconnection team via [email protected] or submit an SPP Request Management System (RMS) ticket (https://spprms.issuetrak.com/login.asp). Information about setting up an RMS account is available on SPP.org. (http://www.spp.org/stakeholder-center/customer-relations/request-management-system/).

Model requestors may obtain the current base case data in accordance with the SPP Open Access Tariff, Attachment V, Section 2.4 Base Case Data. To request such modeling data, a requestor must utilize SPP’s RMS tool by setting up an account and using the “GlobalScape (Docushare/State Estimator/RA) Access” QuickPick to access the GlobalScape folder where the base case data is stored. Requestors will be instructed to complete a confidentiality agreement if they do not already have one on file with SPP Legal.

Eligible requestors may also obtain SPP models specific to an interconnection request by submitting an RMS ticket and selecting QuickPick “Map/Model Orders, Submit NDA.”

Determining which RMS quick pick to use will be based on whether you are requesting specific interconnection models from an SPP interconnection study or if you need the current DISIS models.

mailto:[email protected]

https://spprms.issuetrak.com/login.asp

http://www.spp.org/stakeholder-center/customer-relations/request-management-system/

http://www.spp.org/stakeholder-center/customer-relations/request-management-system/



DEFINITIONS

TARIFF DEFINITIONS These definitions are located in the Attachment V, SPP Open Access Transmission Tariff

• Definitive Interconnection System Impact Study (DISIS)

• Definitive Interconnection System Impact Study Queue (DISIS Queue)

• Distribution Upgrades

• Interconnection Facilities

• Initial Queue Position

• Interconnection Request

• Interconnection Service

• Point of Interconnection

• Previous Network Upgrade

• Queue

• Network Upgrade

• Control Area

• Energy Resource Interconnection Service

• Network Interconnection Resource Service

https://spp.etariff.biz:8443/viewer/viewer.aspx



GENERAL DEFINITIONS Current Queue - Interconnection Requests being evaluated in this study (Transfer Case).

Prior Queue - Higher queued active requests from previous study clusters (Base Case).

Group - The interconnection requests are grouped into five (5) active regions based on geographical and electrical impacts. Please refer to the geographical map below underneath “Regional Groupings” for reference. Please note, prior to DISIS-2017-002 cluster in previous studies, the interconnection requests were grouped into sixteen (16) groups.

MW Amount - The capacity amount (megawatt) evaluated for each request.

LOIS MW Amount - Limited Operation results reflect the most limiting element based on the criteria listed in GIP 8.4.3, the Interconnection Customer may request additional scenarios for Limited Operation based on higher-queued Interconnection Requests not being placed in service. Please refer to the UPGRADE SUMMARY TAB for power flow constraint mitigation.

Upgrade ID - The identification number that SPP utilizes for each upgrade.

System Intact – N-0, Transmission system with all base case circuits intact.

N-n – Transmission system with all base case circuits closed except “n” circuits.

TDF – Transfer Distribution Factor represents the impact of an Interchange Transaction on a given flowgate. It is the measure of responsiveness or change in electrical loading on system facilities due to a change in electric power transfer from one area to another expressed in as a percentage (up to 100%) of the change in power transfer.



DISIS METHODOLOGY A power flow and transient stability analysis is conducted using a cluster scenario. The scenario includes requests in the DISIS queue that were requested in the previous open season window and all higher-queued generator interconnection requests (GIRs).

The results of load flow analysis include power flow magnitudes and voltage levels under probable contingency conditions. The results of the load flow study are used to identify equipment overloads. If an equipment overload is determined to be impacted by the GIR, a cost allocation of the mitigation will be assigned to the GIR shared by other requests in the study that also impact the facility. The study shall be conducted using both PSS®MUST and the ACCC function of PSS®E.

A transient stability analysis is performed to determine generator unit and system response due to fault events on the system. If a stability issue is determined to be resultant by the GIR, a cost allocation of the mitigation will be assigned to the GIR shared by other requests in the study that also impact the stability issue. The transient stability analysis shall be conducted using PSS®E.

For Interconnection Requests resulting in an interconnection to, or modification of, the transmission facilities of the Western-UGP (WAPA), a National Environmental Policy Act (NEPA) Environmental Review will be required.

The deliverability of the energy to final customers and the associated costs are determined by separate studies if the Customer submits a Transmission Service Request (TSR) through SPP’s Open Access Same Time Information System (OASIS) as required by Attachment Z1 of the SPP Open Access Transmission Tariff (OATT).

DEVELOPMENT OF BASE STUDY MODELS Models are developed for each study based on the specific needs and requirements of a particular study product. Feasibility studies include steady-state power flow and short-circuit analysis. DISIS studies also include dynamic stability analysis.



