Chapter 5.3: Market Congestion Planning Study

Chapter 5.3: Market Congestion Planning Study

The goal of the Market Congestion Planning Study (MCPS) is to develop transmission plans that offer MISO customers better access to the lowest electric energy costs through the markets. From a regional perspective, the study seeks to identify both near-term transmission congestion and long-term economic opportunities and the appropriate network upgrades to enhance the efficiency of the market. The solutions may therefore vary in scale and scope, classified as either “MCP Other Projects” or “Market Efficiency Projects.” As an integral part of MISO’s value-based planning, the MCPS looks to develop the most robust transmission upgrades that offer the highest future value under a variety of both current and projected system scenarios.

Similar to the 2014 planning cycle, parallel economic planning efforts have been undertaken for the MISO North/Central and South regions in MTEP15 in order to better engage the various stakeholders across the MISO footprint.

MCPS North/Central Summary

The 2015 MCPS North/Central built on the progress made during the MTEP14 cycle, which identified several congested flowgates and evaluated the appropriate transmission solutions. By building on the MCPS 2014 analysis, the 2015 cycle focused on four specific areas that showed the highest congestion: Southern Indiana, Southern Illinois, Iowa/Minnesota and, Northern Indiana. Similar to the previous study cycle, the area with the greatest need, and therefore highest potential benefit, was on the border of Indiana and Kentucky.

Several solutions were designed in a collaborative effort between MISO and stakeholders. The solutions were tested for their robustness to address system needs under a variety of scenarios, embodied by the MTEP15 futures. Ultimately, working in concert with PJM and stakeholders, Duff – Rockport – Coleman 345 kV project, which offers both regional and interregional benefit to MISO and PJM, was found to offer the best value. This project completely mitigates the congestion on the MISO system around the Newtonville and Coleman areas and strengthens the 345 kV backbone in the region. In addition, the project fully addresses long-standing reliability issues around PJM’s Rockport station and obviates the need for the Rockport Special Protect Scheme and Operation Guide that protects the stability of the grid.

The project consists of two portions:

– MISO portion being Duff-Coleman 345kV

– PJM portion being the tie-in from Rockport to Duff-Coleman 345kV line.

MISO staff therefore recommends that the MISO portion – Duff – Coleman 345 kV project to be approved as a MISO Market Efficiency Project (MEP).

MCPS South Summary

The 2015 MCPS South built on the progress made during the VLR Planning Study and the MTEP14 MCPS South, which identified several congested flowgates and evaluated the applicable transmission solutions. By building on the previous analysis, the 2015 cycle focused on four specific areas of MISO South: Amite South/DSG, WOTAB/Western, Local Resource Zone (LRZ) 8 (Arkansas), and Remainder of LRZ9. Similar to previous studies the areas with the greatest need, and therefore the highest potential, were in the Amite South/DSG and WOTAB/Western load pockets.

Several solutions were developed by both MISO staff and stakeholders. The solutions were tested for their robustness to meet system needs under a variety of expected scenarios, embodied by the MTEP15 futures.

In the 2015 MCPS South, a total of 82 unique transmission solution ideas were proposed and studied. MISO evaluated these solution ideas and formulated 11 project candidates for further robustness testing, in conjunction with south region stakeholders. Of the 11 project candidates, two were selected by MISO, pending stakeholder feedback, as potential best-fit solutions. Both projects produced a weighted present value (PV) benefit-to-cost ratio greater than 1.25, but due to voltage levels do not met Market Efficiency Project criteria.

  • East Texas economic project with an estimated cost of $122.5 million in 2015 dollars
    • A new 230 kV transmission line from Lewis Creek to a new 345/230 kV substation (NSUB2) by cutting into the existing Grimes to Crocket 345 kV line.
      • Note that MISO agrees Grimes alternative provides similar reliability and economic benefits
    • Rebuilding the existing Newton Bulk – Leach 115 kV line
  • Rebuilding the existing Mabelvale – Bryant – Bryant South 115 kV line with an estimated cost of $6.1 million in 2015 dollars.

 

MISO staff therefore recommends that two projects may be approved as Other economic projects.

