Planning Methodology and Assumptions
Overview
These sections describe the process we used to perform a network assessment of the ATC transmission system. The description includes study assumptions, methods we used to analyze our transmission network for planning criteria limitations, and how we shared results for the 2024 10-Year Assessment. Economic, regional, interconnections and asset management planning processes are covered at other locations on the ATC 10-Year Assessment website.
As part of the network assessment, ATC conducted power flow analyses to identify problems or constraints on the transmission system. The power flow models are updated with the latest assumptions. The analyses evaluated the merits of potential reinforcements to address the system limitations that were identified. ATC met with stakeholders to discuss assumptions and results. ATC’s network assessment process is summarized in Figure 1.
Figure 1: 10-Year Assessment Process
Stakeholder engagement process
ATC has developed a stakeholder engagement process that we use to obtain stakeholder input for developing our study assumptions, needs and solutions. More discussion of the process can be found on the stakeholder engagement process page of the website. Through this process we also ensure coordination of ATC’s potential projects with the MISO Transmission Expansion Plan (MTEP) process.
Analyses introduction
Included in the following sections is a discussion of assumptions and study methods used for the years ATC simulated to satisfy the near-term (1 – 5 year) and long-term (5 year and beyond) transmission planning horizon requirements as required by North American Electric Reliability Corporation (NERC) transmission system assessment standards. Also included is discussion of how ATC built each of the models used in this 10-Year Assessment. Discussion items include topics such as load forecasting, reinforcements and new generation to include in models, system load levels, import levels, and system bias scenarios.
During the network assessment of our transmission system, we performed simulations on a variety of models. ATC not only uses these models to identify where constraints or system limitations may exist, we also use these models to test the robustness of potential system reinforcements. Where system limitations exist, they were identified for NERC Categories P0 through P7 contingencies using the ATC Transmission System Planning Criteria.
The system performance analyses represented in this 10-Year Assessment includes steady state power flow analyses and dynamic stability simulations. Multiple outage impacts, economic planning evaluations, generator interconnection impacts, distribution interconnection impacts, asset renewal plans and short circuit study results were also gathered to complete the assessment.
Network assessment methodology
ATC’s 2024 10-Year Assessment provides results from planning activities and analyses of the ATC transmission facilities’ performance. These activities and analyses identify transmission system performance improvement needs and potential projects able to address those needs.
Since ATC’s founding in 2001, we have engaged in open and collaborative efforts to share information and solicit input on our plans. We strive to make our planning efforts transparent and available to the public, believing the transparency about proposals for needed facilities will enable more understanding and acceptance by communities that stand to benefit from them. The federal government has taken additional steps to ensure that transmission-owning utilities have produced and shared planning information with the public and local stakeholders. The Attachment FF-ATCLLC in the MISO Tariff’s Attachment FF describes ATC’s open planning processes.
The information in this report provides further foundation for continued public discussions of the transmission planning process, identifies transmission needs and limitations, identifies possible resolutions to those needs, and discusses coordination with other public infrastructure planning processes.
Computer simulation model years for the 2024 network assessment analyses were selected in order to meet NERC requirements. Specifically, for the steady-state assessment, the years 2025 and 2029 were selected to meet the near-term transmission planning horizon (1-5 years). The year 2034 was selected to meet the long-term transmission planning horizon (beyond 5 years). This led to a range of system conditions and study years developed and analyzed for the 2024 10-Year Assessment.
Once ATC received load forecasts from our customers, we performed a preliminary steady-state assessment to help determine project submittals to the next MISO MTEP cycle. This preliminary assessment included applying no-load-loss-allowed contingencies to 5- and 10-year-out summer peak models from the previous year’s assessment. No-load-loss-allowed contingency categories are those where the NERC TPL-001 standard does not allow interruption of firm transmission service or loss of non-consequential load as a solution to Bulk Electric System (BES) limitations. ATC also applies similar contingency categories to its non-BES facilities.