POWER FLOW MODEL SET The SPP Integrated Transmission Plan (ITP) power flow models serve as the starting point for all interconnection studies requiring steady-state power flow analysis. These models typically include:

DISIS-2017-001 Phase 2 & Prior Studies

• Year 1 or 2 Spring, Summer and Winter Peak

• Year 5 Light Load, Summer and Winter Peak

• Year 10 Summer Peak

DISIS-2017-002 & Future Studies


• Year 5 Light Load, Summer and Winter Peak

DYNAMIC STABILITY MODEL SET The SPP Model Development Working Group (MDWG) dynamic stability models serve as the starting point for all studies requiring dynamic analysis. These models typically include:

DISIS-2017-001 Phase 2 & Prior Studies

• Year 1 Winter Peak




• Year 5 Summer and Winter Peak

SHORT CIRCUIT MODEL SET DISIS-2017-001 Phase 2 & Prior Studies

The Year 2 and Year 10 dynamic stability summer peak models are also used for short-circuit analysis.





TYPES OF UPGRADES INCLUDED IN THE BASE MODELS

BASE CASE UPGRADES Base case upgrades are part of the current SPP Transmission Expansion Plan that have an approved Notification to Construct (NTC) or are in construction stages are assumed to be in-service and are added to the base case models if they are not already included in model.

The generation facilities’ in-service dates listed in the report REQUEST TAB may need to be delayed until completion of the upgrades listed in the UPGRADES SUMMARY TAB. In some cases, the in-service date is beyond the allowable time a customer can delay. In this case, the interconnection customer may move forward with limited operation or remain in the DISIS queue for additional study cycles. If, for some reason, construction on these projects is discontinued, additional restudies may be needed to determine the interconnection needs of the DISIS interconnection customers.

CONTINGENT UPGRADES Contingent upgrades are not yet in-service. These facilities have been assigned to higher-queued interconnection customers. These facilities have been included in the models for this study and are assumed to be in service. This list may not be all-inclusive. The DISIS interconnection customers, at this time, do not have cost responsibility for these facilities but may later be assigned cost if higher-queued customers terminate their generation interconnection agreement or withdraw from the interconnection queue. The generation facilities’ in-service dates listed in the report REQUEST TAB may need to be delayed until completion of the upgrades listed in the UPGRADES SUMMARY TAB.

POTENTIAL UPGRADES NOT IN THE BASE CASE Any potential upgrades that do not have a Notification to Construct (NTC) and are not explicitly listed within this report have not been included in the base case. These upgrades include any upgrades identified in SPP planning studies other than the upgrades in the UPGRADES SUMMARY TAB.

In addition to the base case upgrades, prior-queued interconnection requests and their associated upgrades are added to the base case models. These prior-queued interconnection requests are dispatched as energy resource interconnection service (ERIS) resources that sink into each zone in the SPP footprint in proportion to the zone’s load. Prior-queued requests for network resource interconnection service (NRIS) are also dispatched in separate NRIS scenarios sinking into the same zone.



CLUSTER SCENARIO The cluster scenario considers

• Base case

• All interconnection requests in the DISIS study queue

• All generating facilities and network upgrades that, on the date the DISIS is commenced:

o Are directly connected to the transmission system;

o Are interconnected to affected systems and may have an impact on the interconnection request;

o Have a pending higher-queued interconnection request to interconnect to the transmission system; and

o Have no interconnection queue position but have executed a GIA or requested that an unexecuted GIA be filed with FERC.



REGIONAL GROUPINGS The GIRs in each DISIS are aggregated into regional groups based on similar geographical and electrical impacts as shown in Figure 1.

Figure 1: Approximate Location of Current Regional Cluster Groups



POWERFLOW STUDY

POWER FLOW MODELS To simulate and analyze the variety of generation and service types included in a study cluster, three dispatch scenarios are developed utilizing the regional groupings.

• High-Variable Energy Resource (HVER)

• Low-Variable Energy Resource (LVER)

• Network Resource (NR).

Model Generator Dispatch

Dispatch Scenario Seasons Code Requested

Service Type

In Group Out Group

Renew. Conv. Renew. Conv.