MCPS Study Process Overview

The MCPS begins with a bifurcated Need Identification approach to identify both near- and long-term transmission issues. The Top Congested Flowgate Analysis identifies near-term, more localized congestion while the longer-term Congestion Relief Analysis explores broader economic opportunities (Figures 5.3-1). Given the targeted focus of the MCPS 2015, emphasis was placed on the top congested flowgate analysis. The congestion relief analysis will be employed in future, broader-scoped planning studies.

With the needs clearly defined, the study evaluates a wide variety of transmission ideas in an iterative fashion with both economic and reliability robustness considerations. The Project Candidate Identification phase includes: screening analysis to pinpoint the solutions with the highest potential; economic evaluation over multiple years and futures to asses robustness; and reliability analyses to ensure the projects do not degrade system reliability. Using this approach, optimal economic transmission upgrades (best-fit solutions) are identified to address market congestion; the solutions may be either cost shareable or non-cost shareable projects.

Figure 5.3-1: MCPS North/Central process overview

MISO North/Central Models and Futures

The production cost models utilized for this study are based on data from PROMOD Powerbase and the corresponding MTEP powerflow cases. The data is refreshed with the most current information and with the system variables (fuel cost, demand, etc.) reflecting the MTEP Futures definitions. The agreed-upon future scenarios and weightings for the MISO North/Central MTEP15 study are:

  • Business as Usual (BAU): 40 percent
  • High Growth (HG): 15 percentLimited
  • Growth (LG): 15 percent
  • Generation Shift (GS): 20 percent
  • Public Policy (PP): 10 percent

 

The Planning Advisory Committee (PAC) assigned weights to each future as a reflection of the perceived probability of each future being actualized (see Chapter 5.2, MTEP Future Development).

Similarly, the agreed-upon future scenarios and weightings for the MISO South MTEP15 study are:

  • Business as Usual (BAU): 34 percent
  • South Industrial Renaissance (SIR): 24 percent
  • Generation Shift (GS): 22 percent
  • Public Policy (PP): 20 percent

 

MISO stakeholders likewise assigned weights to each future (see Chapter 5.2, MTEP Future Development).

Top Congested Flowgate Analysis

The top congested flowgate analysis identifies system congestion trends based on both the historical market data and forecasted congestion. The analysis identifies and prioritizes highly congested flowgates within the MISO market footprint and on the seams (Figures 5.3-2 and 5.3-3).

 

Figure 5.3-2: MISO North/Central Projected Top Congested Flowgates

Figure 5.3-3: MISO North/Central Projected Top Congested Flowgates


Figure 5.3-4

Figure 5.3-4: MISO South Projected Top Congested Flowgates

The flowgates of interest are those with historical congestion and are projected to be limiting constraints throughout the 15-year study period. MISO finds these flowgates by examining:

  • Historical day-ahead, real-time and market-to-market congestion
  • Projected congestion identified through out-year production cost model simulations

 

The magnitude and frequency of congestion offers a strong signal to where transmission investments should be made.

Project Candidate Identification

Project candidate identification is a MISO-stakeholder partnership to identify network upgrades that address the top congested flowgates; solutions ideas may be submitted by stakeholders or developed by MISO staff. The solution ideas include those designed to directly address specific flowgates, provide energy transfer paths, and/or to unlock cheaper resources by connecting import-limited areas to export-limited areas.

Given the potential for numerous transmission ideas submissions, MISO developed a screening process to identify solutions that will most cost effectively relieve the congestion of interest. The screening does not preclude any solutions, but rather refines the pool of projects that will be analyzed in detail as MISO determines the optimal solution. Adjusting for model updates through the course of the study, the screening results are a good predictor of projects’ performance. The screening index for each solution was calculated as the ratio between the 15-year-out Adjusted Production Cost (APC) savings and the corresponding project cost:

Figure 5.3-2.5

Any project with a screening index of 0.9 has the potential for a benefit-to-cost ratio greater than 1.25, the Market Efficiency Project (MEP) threshold. In addition to identifying the projects with the highest potential, the screening analysis provides valuable information that can be used to modify and improve the solutions that do not pass the screening. In general, transmission solutions do not pass the screening for one of at least three reasons: the solution does not relieve all of the congestion on a targeted top flowgate(s); the solution relieves congestion on one flowgate but increases congestion on other flowgate(s); or the solution relieves congestion but the project cost is high relative to benefit.