Final assessment steady-state summer peak-load models were then created for 2025, 2029 and 2034. Steady-state shoulder load models were created for years 2029 and 2034. Steady-state minimum load models were created for years 2025 and 2029. In order to address uncertainty in reactive power capability and preserve some margin for the ATC area, an additional model was created for each model above. For each of the additional models, the maximum lagging and leading reactive power capabilities were reduced by 10 percent for appropriate generators within the ATC footprint. These reduced reactive capability models were used for both intact system and contingency analyses.
Planning criteria-driven needs were determined by identifying facilities whose normal or emergency limits are exceeded. The limits used are identified in the ATC Transmission System Planning Criteria in effect at the time of these studies.
This 10-Year Assessment was developed in a chronological fashion. It started by including only planned transmission changes expected to be in service by June 2025 in the 2025 model, as listed in the Table PF-1. Those projects and projects under construction, or with an application filed to construct, or with an application being prepared were included in the 2029 and 2034 models as appropriate based on projected in service dates (See Table PF-1, Table PF-2 and Table PF-3). Once needs were reconfirmed or identified and solutions were reconfirmed or identified, then solutions were added to the models to confirm limitations are appropriately addressed.
Load forecast
The 2023 Load forecast feeds into the 2024 Ten Year Assessment. In 2023, customer load forecasts were gathered from ATC customers, at least through the year 2033 (in most cases, through the year 2039).
Steady-state summer peak models were built using our customers 50/50 load forecast projections as a starting point, meaning that there is a 50 percent chance that the load level will either fall below or exceed the customer projection. The forecasts were compared to historic data and previous load forecasts to check validity and consistency. Once questions were resolved with the customer, the final forecast information was sent back to the customer as confirmation. Then the data was incorporated into our models.
Some customers may not provide a load forecast for the 2034 study year. In these instances, the forecast for 2034 was obtained by growing their load by using a linear growth rate calculated over the last three years of the forecasts provided by the customer. Load power factors and non-scalable loads were held at levels in the last forecast year provided.
In the event ATC or MISO planning processes required a 15th-year load projection, a similar methodology was utilized to obtain a projection for 2039 if not provided by the customer. Customer-provided forecasts were extended by growing their load by using a linear annual growth rate calculated over the last three years of the customer’s forecast. Load power factors and non-scalable loads were held at levels in the last forecast year provided.
ATC summer peak total load projections (MW)
| Year | Load (MW) | Study period compounded growth rate |
|---|---|---|
| 2023 | 12,848 | Not applicable |
| 2033 | 12,988 | 0.11% (2023-2033) |
ATC worked with the distribution companies as much as possible to confirm forecast variations from past historic and past forecast trends.
Model building
Assumptions common to all steady state models
The following subsections contain assumptions that are common to all steady state models studied in the 10-Year Assessment.
- New generation
- Generation retirements
- Cutoff dates for model modifications
- Generation project schedule
- Generation outside of the system
- Generation dispatch
- Line and equipment ratings
- Project criteria
- Normal (Category P0) conditions
- Planned maintenance and construction outages
- Protection systems
- Control devices
New generation
There have been multiple generation projects proposed within the ATC service territory. Many of these proposed projects have interconnection studies completed. Some transmission facilities have proceeded to or through the licensing phase and some are under construction. There are also proposed generation projects that have dropped out of the MISO generation queue (refer to Generation Interconnections), adding uncertainty to the transmission planning process. Given this uncertainty we adopted a criterion that only generators with Federal Energy Regulatory Commission (FERC) approved interconnection agreements will be included in the planning models.
Generation retirements
Generators connected to the ATC transmission system may be retired or mothballed. Our criteria to determine when generators should no longer be available for dispatch in our 10-Year Assessment models requires a completed MISO Attachment Y study. When this is true the generator will be disconnected in the appropriate power flow study models. In addition, ATC sends an annual letter to each generation owner. Generating companies are asked to identify generator retirements or mothballing that should be included in ATC’s planning horizon. Generators identified as such by the customer will be modeled off-line in the relevant models.