HVER Summer, Winter, Light 01, 02, 03, 04, 05 ERIS and NRIS 100% n/a n/a n/a

LVER Summer and Winter 00 ERIS and NRIS 20% 100% n/a n/a

NR

Light 01NR, 02NR, 03NR, 04NR, 05NR NRIS 100% 100% n/a n/a

Summer and Winter 00NR NRIS 100% 100% 100% 100%

Notes: - Dispatch criteria is in accordance with BP 7350 - SPP does not modify the dispatch of existing, higher queued units with firm service if

Pgen > SPP Dispatch Criteria



Each Generating Facility is represented in the power flow models as an equivalent generator dispatched at the applicable percentage of the requested service amount with 0.95 power factor capability. The facility modeling includes explicit representation of equivalent generator step-up (GSU) and main project transformer(s) with impedance data provided in the interconnection request. Collector system(s) and transmission lead line(s) shorter than 20 miles are represented as zero-impedance branches. Longer lead lines are explicitly represented.

POWER FLOW ANALYSIS For all power flow models developed, the ACCC function of PSS®E is used to simulate single-element, breaker-to-breaker, and multi-element outages in all power flow areas of the SPP footprint, as well as other power flow areas external to SPP. The standard SPP contingency and monitored files used in the ITP determine which outages to simulate.

CONSTRAINT IDENTIFICATION An impact analysis is performed using PSS®MUST to determine the distribution factor (DF) of each of the GIRs upon the constraint (overload). For ERIS, constraints are screened to determine which of the GIRs had at least a 20% DF upon the constraint for outage-based constraints and 3% DF for constraints for system-intact conditions. Constraints that measured these criteria from at least one GIR are considered for transmission reinforcement under ERIS. In addition, stability issues are considered for transmission reinforcement under ERIS. GIRs that have requested NRIS are additionally studied in the NRIS analysis to determine if any constraint measured at least a 3% DF. If so, these constraints are also considered for mitigation under NRIS.

Service Type Constraint Type TDF % ERIS/NRIS System Intact / N-n Voltage 3

ERIS System Intact / Non-Converge Thermal 3 ERIS N-n Thermal 20 NRIS System Intact / Non-Converge Thermal 3 NRIS n-n Thermal 3

Notes:

- Constraints criteria is in accordance with BP 7250



Constraints that required transmission reinforcement are generally listed in each DISIS RESULTS WORKBOOK (see DISIS RESULTS WORKBOOK Summary) for power flow upgrades. For stability upgrades, the reinforcements are discussed in the stability section of the DISIS report.

CONTINGENCY ANALYSIS The following TPL-001-4 contingencies will be simulated and mitigated accordingly for in the steady-state analysis portion of the DISIS:

Category Initial Condition Event (HV/EHV) P1: Single Contingency Normal System Loss of one of the following:

P1:1 Generator P1:2 Transmission Circuit P1:3 Transformer P1:4 Shunt Device P1:5 Single Pole of a DC line

P2: Single Contingency Normal System P2:1 Opening of a line section w/o a fault P2:2 Bus Section Fault (EHV only) P2:3 Internal Breaker Fault (non-Bus-tie Breaker)

(EHV only) P2:4 Internal Breaker Fault (Bus-tie Breaker)

(Not Mitigated for) P3: Single Contingency Loss of generator unit

followed by System adjustments

Loss of one of the following: P3:1 Generator P3:2 Transmission Circuit P3:3 Transformer P3:4 Shunt Device P3:5 Single pole of a DC line

P4: Multiple Contingency (Fault plus stuck breaker)

Normal System Loss of multiple elements caused by a stuck breaker (non-Bus-tie Breaker) attempting to clear a Fault on one of the following:

P4:1 Generator (EHV only) P4:2 Transmission Circuit (EHV only) P4:3 Transformer (EHV only) P4:4 Shunt Device (EHV only) P4:5 Bus Section (EHV only) P4:6 Loss of multiple elements caused by a stuck breaker

(Bus-tie Breaker) attempting to clear a Fault on the associated bus (Not Mitigated for)

P5: Multiple Contingency (Two overlapping singles)

Loss of one of the following followed by System adjustments. 1. Transmission Circuit 2. Transformer 3. Shunt Device 4. Single pole of a DC line

Delayed Fault Clearing due to the failure of a non-redundant relay protecting the Faulted element to operate as designed, for one of the following:

P5:1 Generator (EHV only) P5:2 Transmission Circuit (EHV only) P5:3 Transformer (EHV only) P5:4 Shunt Device (EHV only) P5:5 Bus Section (EHV only)

The criteria for which contingencies are identified is based off of the NERC TPL-001-4 standard. To find a full description of this standard, please visit the NERC website at the following link: https://www.nerc.com.

https://www.nerc.com/



Per DISIS standards, contingency analysis excludes P6 & P7 events, and subsequently are not mitigated for.

THERMAL OVERLOADS Network constraints are found by using PSS/E AC contingency calculation (ACCC) analysis with PSS/E MUST first contingency incremental transfer capability (FCITC) analysis on the entire cluster grouping dispatched at the various levels previously described.