By considering the specific reason for a project’s screening performance, the project can be refined to better address the congestion. Corresponding to the above three reasons, the refinement may include: expanding and/or reconfiguring a project; combining projects that address related flowgates; and pruning projects to keep the most effective elements. The refinement of the solutions properly considers the balance of achieving synergistic benefits and avoiding excessive transmission build-outs that produce diminishing returns. This study phase determines the project candidates that move on to a more comprehensive analysis.

Robustness Testing

Once the preliminary project candidates are identified, an iterative process takes place between economic robustness evaluation and reliability assessment. Robustness testing identifies the transmission projects/portfolios that provide the best value under most, if not all, predicted future outcomes; the reliability assessment ensures system reliability is at least maintained.

Project Benefit and Cost Analysis:

The MISO Tariff measures a MEP’s benefit by the APC savings realized through the project under each of the MTEP future scenarios. APC savings are calculated as the difference in total production cost adjusted for import costs and export revenues with and without the proposed project in the transmission system. Given the parallel MCPS studies, the benefits for each project are counted only for the relevant MISO sub-region, North/Central or South. Data from three simulation years (2019, 2024 and 2029) are used as the basis for evaluating the project impact. A 20-year benefit is calculated by linearly interpolating and extrapolating from these three years. The total project benefit is determined by calculating the present value of annual benefits for the multi-future and multi-year evaluations.

As further detailed in Attachment FF of the MISO Tariff, a MEP must meet the following criteria:

  • Have an estimated cost of $5 million or more
  • Involve facilities with voltages of 345 kV or higher; and may include lower-voltage facilities of 100 kV or above that collectively constitute less than 50 percent of the combined project cost
  • Benefit-to-cost ratio of 1.25

 

Although prescribed for MEPs, the above metric and analysis is used to evaluate all “economics” projects. To arrive at the best solution, projects with a benefit-to-cost ratio greater than 1.25 but not meeting either all the MEP criteria are also considered.

Reliability Analysis:

The reliability analysis uses a no-harm test to determine the impact of project candidates on the thermal and voltage stability of the system under select NERC Category B and C contingencies. A project candidate passes the reliability no-harm test if there is no degradation of system reliability with the addition of the project.

The no-harm test compares the contingency analysis results between two models, a base model and a model including the project candidate, to find if any violations are worsened by the addition of the project candidate.

The no harm test is performed on four cases:

  • Five-year-out Summer Peak
  • Five-year-out Shoulder Peak for North/Central and five-year-out Winter Peak for South
  • 10-year-out Summer Peak

 

The following NERC categories of contingencies are evaluated:

  • Category P0 when the system is under normal conditions
  • Category P1 contingencies resulting in the loss of a single element
  • Category P2 contingencies resulting in the loss of two or more elements due to a single event

 

Southern Indiana

MCPS identified a significant amount of congestion in Southern Indiana, particularly around the Coleman substation, which is a gateway for the nearby large industrial load pocket (Figure 5.3-4). In the event that Davies – Coleman 345 kV, a key feed into this load pocket, is outaged, the supply route for this area shifts to the lower voltage branches. As a result, congestion on branches such as Newtonville – Coleman 161 kV increases under N-1 conditions. Further exacerbating this issue are the projected load growth and the in-service status of local coal generation. Congestion relief in this area would mean that the load pocket could be more easily supplied with alternative generation.

Figure 5.3-3: Southern Indiana Top Flowgates

Figure 5.3-3: Southern Indiana Top Flowgates

With the highest amount of congestion in the MISO North/Central footprint, several submitted solutions ideas in this area passed the screening and had high benefit-to-cost ratios. The majority of proposed solution ideas in this area were new 345 kV lines providing an alternative access point into the load pocket. The recommended project of Duff – Rockport – Coleman 345 kV along with five high-voltage alternatives were considered for addressing the congestion in this area (Table 5.3-1).