Using the disconnection criteria above, the following generators were assumed out of service in the 2024 10-Year Assessment.
ATC assumed the following generators were to be out of service
| Plant Name | Zone | Installed capacity (MW) |
|---|---|---|
| Columbia #1 | 3 | 585 |
| Columbia #2 | 3 | 585 |
| Edgewater #5 | 4 | 420.5 |
| Oak Creek #5 | 5 | 265 |
| Oak Creek #6 | 5 | 249 |
| Oak Creek #7 | 5 | 302 |
| Oak Creek #8 | 5 | 310 |
| Fitchburg #1 | 3 | 16 |
| Fitchburg #2 | 3 | 16.2 |
| Nine Springs #1 | 3 | 14.1 |
| Sycamore #1 | 3 | 12.6 |
| Sycamore #2 | 3 | 18.1 |
| Net decrease | 2793.5 |
Cutoff dates for model modifications
- 2025 models – Dec. 12, 2023
- 2029 models – Dec. 12, 2023
- 2034 models – Dec. 12, 2023
Generation projects schedule
To maintain the schedule needed to complete this Assessment, the models were developed during late 2023. Only those generation projects that qualified to be included in our planning models, as of the various cutoff dates, were included in the Assessment models. For generation projects not planned to be in service by June 2024 the criterion above resulted in the following proposed generation projects being included in the applicable power flow models.
Proposed generation projects being included in applicable power flow models
| Plant Name | Zone | Capacity increase (MW) | Dispatched increase (MW) | Assumed in-service |
|---|---|---|---|---|
| Beaver Dam Solar (J1003) | 3 | 51.0 | 25.5** | Jan 2024 |
| Grant County Solar (J947) | 3 | 205.0 | 102.5** | Feb 2024 |
| Waupaca Energy Storage | 1 | 2.5 | 0 | Mar 2024 |
| Darien Solar (J850) | 3 | 250.0 | 125.0** | Aug 2024 |
| Paris Solar (J878) | 5 | 200.0 | 100.0** | Dec 2024 |
| Badger State Solar (J818) | 3 | 149.0 | 74.5** | Mar 2025 |
| Edgewater Energy Storage (R1014) | 4 | 100 | 100 | May 2025 |
| Marquette County Solar (J1251) | 2 | 100 | 50** | Jun 2025 |
| Koshkonong Solar (J1214) | 3 | 300 | 75** | Oct 2025 |
| Koshkonong Energy Storage (J1326) | 3 | 75 | 75 | Nov 2025 |
| White Tail Wind (J1374) | 3 | 67.2 | 12.2** | Nov 2025 |
| Dawn Harvest Solar (J1460) | 3 | 147.4 | 73.7** | Dec 2025 |
| Dawn Harvest Energy Storage (J1460) | 3 | 56.7 | 56.7 | Dec 2025 |
| Paris Energy Storage (J1316) | 5 | 50 | 50 | Dec 2025 |
| Paris Energy Storage (S1005) | 5 | 60.4 | 60.4 | Dec 2025 |
| Great Dane Solar (J1410) | 3 | 300 | 150** | Jun 2026 |
| Great Dane Energy Storage (J1411) | 3 | 75 | 75 | Jun 2026 |
| Two Creeks Energy Storage (J1101) | 4 | 20.0 | 20.0 | Aug 2026 |
| Badger Hollow Wind (J1483) | 3 | 110 | 20.1* | Sept 2026 |
| Rock County Solar (J1377) | 3 | 98.5 | 49.3** | Nov 2026 |
| Silver Maple Solar (J1253) | 4 | 101 | 50.5** | Mar 2027 |
| Edgewater Energy Storage (R1014) | 4 | 300 | 300 | May 2028 |
| Net increase by Dec 2024 | 708.5 | 353.0 | ||
| Net increase 2025-2034 | 2110.2 | 1292.4 |
**solar farm dispatched increase listed is 50% of total installed capacity
A more comprehensive discussion of proposed generation is provided in Generation Interconnections.