For ERIS, thermal overloads are determined for system intact (n-0) greater than 100% of Rate A - normal and for contingency (n-n) greater than 100% of Rate B – emergency conditions.

The overloads are then screened to determine which interconnection requests have at least:

• 3% TDF for system intact conditions (n-0),

• 20% TDF upon outage-based conditions (n-n), or

• 3% TDF on contingent elements that resulted in a non-converged solution.

Appropriate transmission reinforcements are identified to mitigate the constraints.

Interconnection requests that requested NRIS are also studied in a separate NRIS analysis to determine if any constraint measured greater than or equal to a 3% DF. If so, these constraints are also assigned transmission reinforcements to mitigate the impacts.

VOLTAGE VIOLATIONS For non-converged power flow solutions that are determined to be caused by lack of voltage support, appropriate transmission support will be identified to mitigate the constraint.

After all thermal overload and voltage support mitigations are determined; a full ACCC analysis is then performed to determine voltage constraints. The following voltage performance guidelines are used in accordance with the Transmission Owner local planning criteria.

SPP voltage criteria is applicable to all SPP facilities 69 kV and greater in the absence of more stringent criteria:

System Intact Contingency

0.95 – 1.05 per unit 0.90 – 1.05 per unit



Areas and specific buses having more-stringent voltage criteria:

Areas/Facilities System Intact Contingency AEPW – all buses

EMDE High Voltage 0.95 – 1.05 per unit 0.92 – 1.05 per unit WERE Low Voltage 0.95 – 1.05 per unit 0.93 – 1.05 per unit WERE High Voltage 0.95 – 1.05 per unit 0.95 – 1.05 per unit

TUCO 230 kV Bus #525830 0.925 – 1.05 per unit 0.925 – 1.05 per unit

Wolf Creek 345 kV Bus #532797 0.985 – 1.03 per unit 0.985 – 1.03 per unit

The constraints identified through the voltage scan are screened for the following for each interconnection request: 3% DF on the contingent element and 2% change in per unit voltage. In certain conditions, engineering judgement was used to determine whether or not a generator had impacts to voltage constraints.

Constraints and associated mitigations for each Interconnection Request are summarized in the CONSTRAINTS SUMMARY TAB of the SPP DISIS RESULTS WORKBOOK. Details are contained in the G-T tab and the G-V tab of the SPP DISIS RESULTS WORKBOOK. Cost allocation for the Cluster Scenario is found in ASSIGNED UPGRADE COSTS tab of the SPP DISIS RESULTS WORKBOOK.

LIMITED OPERATION Limited Operation results reflect the most limiting element. They are listed in the REQUESTS TAB of the SPP DISIS RESULTS WORKBOOK. While these results are based on the criteria listed in GIP 8.4.3, the Interconnection Customer may request additional scenarios for Limited Operation based on higher-queued Interconnection Requests not being placed in service.

SOLUTION PROCESS AND METHODOLOGY When conducting constraint analysis, solutions/mitigations are used to negate the effects of the identified constraints. In accordance with the previously stated criteria for which constraints are identified, the objective of a mitigation is to find the lowest cost upgrade to the system that maintains system reliability.



LOADFLOW SOLUTION PARAMETERS To perform a constraint analysis, PSS/E is used to bring the models to a convergent state. This is the process of using linear algebraic calculations to bring the system total mismatch to realistically possible.

Solve Parameters:

• Fixed Slope Decoupled Newton-Raphson

• Tap Adjustment – Stepping

• Switch Shunt Adjustments – Enable All

• Area Interchange Control – Tie Lines and Loads

• Adjust Phase Shift

• Adjust DC Taps

• VAR Limits – Apply Immediately

• Must Solve Within Three or Less Iterations

* SPP Reserve Group (all generation excluding Wind, Solar, and Hydro) is dispatched to make up for generation outage



DETERMINATION OF COST ALLOCATION FOR NETWORK UPGRADES Cost allocation of network upgrades for wind GIRs are determined using the spring model. Cost allocation of network upgrades of peaking units is determined using the summer peak model. A PSS®MUST sensitivity analysis is performed to determine the DF, a distribution factor with no contingency that each GIR had on each new upgrade. The impact each GIR had on each upgrade project is weighted by the size of each request. Finally, the costs due by each request for a particular project are then determined by allocating the portion of each request’s impact over the impact of all affecting requests.