Transmission Solution Cost to MISO ($M) Cost to PJM ($M) MISO Benefit to Cost Ratios
BAU GS HG LG PP Weighted
Recommended Project Duff – Rockport – Coleman 345 kV $67.4 $85.3 16.8 21.2 17.4 17.0 0.2 16.1
Alternative 1 Duff – Coleman 345 kV $67.4 NA 16.6 20.9 17.1 16.8 (2.9) 15.6
Alternative 2 Rockport – Coleman Double Circuit 345 kV $56.9 $54.6 19.9 24.8 19.6 20.3 1.9 19.1
Alternative 3 Duff – Century 345 kV, Century 345/161 kV $83 NA 14.1 17.2 14.4 14.2 (1.8) 13.2
Alternative 4 Reid – Coleman 345 kV $144 NA 7.5 8.8 7.1 7.9 (2.7) 6.8
Alternative 5 Wilson – Coleman 345 kV $111 NA 9.5 11.3 8.6 10.2 (2.9) 8.6
Table 5.3-1: Southern Indiana project alternatives benefit-to-cost ratios

All of the transmission solutions in Table 5.3-1 relieve most or all of the congestion around Newtonville and Coleman, but have different benefit-to-cost ratios due to their varying costs. Other low-voltage alternatives, such as adding a third Newtonville transformer or adding a phase shifter in between Newtonville and Coleman, were also considered. However, these projects do not adequately address the congestion in the area.

Duff – Coleman 345 kV was initially found to provide the most value by fully mitigating the congestion around the Newtonville substation, strengthening the surrounding area’s 345 kV backbone by completing the loop started years ago by Gibson – AB Brown – Reid – Wilson – Coleman 345 kV, and unlocks cheaper generation in Southern IN to serve the load pocket at the Coleman substation area.

Due to Coleman’s proximity to the Rockport substation, MISO and PJM found an opportunity to collaboratively develop two additional options: Rockport – Coleman Double Circuit 345 kV and Duff – Rockport – Coleman 345 kV. These two options were designed to capture equal or greater value as Duff – Coleman 345 kV for the MISO footprint at equal or lesser cost while at the same time allowing PJM to remove its need for the longstanding Rockport operational complexity by providing additional outlets out of the Rockport substation. As part of this collaboration, PJM agreed to pay any incremental cost beyond the cost required by Duff – Coleman 345 kV.

Reliability analysis revealed that the Rockport – Coleman Double Circuit 345 kV option led to severe overloading on Davies – Coleman 345 kV and both Coleman 345/161 kV transformers. Additionally, it did not achieve its intended purpose by fully resolving the operational performance issues at Rockport. Analysis on Duff – Rockport – Coleman 345 kV, on the other hand, found that it allowed for the full removal of Rockport’s special protection scheme needs and did not cause severe overloading. Furthermore, it still achieves all the aforementioned benefits provided by the Duff – Coleman 345 kV project. Duff – Rockport – Coleman 345 kV (Figure 5.3-5).

Figure 5.3-5: Map of Duff – Rockport – Coleman 345 kV (approximate line routing)

Figure 5.3-5: Map of Duff – Rockport – Coleman 345 kV (approximate line routing)

In light of all this, Duff – Rockport – Coleman 345 kV was selected as the project of choice. MISO staff recommends that the Duff – Rockport – Coleman 345 kV project be approved as a MISO Market Efficiency Project (MEP). This project is to be jointly funded by MISO as an MEP and PJM as a supplemental project (Figure 5.3-6). MISO will be responsible for the cost of the Duff – Coleman ($67.4 million) portion, which will be open for bid as part of the Transmission Developer Qualification and Selection (TDQS) process. PJM will fund the cost of the double circuit 345 kV tie-in to Rockport ($85.3 million) outside the MISO TDQS process.

Figure 5.3-6: MISO and PJM shares of Duff – Rockport – Coleman 345 kV

Figure 5.3-6: MISO and PJM shares of Duff – Rockport – Coleman 345 kV

Southern Indiana Reliability Analysis

For 2015 cycle, primarily MTEP15 phase two 2020 summer peak models are used.  Additional to basic no-harm test, comprehensive reliability analysis is done to evaluate the candidate projects showing high values. Additional scenarios include:

  • Sensitivity analysis:  Specific generators status was adjusted.  Units under suspension or expected retirement of the unit motivated the sensitivity analysis.
  • Project impact on SPS:  For the candidate project associated with SPS, reliability analysis was done to assess the system condition with the SPS. At the same time, study was done to see if the project could permanently remove the associated SPS.
  • Extended reliability analysis: Specific flowgates, pre and post contingent flow pattern, and additional NERC category contingencies are evaluated.
               