Generation Outside of the ATC system and interchange
The model for the system external to ATC was taken from the most appropriate model included in the 2023 MMWG Series models. The external system interchange was adjusted from the 2023 MMWG Series models to match the latest ATC members’ firm interchange.
Generation dispatch
Balancing Authority area generation was dispatched based on economic dispatch for that Balancing Authority, except for in the Minimum Load models.
Line and equipment ratings
We revised line and equipment ratings based on updates to our Substation Equipment and Line Database (SELD).
Project criteria
The steady state models built for the 2024 10-Year Assessment include revised system topology based on projects that were placed in service by the model year, or that were anticipated to be placed in service by June 15 of that year. Refer to Table PF-1, Table PF-2, and Table PF-3 for projects that were included in the analyses.
Normal (Category P0) conditions
The power flow models for the 10-Year Assessment are built to include established (pre-contingency) operating procedures to assess system performance under the normal (P0) conditions as required in the TPL-001 Reliability Standard. The relevant operating procedures are generally standing operating procedures that apply for the planning horizon. These procedures include, but are not limited to, normal open points and switched capacitor banks. Normal open points are assumed to remain normally open in the base cases. Changes in the status of normally open points are provided by the system planners that participate in the decision to change the status of a normally open point. Switched non-mobile capacitor banks are assumed to be available for use by the system operators, except in the case of planned outages. This availability is represented by modeling these capacitor banks in the discrete adjustment voltage regulating mode. Mobile capacitor banks are modeled in the base case when there is a known date and location in the planning horizon during which the mobile capacitor bank is planned to be in service.
Planned maintenance and construction outages
The power flow models for the 10-Year Assessment are built to include specific, long-duration maintenance and construction outages that are expected to occur in the planning horizon. The outages modeled are typically conditions that are expected to last for a period of six months or more, coinciding with the season being modeled. The modeled outages are obtained from ATC’s Transmission Outage Application software.
Protection systems
All appropriate existing and planned protection systems, including any backup or redundant systems that would be applicable to a given contingency were simulated in the studies and analyses. In the steady state simulations, we simulated event-based contingencies that reflect all elements that would be removed by the existing or planned protection system. Dynamic studies simulate protection system operating times, associated breaker clearing times and backup device tripping functionality.
Control devices
All appropriate existing and planned control devices that would be applicable to a given contingency were enabled in the studies and analyses. These control devices include transformer automatic tap changers, capacitor bank automatic controls, SVCs and back-to-back HVDC (VSC) power flow controllers.
Specific steady state power flow models
Project deficient models
The power flow models built for the 10-Year Assessment are for system analyses. For some project deficient models, projects were purposely left out of these models in order to verify system problems and determine which problems worsen over time. We have taken the approach of evaluating subsequent summer peak seasons in each of our annual 10-Year Assessments to determine the immediacy of needs identified, hence providing a means of prioritization.
The 2025, 2029 and 2034 steady state project deficient summer peak models were developed to evaluate needs, verify 10-Year Assessment findings from previous years, and confirm that previously identified needs will increase over time. The 2024 10-Year Assessment project deficient models reflect years sufficiently forward in time to determine the need for and assess the performance of larger-scale, long lead-time projects (345 kV lines, for example) that could be needed and expected to be in service in that time frame.
All project models
After the initial analyses portion of the 10-Year Assessment was completed, “All Project” models were built. The “All Project” models were built with all planned and proposed projects included as well as the majority of the provisional projects. The provisional projects included are needed to address system limitations found in the ten–year planning horizon that were not addressed by proposed and planned projects. These models are more indicative of the expected system configurations and performance for the three study years than “Project Deficient” models. The “All Project” models are more likely to reflect the projects ATC includes in regional models. As part of the 10-Year Assessment, contingency analyses are performed on each of the “All Project” models. These analyses will verify whether the planned, proposed, and provisional projects included in the models will resolve issues revealed in the 10-Year Assessment process and will not introduce any new limitations.