For example, assume there are three GIRs: X, Y and Z, responsible for the costs of Upgrade Project 1. Given their respective power transfer distribution factors (PTDFs) for the project have been determined, the cost allocation for GIR X for Upgrade Project 1 is found by the following set of steps and formulas:

• Determine an impact factor on a given project for all responsible GI requests:

o Request X Impact Factor on Upgrade Project 1 = PTDF (%)(X) * MW(X) = X1

o Request Y Impact Factor on Upgrade Project 1 = PTDF (%)(Y) * MW(Y) = Y1

o Request Z Impact Factor on Upgrade Project 1 = PTDF (%)(Z) * MW(Z) = Z1

• Determine each request’s allocation of cost for that particular project:

• 𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅𝑅 𝑋𝑋′𝑅𝑅𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑠𝑅𝑅𝑠𝑠𝑅𝑅 1 𝐶𝐶𝑠𝑠𝑅𝑅𝑅𝑅 𝐴𝐴𝐴𝐴𝐴𝐴𝑠𝑠𝑠𝑠𝐴𝐴𝑅𝑅𝐴𝐴𝑠𝑠𝐴𝐴($) = 𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁𝑁 𝑈𝑈𝑈𝑈𝑈𝑈𝑁𝑁𝑈𝑈𝑈𝑈𝑁𝑁 𝑃𝑃𝑁𝑁𝑁𝑁𝑃𝑃𝑁𝑁𝑃𝑃𝑁𝑁 1 𝐶𝐶𝑁𝑁𝐶𝐶𝑁𝑁 ($)×𝑋𝑋1𝑋𝑋1+𝑌𝑌1+𝑍𝑍1

• Repeat previous for each responsible GIR for each project.

The cost allocation (+/- 30%) of each needed network upgrade is determined by the size of each request and its impact on the given project. This allows for the most efficient and reasonable mechanism for sharing the costs of upgrades. Costs assigned to each GIR are listed in the ASSIGNED UPGRADE COSTS tab of the SPP DISIS RESULTS WORKBOOK.



SPP DISIS RESULTS For each DISIS, power flow and dynamic stability results are provided in an Excel workbook; both are labeled and posted to SPP.org.

The DISIS Results Workbook provides a detailed summary of each interconnection request, assigned interconnection and shared network upgrade cost estimates and descriptions, previously allocated upgrades, and thermal and voltage violations meeting criteria for mitigation. Please use the tab summary to become familiar with how to analyze the workbook.

SPP DISIS RESULTS WORKBOOK TABS (POWERFLOW) The workbook contains worksheets providing the necessary data to analyze interconnection requests presented within the specific DISIS study cluster.

EXECUTIVE SUMMARY A summary of total MW amount included in the study, total cost for interconnection and models used for the study.

http://opsportal.spp.org/Studies/Gen



REVISION HISTORY Contains description of each report revision.

REVISION DETAILS Contains a further description of each report revision.



REQUESTS Contains summarized information for the current and prior queued interconnection requests (GEN numbers) and the pertinent information about each request included in this DISIS cluster study.

CONSTRAINT SUMMARY Contains all ERIS and NRIS constraints (non-converge, thermal and voltage) observed for single contingency (N-1) and multi-contingency (P1, P2, etc.) conditions and are summarized in conjunction with associated mitigations.



ASSIGNED UPGRADE COSTS

Cost allocated for Network Upgrades and Transmission Owner Interconnection Facilities.

UPGRADE SUMMARY Contains summarized information for the current and previously allocated upgrades and their associated details.



ALL THERMAL Details for thermal constraints for each Interconnection Request are contained here.

ALL VOLTAGE Details for voltage constraints for each Interconnection Request are contained here.



SHORT-CIRCUIT RATIO The short circuit ratio calculation in relation to each request.



STABILITY STUDY

STABILITY MODELS To simulate and analyze the variety of generation included in a study cluster, two categories of generating facilities are dispatched utilizing the regional groupings for a single scenario per group.

• High-Variable Energy Resource (HVER)

• Low-Variable Energy Resource (LVER)

Model Generator Dispatch

Facility in MDWG Models

Seasons Code

In Group Out Group

HVER LVER HVER LVER

Not included in MDWG

Winter/Summer

01, 02, 03, 04, 05

100% 100% 20% 100%

100% 100% 0% 0%

Existing in MDWG

Winter/Summer

100% N/A 20% N/A

100% N/A N/A N/A

The output of these requests is distributed across the host system (i.e SPP, MISO, or AECI) footprint by scaling existing low-variable generation, excluding nuclear and dispatched units, to maintain the host system energy balance and output of the system swing. Specific adjustments for sensitivities in a cluster group may be made in order to assess stability limits or specific scenarios.

Each generating facility is represented in the dynamic stability models as an equivalent generator dispatched at the applicable percentage of the requested service amount. The facility modeling includes explicit representation of equivalent GSU and main project transformer(s), with impedance data and power factor capability provided in the interconnection request. Equivalent collector system(s) and transmission lead line(s) impedances are also explicitly modeled for dynamic stability analysis.