The congestion issues at Newtonville transformers are solved by the proposed candidate projects. All of these projects passed the basic no-harm test. As Duff-Coleman and Rockport- Coleman project showed high value, in additional to basic no-harm test, the aforementioned comprehensive reliability analysis was performed.

For the sensitivity case with the retired Coleman units, both the Duff and Coleman projects have thermal violations at 5COLEMAN to COLEEHV 161 kV circuits 1 and 2. Costs to mitigate are estimated at $200,000.

  • Rockport-Coleman double circuit 345 kV line
    • Reliability constraints identified on either of the two Coleman to Coleman EHV 161 kV circuits for n-1 loss of the other Coleman to Coleman EHV 161 kV circuit
    • Additional severe overloads identified on Davies to Coleman 345 kV line and both 345/161 kV transformers at Coleman for n-2 loss of Rockport-Jefferson and Rockport-Sullivan 765 kV lines without Rockport redispatch
  • Duff-Rockport-Coleman 345 kV line
    • Reliability constraints identified on either of the two Coleman to Coleman EHV 161 kV circuits for n-1 loss of the other Coleman to Coleman EHV 161 kV circuit
    • Additional overload identified on Reid to Davies 161 kV line for n-2 loss of Wilson-Reid 345 kV and Rockport-Coleman 345 kV lines. Redispatch using Wilson generation mitigate overloads

 

Additional qualitative review was inconclusive in identifying superior alternative from reliability standpoint.

Southern Illinois

General flows in the MISO North/Central system are from west to east and through Southern Illinois. In Missouri and Southern Illinois, there is a generation pocket containing several economic units but with a constrained transmission outlet, particularly under N-1 conditions. Both historically and in out-year simulations, the lower-voltage system becomes congested under contingency conditions for the loss of 345 kV transmission that delivers flow eastward through the region (Figure 5.3-7).

In the 2014 cycle of the MCPS, the flowgates Tilden – Sparta Tap 138 kV and the Baldwin 345/138 kV transformer were identified as two of the top-congested flowgates in the system. The analysis showed that relieving these flowgates offered high benefits to the region. A MISO market participant is funding upgrades to address these constraints through projects that are now included in MTEP15 Appendix A. The market participant funded upgrades were included in the MCPS model midway through the study. As a result of this model update, solution ideas that also address these flowgates show lower benefits.

Figure 5.3-4: Southern Illinois top congested flowgates

Figure 5.3-7: Southern Illinois top congested flowgates

A total of 17 transmission solution ideas were submitted to address congestion in Southern Illinois. Two of the solution ideas, addressing flowgates I and M, passed the screening process.

  • Cahokia – N. Coulterville tap at Prairie State 230 kV
  • 2nd Joppa 345/161 kV transformer

 

As a result of the screening analysis, an additional solution was developed to address both flowgates simultaneously: Albion – Norris City 345 kV and a 2nd Joppa 345/161 kV transformer.

In carrying these solutions forward, the analysis showed that congestion in Southern Illinois was particularly sensitive to congestion in the Newtonville area in Southern Indiana and retirement assumptions in the Tennessee Valley Authority (TVA) area.

The solutions submitted to address congestion in Southern Illinois impact generation in Southern Indiana; the output from this generation, though economic, is restricted by congestion around Newtonville. As a result, there are diminishing benefits when combining solution ideas in Southern Illinois with projects that more directly and effectively address the Newtonville area congestion in Southern Indiana. Therefore, the comprehensive evaluation of Southern Illinois was performed sequentially after first relieving the Newtonville area congestion.

The analysis found that nearby Shawnee TVA coal units have notable impact on the top two flowgates: Nason Point – Ina 138 kV and the Joppa 345/138 kV transformer. The most current information indicates that nine out of the 10 TVA units will remain in service. The TVA units provide counter flow on the top two flowgates, which decreases the level of congestion in Southern Illinois.