Load, dispatch and interchange profiles
Models of expected load range
Summer Peak (2025, 2029 and 2034)
- These models are used to support regional model building.
- These models are also used to create models with Generator reactive capability QMax/QMin reduced to 90% for the 10-Year Assessment.
- We used interconnection point load forecasts provided by various distribution companies in 2023 for both real and reactive power components of load. Please refer to the Load Forecast section for further details.
- The external system interchange for the 2025 peak model was adjusted from the 2023 MMWG Series 2025 peak interchange to match the latest ATC members’ firm interchange. The external system interchange for the 2029 peak model was adjusted from the 2023 MMWG series 2028 summer peak interchange to match the latest ATC members’ firm interchange. The external system interchange for the 2034 peak model was adjusted from the 2023 MMWG series 2033 summer peak interchange to match the latest ATC members’ firm interchange.
- Mackinac VSC set to 5 MW north to south.
- These models are used to support regional model building.
- These models are also used to create models with Generator reactive capability QMax and QMin reduced to 90% for the 10-Year Assessment.
Shoulder Models (2029 and 2034)
- We started with the summer peak interconnection point load forecasts provided by various distribution companies in 2023.
- To develop shoulder loads, keeping non-scalable loads at LDC-provided shoulder load levels, scalable loads in Zone 2, northern Zone 4, and the remainder of the ATC system were reduced proportionally to attain the following shoulder load levels. The overall Zone 2 load was modeled at 90% of summer peak, northern Zone 4 was modeled at 80% of summer peak, and the remainder of the ATC system load level was modeled at 70% of summer peak. These load levels were chosen for the shoulder models based on historical data to reflect the higher load levels when maintenance may need to occur. However, it is recognized that loads at individual points will vary under real-time shoulder conditions.
- The external system interchange for the 2029 shoulder model was adjusted from the 2023 MMWG Series 2028 shoulder to match latest ATC members’ firm interchange. The external system interchange for the 2034 shoulder model was adjusted from the 2023 MMWG series 2028 summer shoulder peak interchange to match latest ATC members’ firm interchange.
- Mackinac VSC set to 5 MW north to south.
- These models are used to support regional model building.
- These models are also used to create models with Generator reactive capability Qmax and QMin reduced to 90% for the 10-Year Assessment.
Models of load sensitivities
Minimum Load Scenario (2025 and 2029)
- ATC Load: 5,388 MW and 5,399 MW, respectively.
- 2023 vintage load forecast collection, with non-conforming off-peak loads maintained at their defined values and the scalable loads reduced to obtain an overall 40% of Peak load.
- Increased power factor of loads with respect to peak load based on historical data.
- Total ATC Generation: 5,177 MW and 5390 MW, respectively.
- Includes all planned and proposed projects to be in-service by 6/15/2025 and 6/15/2029, respectively.
- Interchange: Firm interchange only as of 12/12/2023.
- Dispatch: ATC-wide Merit order as of 12/12/2023.
- Mackinac VSC set to 5 MW north to south.
- These models are also used to create models with Generator reactive capability Qmax and QMin reduced to 90% for the 10-Year Assessment.
Dynamic stability assessment models
The process for performing dynamic stability assessments includes three types of analyses: (1) the annual review of existing resources, resources with signed GIAs, and synchronous generator angular stability, (2) specific generator interconnection study reports, and (3) specific voltage stability assessments.
Annual review of existing resources, resources with signed GIAs, and synchronous generator angular stability
The base cases for the annual review of existing generation angular stability for this compliance monitoring period are a 2029 light load model with high generation in ATC Planning Zones 1, 2 and 4, a 2029 light load model with high generation in ATC Planning Zones 3 and 5, a 2029 peak load model with high generation in ATC Planning Zones 1, 2 and 4, and a 2029 peak load model with high generation in ATC Planning Zones 3 and 5. All of the base cases were created using the MISO MTEP 2024 series 2029 models.