STABILITY ANALYSIS

STABILITY FAULT EVENTS For all stability models developed, a transient stability analysis will be performed to determine generator unit response due to fault events on the system. The stability analysis includes new transmission reinforcements that were determined to be necessary by the power flow analysis. The following NERC TPL-001-4 planning standard fault event categories will be simulated in the stability analysis:

• P1-2: Three-phase transmission circuit fault with reclosure • P1-3: Three-phase transformer fault without reclosure • P4-2: Single-phase transmission circuit fault with delayed clearing without reclosure • P4-3: Single-phase transformer fault with delayed clearing without reclosure • P6-1: Pre-fault system adjustment of curtailment followed by three-phase

transmission circuit fault with reclosure • P6-2: Pre-fault system adjustment of curtailment followed by three-phase

transformer fault without reclosure The transient stability analysis will evaluate:

• System stability in response to fault events • Compliance of Current Queue and Prior Queue with FERC Order 661-A • Adherence to the SPP Disturbance Performance Requirements • Post event voltage recovery within the SPP voltage criteria

Fault events will include P1 events involving each network circuit segment connected within 3 levels of each Requests POI as well as P4 and P6 events involving each network circuit connected within 2 levels of each Requests POI. A network circuit is comprised of each segment of sectionalized single (or double) circuits from substations or buses to accommodate generation and radial load. Each level includes all substations on the remote end of all network circuits. (i.e. 0 levels away from a line tap POI includes substations with at last 3 connected circuits on either end of the tapped circuit) Additionally, P1, P4, and P6 events on regional or tie line facilities applicable to the study group will be evaluated.

P1 and P6 fault events will each be initially evaluated with a normal clearing of 19 cycle (16 cycle for 345kV) three-phase fault with reclose into the fault on both ends of the faulted circuit initiated 20 cycles following initial clearing. Fault events on transformer circuits are not evaluated with a reclose.



P4 fault events will be initially evaluated with a 16 cycle single line to ground (may be simulated as a three phase fault admittance that reduces the voltage to ~60% of steady-state voltage) with delayed clearing from a stuck breaker condition.

Each event should remove from service all elements that are expected to automatically disconnect for each event. Typically a single circuit (potentially including multiple buses and branches) for P1 and P6 events and multiple circuits sharing the stuck breaker for P4 events. Initial evaluation across the entire SPP system with these clearing times is a conservative study approach.

MITIGATIONS Mitigation of stability issues, not also observed as a steady-state issue, will evaluate reduced fault duration and removal of reclose from the fault definition. Actual equipment settings and capabilities may provide reduced clearing times.

Evaluation of reduced clearing times and removal of reclose may be used to identify and determine whether mitigation is provided by existing equipment and settings or may be provided by a Network Upgrade to fault interrupting equipment (i.e. breakers and relays).

LIMITED OPERATION Limited Operation stability analysis results, a quantification of the amount of interconnection capacity available to the Interconnection Customer without system instabilities prior to the in-service date of identified upgrades, is listed in the REQUESTS TAB of the SPP DISIS RESULTS WORKBOOK.

SHORT CIRCUIT ANALYSIS A short-circuit analysis was conducted for each interconnection request using modified versions of the MDWG models’ dynamic cases used in the stability analysis. The short circuit analysis assumes that all upgrades identified in the power flow analysis are in-service unless otherwise noted in the individual group short circuit study.

As sequence impedance data included in the stability models is not comprehensive, a preliminary short-circuit analysis was performed for this study and will be refined in the Interconnection Facilities Study with any additional required upgrades and cost assignment identified at that time.

𝑆𝑆𝐶𝐶𝑅𝑅𝑃𝑃𝑃𝑃𝑃𝑃 = 𝑆𝑆𝐶𝐶𝑆𝑆𝑆𝑆𝐴𝐴𝑃𝑃𝑃𝑃𝑃𝑃𝑆𝑆𝑀𝑀𝑉𝑉𝑉𝑉𝑉𝑉



SCRPOI – Short Circuit Ratio at the Point of Interconnection

SCMVAPOI – Short Circuit MVA at the Point of Interconnection

MWVER – MW value of the generator

SPP DISIS RESULTS WORKBOOK TABS (STABILITY AND SHORT CIRCUIT) The workbook contains worksheets providing the necessary data to analyze interconnection requests presented within the specific DISIS study cluster.

EXECUTIVE SUMMARY A summary of total MW amount included in the study, total cost for interconnection and models used for the study.

REVISION HISTORY Contains description of each report revision.

REQUESTS Contains summarized information for the current and prior queued interconnection requests (GEN numbers) and the pertinent information about each request included in this DISIS cluster study.