Transmission Solution Cost ($M) ISD Benefit to Cost Ratios
BAU GS HG LG PP Weighted
Cahokia–N. Coulterville Tap at Prairie State 230 kV 23.5 2018 0.7 0.6 1.4 0.5 0.0 0.67
Albion–Norris City 345 kV + 2nd Joppa Transformer 78.2 2022 0.2 0.4 0.2 (0.0) (0.5) 0.14
2nd Joppa 345/161 kV Transformer 10.3 2019 (0.1) 0.5 (0.2) 0.1 (2.4) (0.20)
Table 5.3-2: Southern Illinois projects benefittocost ratios

Cahokia – N. Coulterville Tap at Prairie State 230 kV showed the greatest benefit for its cost in this area (Table 5.3-2). For this solution idea, a revised cost estimate was determined based on MISO independent cost evaluation. With the current TVA generation retirement assumptions, the project’s benefits are reduced. This project will be evaluated in future MCPS cycles as generation retirement assumptions become clearer.

Iowa/Minnesota

A significant amount of cheap coal and wind resources are located in Western MISO. It is assumed that the renewable capacity in this area will continue to grow over the next 15 years. With the big load centers to the east of this region, the flows are west to east through Iowa. The low voltage transmission will likely be congested with the loss of major 345 kV lines in this transfer path. In particular, under the Public Policy and Generation Shift futures, the projected wind additions increases west-to-east flows that further stress the system.

Four top flowgates were identified in this region: one in Minnesota, three in Iowa (Figure 5.3-7). Of the 12 solution ideas studied in Iowa/Minnesota area, three passed the screening analysis and were further evaluated:

  • Rebuild Winnebago – Blue Earth 161 kV
  • New Huntley – South Bend 345 kV
  • New Huntley – Wilmarth 345 kV

 

All of the three ideas address flowgate Blue Earth‑Winnebago, which delivers power from Northwestern Iowa to the Twin Cities.

Figure 5.3-6: Iowa/Minnesota top congested flowgates

Figure 5.3-8: Iowa/Minnesota top congested flowgates

None of the three projects meet the MEP benefit to cost ratio of 1.25 (Table 5.3-3). This is due, in part, to a model correction midway through the study that increased the rating of Blue Earth–Winnebago.

Transmission Solution Cost ($M) ISD kV 20 Year NPV B/C Ratio
BAU GS HG LG PP Weighted
Rebuild Blue Earth–Winnebago 161 kV 5 2018 161 0.16 2.13 1.15 (0.19) 2.85 0.92
Huntley–South Bend 345 kV, South Bend 345/115 kV 95 2023 345 0.01 1.25 0.17 (0.01) 5.12 0.79
Huntley–Wilmarth 345 kV 67 2020 345 0.08 3.37 0.33 0.05 1.52 0.92
Table 5.3-3: Iowa/Minnesota projects benefit-to-cost ratios

In addition, the third project, Huntley – Wilmarth 345 kV, initially had a weighted benefit-to-cost ratio of 2.21. However, with a low benefit in the Business as Usual (BAU), High Growth (HG) and Limited Growth (LG) futures, the result indicated that the weighted benefit was disproportionately reliant on the Public Policy (PP) future that assumes significant additions in the area. To verify this, a sensitivity test was performed in which a number of wind generators were re-sited from western to eastern MISO, bringing the PP future capacity in the west to the BAU level. This amounted to a relocation of 3.7 GW in the 2024 model and 8.7 GW in the 2029 model. Study results show that the benefit-to-cost ratio of this project under PP future dropped to 1.52, lowering the weighted B/C ratio to 0.92.

The generation growth and flows in this region will continue to be studied in future planning cycles.

Northern Indiana

Northern Indiana is impacted by a confluence of various flows across the MISO system: west-to-east flows driven by both MISO and PJM transfers; south-to-north flows; east-to-west flows to serve industrial load around southern Lake Michigan; and flows driven by wind in central Indiana and Illinois. The MCPS 2015 simulation models show only the congestion on the east of southern Lake Michigan, driven by east-to-west flows. The top flowgate in this area is New Carlisle ‑ Bosserman for the loss of New Carlisle ‑ Olive 138 kV, which stradles the border of MISO and PJM (Figure 5.3-9).