Additional ATC updates are applied to the base cases to create study-specific models including changes to topology, load, and generation. This includes:
- The latest generators with signed GIAs as of the kickoff of the next study cycle,
- Additional MTEP Appendix A projects submitted to MISO since MTEP creation,
- The most recent ATC Load Forecast
- The latest summer ratings,
- The latest impedances.
Generally, for positive sequence simulation, all BES and select non-BES generators in ATC Zones 1, 2, 3, 4 and 5 are assessed for system dynamic stability. PSCAD simulations may also be conducted, but these studies are usually reserved for Inverter Based-Resources.
The positive sequence study evaluates dynamic stability for faults near generation stations. For each study generator, the ATC Planning Rationale PLG-RTNL-0005 is used to determine the most relevant faults. The dynamic stability and ride through of all generators is monitored. While this study is not designed to be an exhaustive dynamic voltage study for all ATC buses, the study generator Point of Interconnection voltages, active and reactive power are also monitored. An associated study report is written to discuss all assumptions, methodology, and results. It will document all unacceptable stability and transient voltage recovery impacts of the study generators.
Specific generator interconnection study reports
The base cases for specific generator interconnect study reports are described in detail in the associated study report.
Specific voltage stability assessments
The base cases for specific voltage stability assessments are described in detail within the associated study report
Short-Circuit Assessment Models
The base case model for the annual short-circuit assessment was the ATC Near-Term Planning Horizon CAPE (fault study related software) scenario. On an annual basis, the current-interrupting capability for existing ATC BES circuit breakers and circuit switchers and the near-term planning horizon transmission modifications are modeled in CAPE. The current-interrupting capability is compared to the expected short circuit fault current using 3-phase and line-to-ground short circuit fault simulations. Mitigation plans are developed where short circuit fault current sufficiently exceeds the device current-interrupting capability. For our studies of new interconnections, the base model is an as-built CAPE scenario. Interconnection studies are used to modify the as-built CAPE base case to include the new interconnected facilities and any proposed transmission system modifications.
Preliminary Needs and Solution Development
Steady State Project-Deficient Needs Assessment
System Intact and No Load Loss Allowed Contingency Simulations
ATC performed system intact and no-load loss allowed contingency simulations on the 2025, 2029 and 2034 models. No load loss allowed contingency simulations included all contingencies that do not allow interruption of firm transmission service or non-consequential load loss, as described in the NERC TPL-001 standard, as well as P1 and P2-1 contingencies at the 69-kV level. We ran these simulations for all the steady state models described above.
Comparison of Results vs Planning Criteria
The models described above are analyzed and compared to the ATC Transmission System Planning Criteria. Limits that approach or exceed our criteria are then listed in a limitations table.
Reconciliation of Significant Changes to Power Flow Results
To reconcile changes in power flow results between 10-Year Assessments, zone planners ran data comparisons to determine if limitations identified in prior 10-Year Assessments have become more severe, less severe, or have been mitigated. Steps were taken to verify topology and other model changes to ensure that the results are consistent with all the available information.
Preliminary Solution Development
New Limitation
If a new limitation is found in the initial screening, the zone planner takes steps to ensure that the limitation is valid, including verification of the power flow model. If the new limitation is within the current five-year time frame, the zone planner will then check for potential delay ability, including investigation of operating guides or other mitigation measures.
Cost estimates are developed for one or more solution options that effectively address the identified limitations. After cost information has been obtained, the zone planner initiates the project development process by completing the project request to create a provisional project. Finally, the project request is processed through ATC’s project approval process.
Repeat Limitation
If a previously identified limitation is found in our initial screening, the zone planner will re-verify that existing solution options address that limitation. If an in-service date or scope change is warranted, updated cost estimates are developed. The project request is then updated with the revised in-service date, cost, scope and/or justification. The updated project request is then resubmitted through ATC’s project approval process.