STABILITY ANALYSIS Contains all ERIS stability analysis constraints.

SENSITIVITY DISPATCH

Contains the listing of each unit dispatched for the evaluated sensitivity dispatches.

SHORT-CIRCUIT ANALYSIS The short circuit calculation at substations near each request.



AFFECTED SYSTEMS COORDINATION The following procedures are in place for coordination of affected systems.

Impacts on Associated Electric Cooperative Inc. (AECI) – For any observed violations of thermal overloads on AECI facilities, SPP will notify AECI SPP to evaluate the violations for impacts on its transmission system.

Impacts on Midcontinent Independent System Operator (MISO) – Per SPP’s agreement with MISO, MISO will be contacted and provided a list of interconnection requests that proceed to move forward into the interconnection facilities study queue. MISO will then evaluate the interconnection requests for impacts and will be in contact with affected interconnection customers. All potential impacts are available upon request.

Impacts on Minnkota Power Cooperative, Inc. (MPC) – MPC will be contacted and provided a list of interconnection requests that proceed to move forward into the interconnection facilities study queue. MPC will then evaluate the interconnection requests for impacts. All potential impacts are available upon request.

Impacts to other affected systems – For any observed violations of thermal overloads or voltage constraints, SPP will contact the owner of the facility for further information.

FIRST-TIER EXTERNAL AREAS FACILITIES 115 KV AND GREATER

Area System Intact Contingency EES-EAI LAGN EES

AMMO CLEC LAFA LEPA XEL MP

SMMPA GRE OTP

ALTW MEC MDU DPC ALTE

0.95 – 1.05 per unit 0.90 – 1.05 per unit

OTP-H (115kV+) 0.97 – 1.05 per unit 0.92 – 1.10 per unit SPC 0.95 – 1.05 per unit 0.95 – 1.05 per unit



RE-STUDY SPP shall notify the customer in writing if a re-study is required due to a higher-queued project withdrawing from the queue, a modification of a higher-queued project, or more than one GIR moving forward into the interconnection facility study phase. Any re-study cost will be borne by the interconnection customer. The customer is responsible for prepaying the cost of the re-study.

CURTAILMENT AND SYSTEM RELIABILITY DISIS report results do not guarantee operation for all periods of time. Although studies analyzed many of the most probable contingencies, they are not an all‐inclusive list and cannot account for every operational situation. It is likely that the customer(s) may be required to reduce their generation output to 0 MW, also known as curtailment, under certain system conditions to allow system operators to maintain the reliability of the transmission network.



FREQUENTLY ASKED QUESTIONS What does TC and BC mean?

TC stands for Transfer Case and is the aggregate of interconnection requests that are being studied in the current cluster. BC stands for Base Case and includes the prior queued generation.

Were cost estimates provided by Transmission Owners or SPP?

SPP requests feedback and cost estimates from Transmission Owners (TOs) for all assigned upgrades in the DISIS. All cost information submitted by TOs are incorporated into the study for accuracy. In the event that SPP does not receive a cost estimate, the standards developed by the Project Cost Working Group (PCWG) are used to help develop cost estimates.

Are alternative mitigations considered during the DISIS/Can Interconnection Customers provide their own solutions?

Alternate mitigations may be provided to GI staff throughout the study portion of the DISIS. Please note that alternate mitigations are not guaranteed to be analyzed or incorporated into the study. To ensure the best possibility of an alternate mitigation being analyzed, prior testing of the alternate mitigation should be conducted. Creating an automation file (Python or Response [.idv]) that includes the proposed mitigation should be created and sent with an explanation of the alternate mitigation.

How can an Interconnection Customer determine their Financial Security Requirement?

All ICs will receive an invoice for the Financial Security amount during the start of the Decision Point. If an IC did not receive an invoice, please send an email to [email protected] to request a copy. The Financial Security amount can also be calculated by “first determining the cost allocation factor pursuant to Section 4.2.2 of the GIP applicable to an Interconnection Request for an upgrade assigned to that same Interconnection Request, and multiplying the cost allocation factor by itself and then by the total estimated cost of the upgrade; then summing the resulting products for every upgrade allocated to an Interconnection Request”. Please refer to Attachment V, Section 8.5.1 of the SPP OATT.

What is a Contingent Upgrade and why is the Allocated Cost $0?

A Contingent Upgrade is a Network Upgrade that ICs are dependent upon for their request(s). The IC is not assigned any cost for these upgrades as the costs were previously allocated through other SPP studies or processes. However, the IC is dependent on the energization date of this upgrade for service.



Does dropping NRIS during DP1 reduce an Interconnection Customers Financial Security?