Figure 5.3-7: Northern Indiana top congested flowgates

Figure 5.3-8: Northern Indiana top congested flowgates

Seven projects were submitted to address the congestion in this area. The projects addressed the issue by either providing an alternative west-to-east path or reinforcing the east-to-west path to meet the load. None of the projects passed screening.

Amite South/DSG

MCPS South identified a significant amount of congestion in the Amite South and DSG load pockets, particularly on the import lines into the DSG load pocket (Figure 5.3-9). In the event that Little Gypsy – Wesco 230 kV, a tie-line between the Amite South and DSG load pockets, is outaged and a generator is lost inside of the DSG load pocket, flows are shifted to remaining tie-lines between the pockets. As a result, the next limiting element under N-1, G-1 conditions becomes the Snakefarm – Labarre 230 kV line. Further aggravating this issue is that the DSG load pocket is import limited and has few economic generation options inside of the load pocket. Construction of an additional import line between Amite South and DSG would help to alleviate congestion under N-1, G-1 conditions and more easily supply the DSG load pocket with alternative economic generation.

Figure 5.3-9: Amite South/DSG top congested flowgates

Figure 5.3-10: Amite South/DSG top congested flowgates

Through collaboration with stakeholders, MISO evaluated different generation scenarios as part of the robustness testing for projects identified in the Amite South and DSG load pockets (Table 5.3-4). Pending additional stakeholder feedback, MISO may perform additional generation sensitivities around the Regional Resource Forecast (RRF) unit located at the Little Gypsy site inside the Amite South load pocket.

Powerbase Name Scenario 1 Scenario 2
RRF MISO CC:3 Lewis Creek 230kV Lewis Creek 230kV
RRF MISO CC:4 Nelson 500kV Nelson 500kV
RRF MISO CT:29 Michoud 115kV Big Cajun 500kV
RRF MISO CT:31 Sabine 138kV Sabine 138kV
Table 5.3-4: Amite South/DSG RRF scenario siting

Sixteen projects were submitted to address congestion in Amite South and DSG load pockets. The projects addressed the issues of increasing transfer capability into Amite South and DSG, however after screening and refinement only three projects adequately addressed the congestion (Table 5.3-5).

Transmission Solution Cost ($M) ISD Siting Scenario Benefit to Cost Ratios
BAU GS PP SIR Weighted
2nd Waterford – Nine Mile 230kV $105.1 2021 Scenario 1 1.30 1.25 1.15 0.56 1.08
Scenario 2 1.30 1.25 1.15 1.96 1.42
Waterford – NSUB1 230kV $98.8 2021 Scenario 1 1.37 1.26 1.25 0.66 1.15
Scenario 2 1.37 1.26 1.25 2.02 1.48
Union Carbide – Wesco 230kV $37.9 2022 Scenario 1 1.88 2.33 1.16 1.38 1.71
Scenario 2 1.88 2.33 1.16 4.35 2.43
Table 5.3-5: Amite South/DSG project benefit-to-cost ratios

All three projects help to mitigate the congestion seen on the import lines between the Amite South and DSG load pockets. However, where the second Waterford to Nine Mile 230kV and Waterford to NSUB1 230kV projects fully mitigate the congestion, Union Carbide to Wesco 230kV only partially mitigates the congestion. There is also potential infeasibility issues associated with building a new line into the Nine Mile substation, thus creating the need for the evaluation of the Waterford to NSUB1 230 kV alternative. With the uncertainty surrounding the future generation scenarios and the inability of Waterford to NSUB1 230 kV to show sufficient benefits, above a 1.25 benefit-to-cost ratio, in all siting scenarios these projects will be further evaluated as part of MTEP16.

WOTAB/Western

MCPS South identified a significant amount of congestion in the WOTAB and Western load pockets, both on import lines and internal congestion inside the load pockets (Figure 5.3-11). Both the WOTAB and Western load pockets are import limited and therefore commitments of units within the load pockets are required at specified limits to maintain reliability. The 2015 MCPS South models replicate these commitments using N-1, G-1 conditions. These N-1, G-1 conditions show high levels of congestion on the Newton Bulk – Leach 138kV, which represents an import line into the WOTAB load pocket, as well as congestion on both Grimes – Mt. Zion 138kV and Tubular – Dobbin 138 kV located inside of the Western load pocket.