If a previously identified limitation was not found in our screening, the zone planner will confirm the need did not appear in this 10-Year Assessment or any other parallel studies. If the need does not appear in three annual 10-Year Assessments the potential solution will then be removed from the project list.
Unspecified-Network Capital Forecast Process
The Unspecified-Network capital forecast consists of potential solutions that are likely to shift into the 10-year time frame, but the exact need, solution, and schedule cannot be determined at this time. Unspecified-Network dollars may be needed for the following reasons:
- Changing load forecasts.
- Changes in generation and distribution interconnection projects.
- Changes in public policy requirements.
- Additional projects that are driven by economic benefits or multiple outage impacts.
Dollars are set aside in ATC’s capital forecast to address Unspecified-Network need drivers. ATC begins to identify Unspecified-Network dollars with internal discussions to determine how to best serve our customers’ local and regional needs. In these discussions, we determine which potential solutions are more likely to be built within the 10-year Assessment period should events happen that cannot currently be accurately predicted. The cost and potential benefits of the solutions are discussed, vetted, and approved by our executives. After internal consensus is reached, the ATC capital forecast is updated to include dollars for these Unspecified-Network need drivers. Project requests are not initiated for these Unspecified-Network dollars until specific needs are confirmed.
All Projects Assessment
After the 10-Year Assessment project deficient analysis is completed, models are built that include all planned, proposed, as well as the majority of the provisional projects. The provisional projects included are needed to address system limitations found in the ten-year planning horizon that were not addressed by proposed and planned projects. These models are called “All Projects” models and are more indicative of the expected system configurations for the 2025, 2029 and 2034 study years.
As part of the 10-Year Assessment, contingency analysis is performed on each of the “All Projects” models. The contingency analysis includes all no-load-loss-allowed contingencies, as described in the Steady State Project-Deficient Needs Assessment section. The analysis will verify whether the planned, proposed, and provisional projects included in the models will resolve issues revealed in the 10-Year Assessment process.
This “All Projects” analysis assesses the list of reinforcements that are beginning to define our reinforcement plan. The following are three important questions regarding this plan:
- How do all the reinforcements perform together?
- Does applying a solution create a problem that was not seen before?
- Are some solutions redundant when all the solutions are applied to the system?
We address the first two questions in our 10-Year Assessment. “All Project” models built for years 2025, 2029 and 2034 include projects identified in the project tables for this 10-Year Assessment observing specific in-service dates. As required by NERC TPL-001, Table 1, no load loss allowed contingency analysis was performed on these models, including selected contingencies in neighboring systems. This analysis showed that no additional reinforcements were needed. The third question is addressed during our detailed project development process.
Other Studies
Multiple Outage Review and Analysis
ATC performed a steady-state assessment for the applicable multiple-element contingency categories of planning events and extreme events identified in the NERC TPL-001 Reliability Standard. These evaluations may be performed on an annual schedule, a rolling periodic schedule, or for specific interconnection studies.
Category P “Load-Loss-Allowed” contingencies
ATC and MISO collaborate on an annual comprehensive analysis of Category P load loss allowed contingencies that are inside of the ATC system. The load loss allowed contingencies refer to all the planning events in NERC TPL-001, Table 1, that allow interruption of Firm Transmission Service and Non-Consequential Load Loss.
For base case models, to perform the assessment of Category P load loss allowed contingencies that are outside of the ATC system, ATC and MISO collaborate on an annual reliability planning assessment of MISO’s MTEP study that focus on ATC’s footprint. MISO’s assessment includes all the systems adjacent to the ATC system. This allows ATC to identify potential performance deficiencies inside of the ATC system due to these external contingencies and develop potential mitigation to address deficiencies.
For sensitivity case models, to perform the assessment of Category P load loss allowed contingencies that are both inside and outside of the ATC system, ATC also uses the annual reliability Planning Assessments of MISO. This allows ATC to identify potential performance deficiencies inside of the ATC system due to these internal and external contingencies and develop potential mitigation to address deficiencies.