Dropping NRIS during DP1 will not reduce the Financial Security 2 (FS2) requirement for DP1. An IC is still obligated to pay the FS2 requirement for NRIS if their request was studied as NRIS during Phase 1 of the DISIS. Any change from NRIS to ERIS will take place in Phase 2 of the study and those associated costs will be collected during DP2.

What are the financial risks for each Decision Point?

Refer to Attachment V, Section 8.14 of the SPP OATT for refund eligibility throughout the three stage process and/or ‘New Three Stage Interconnection Process’ that outlines the financial risks at each decision point. See ‘Helpful Links’ below.

Is there a Decision Point extension if cost allocation changes?

If cost allocation changes and SPP reposts a DISIS report, then the Decision Point will be extended by 10 business days. Refer to Attachment V, Section 8.5.1 for the specific criteria.

How are the Business Days determined for the Decision Point windows?

The Tariff describes a “Business Day” in accordance with Federal Reserve Holidays.

Does the Interconnection Customer have to provide a revised Appendix 3 during DP1?

All customers will need to provide a revised Appendix 3 with Attachments A, B, and C. Since the ICs in the DISIS-2017-001 cluster entered the queue under a different process, paperwork will need to be updated to reflect the new three stage process.

How can an Interconnection Customer determine estimated in-service dates for Contingent Upgrades?

The Contingent Upgrades in the DISIS-2017-001 report have lead times based on the in-service date from the latest SPP Quarterly Project Tracking Reports. This report shows the latest in-service date for all active SPP projects and upgrades.



Who does the Interconnection Customer contact to set up a meeting or ask further questions?

For meeting request or questions related to the DISIS study, please email Daniel Clark, Caitlin Shank and/or GI Studies

Daniel Clark – [email protected]

Caitlin Shank – [email protected]

Tariff Inquires

GI Studies – [email protected]

Technical Inquires

DISIS Engineers & Analysis – [email protected]

REFERENCE DOCUMENTS The following reference materials are available at www.spp.org: SPP Open Access Transmission Tariff

Generator Interconnection Procedures (Attachment V) SPP Business Practices

7250 Generator Interconnection Service 7300 Guideline for Clarifying Application of the SPP Generator Interconnection Procedures 7350 Generator Interconnection Modeling of Variable Energy Resources 7400 Interconnection Service for Energy Storage Resources

Seams Agreements AECI ERCOT MISO Peak Saskatchewan Power SWPA TVA

SPP-MISO JOA SPP-AECI JOA SPP Disturbance Performance Requirements SPP Quarterly Project Tracking Report Request Management System New Three Stage Interconnection Process



http://www.spp.org/

https://spp.etariff.biz:8443/viewer/viewer.aspx

https://www.spp.org/documents/61922/20200330_spp-miso%20joa.pdf

https://www.spp.org/documents/8373/aeci%20spp%20joa%20final%20signed%2008-12-08.pdf

https://www.spp.org/documents/28859/spp%20disturbance%20performance%20requirements%20(twg%20approved).pdf

https://www.spp.org/documents/28859/spp%20disturbance%20performance%20requirements%20(twg%20approved).pdf

https://spp.org/spp-documents-filings/?id=18641

https://spprms.issuetrak.com/login.asp

http://opsportal.spp.org/documents/studies/SPP%20Three%20Stage%20Process%20Overview%202019-05-31.pdf



GLOSSARY OF TERMS Term Definition BC Base Case DF Distribution Factor DP Decision Point ERIS Energy Resource Interconnection Service ESR Energy Storage Resource EHV Extra-High Voltage (300kV or higher) FCITC First Contingency Incremental Transfer Capability FERC Federal Energy Regulatory Commission FS Financial Security GI Generator Interconnection GIA Generator Interconnection Agreement GIP Generator Interconnection Procedures GIR Generator Interconnection Request GSU Generator Step-Up HV High Voltage (300kV or lower) HVER High Variable Energy Resource (Wind/Solar) IC Interconnection Customer IFS Interconnection Facilities Study ITP Integrated Transmission Planning LVER Low Variable Energy Resource (Gas/Coal) MUST Managing and Utilizing System Transmission NERC North American Electric Reliability Corporation NRIS Network Resource Interconnection Service NTC Notice to Construct OATT Open Access Transmission Tariff PCWG Project Cost Working Group POI Point of Interconnection PSS/E Power System Simulator for Engineering PTDF Power Transfer Distribution Factor RMS Request Management System SPP Southwest Power Pool TC Transfer Case TO Transmission Owner TPL Transmission System Planning Performance

Requirement VER Variable Energy Resource

definitive interconnection system impact study manual

Documents