Extreme event contingencies
Generally, for a comprehensive assessment of extreme event contingencies, ATC uses the annual reliability Planning Assessments of MISO to identify the consequences and adverse impacts to the ATC system.
System stability review and analysis
ATC generally investigates three types of system stability: steady state voltage stability, dynamic voltage stability, and dynamic angular (e.g., generator) stability.
The specific system performance criteria that are used to assess the transmission system for each type of system stability are given in the ATC Transmission System Planning Criteria.
Steady state voltage stability
The steady state voltage stability analysis (e.g., P-V Curve simulation) is performed on a specific area of the ATC system when steady state analysis indicates areas of very low voltage or potential voltage collapse (non-convergent power flow simulations) for NERC TPL-001 reliability standard contingencies in the near- or long-term planning horizons. If general steady state analyses identify areas of weakness indicative of voltage instability, further examination of system characteristics and, possibly, more detailed analysis will be performed.
Dynamic voltage stability
The dynamic voltage stability analysis is performed on a specific area of the ATC system when steady state analysis indicates areas of very low voltage or potential voltage collapse (non-convergent power flow simulations) for NERC TPL-001 reliability standard contingencies in the near- or long-term planning horizons. Dynamic voltage stability analysis can reveal results where the voltage at some buses will collapse and not recover to the acceptable values found in steady state analysis. Steady state analysis assumes that the system “rides through” the dynamic recovery period.
Dynamic voltage stability analysis is assessed for any new or revised generation interconnection facilities before they are placed in service.
When dynamic analysis is performed, very large loads may be modeled with specific dynamic models and the remaining loads are modeled using lumped dynamic load models that depend on the percentage of industrial, commercial, and residential load at each distribution load interconnection point.
Dynamic angular (generator stability)
The dynamic angular stability of all BES generation facilities in the ATC system is assessed annually. In addition, dynamic angular stability is assessed for any new generation facility before it is placed in service.
All BES generation facilities (those with a total net output above 75 MVA and associated transmission lines operating above 100 kV or single generating units above 20 MVA and associated transmission lines operating above 100 kV) are included in the system angular stability assessment. Select non-BES generation facilities may also be screened for this assessment. The assessment considers applicable simulation requirements and performance requirements in the NERC TPL-001 reliability standard, as well as the ATC dynamic performance criteria.
ATC observes a half-cycle margin for tested generator data and a one-cycle margin for planned generator data. This margin is added to the clearing times that are received from protection.
Inverter-Based Resource stability
The dynamic stability of new Inverter-Based Resources is studied with PSCAD during the interconnection process and BES Inverter-Based Resources are restudied on a rolling 5-year rotational window with PSCAD as part of the 10-Year Assessment. The rolling five-year study process for the 10-Year Assessment PSCAD process only reviews resources that have not been studied for the last 5 years as part of another PSCAD study process, including MISO DPP, Material Modification process, or Operational PSCAD Studies. This five-year date is measured from the finalization of the last performed study. ATC maintains a PSCAD 10-Year Assessment Cycle schedule to track these dates. Note only BES generation units are assessed in this rotational review (i.e., DER, non-BES units, and FACTS devices are not specifically included).
Any instability found in these studies will be examined in future PSCAD studies. If an instability is found in the 10-Year Assessment stability analysis in TSAT or PSS/E, then that fault will be restudied in the next 10-Year Assessment or Operational PSCAD study to confirm its accuracy.
Documentation
Writing/approval processes
The 10-Year Assessment is written and developed by several contributors. The following steps are performed in order to ensure cohesive, consistent, non-CEII information is posted publicly.
- Requests are made for the latest financial, environmental, demographics, asset renewal, and economics information from other ATC departments.
- Drafts of text, figures, and tables are compiled for peer review.
- A summary presentation of 10-Year Assessment information is reviewed and approved by ATC management.
- CEII information is documented in a separate electronic document with restricted distribution.
Once the information has been approved internally, the Summary Report is distributed publicly. The Summary Report and additional non-CEII details are posted at www.atc10yearplan.com.