Figure 5.3-10: WOTAB/Western top congested flowgates

Figure 5.3-11: WOTAB/Western top congested flowgates

Through collaboration with stakeholders, MISO evaluated different generation scenarios as part of the robustness testing for projects identified in the WOTAB and Western load pockets (Table 5.3-6).

Powerbase Name Scenario 1 Scenario 3
RRF MISO CC:3 Lewis Creek 230kV Holland Bottoms 500kV
RRF MISO CC:4 Nelson 500kV White Bluff 500kV
RRF MISO CT:29 Michoud 115kV Michoud 115kV
RRF MISO CT:31 Sabine 138kV Franklin 500kV
Table 5.3-6: WOTAB/Western RRF scenario siting

Twenty-eight projects were submitted to address congestion in the WOTAB and Western load pockets. These projects aimed to address issues of increased transfer capabilities into the WOTAB and Western load pockets, as well as alleviating internal congestion in the load pockets. After the completion of screening and refinement, three projects were identified as potential solutions to address congestion within the WOTAB and Western load pockets (Table 5.3-7).

Transmission Solution Cost ($M) ISD Siting Scenario Benefit to Cost Ratios
BAU GS PP SIR Weighted
Newton Bulk – Leach: Rebuild 138kV $25.0 2021 Scenario 1 1.48 4.41 6.76 1.26 3.13
Scenario 3 3.53 5.25 8.81 6.11 5.58
NSUB2 – Lewis Creek 230kV & Newton Bulk ‑ Leach: Rebuild 138kV $122.5 2021 Scenario 1 0.83 1.48 3.45 0.86 1.50
Scenario 3 1.77 2.50 3.78 4.03 2.88
NSUB2 – Lewis Creek 345kV & Newton Bulk ‑ Leach: Rebuild 138kV $183.7 2021 Scenario 1 0.55 1.04 2.29 0.68 1.04
Scenario 3 1.22 1.88 2.69 3.18 2.13
Table 5.3-7: WOTAB/Western project benefit-to-cost ratios

The NSUB2 – Lewis Creek 230 kV and Newton Bulk – Leach: Rebuild 138 kV project performs well, above a 1.25 benefit-to-cost ratio, with future RRF units sited either inside or outside of the WOTAB and Western load pockets. Though the 345 kV option does produce a benefit-to-cost ratio above 1.25 when future RRF units are sited outside of the load pockets, its benefit-to-cost ratio is just above 1.0 when future RRF units are sited inside of the load pockets. Given this result the preferred solution to mitigate the identified congestion is the 230 kV option from NSUB2 to Lewis Creek and the rebuild of the 138 kV line from Newton Bulk to Leach. Potential recommendation of this project by MISO to the Board for approval as part of MTEP15 is pending based on additional stakeholder feedback at this time.

LRZ8 (Arkansas)

The identified congestion in LRZ8 (Arkansas) was more localized than that seen in the import limited load pockets in Louisiana and Texas. The 2015 MCPS South models showed reduced levels of congestion in comparison to Amite South, DSG, WOTAB and Western. The majority of congestion in this area was in central Arkansas, particularly the congestion see in Mabelvale – Bryant 115 kV (Figure 5.3-12).

Figure 5.3-11: LRZ8 (Arkansas) top congested flowgates

Figure 5.3-12: LRZ8 (Arkansas) top congested flowgates

Eleven projects were submitted to address congestion in LRZ8 (Arkansas). After the completion of screening and refinement, one project was identified as a potential solution to address congestion within the LRZ8 (Arkansas), while the others had associated costs that well exceeded their associated benefits (Table 5.3-8).

Transmission Solution Cost ($M) ISD Benefit to Cost Ratios
BAU GS PP SIR Weighted
Mabelvale – Bryant – Bryant South: Rebuild 115 kV line $6.1 2020 7.65 10.38 1.36 3.02 5.88
Table 5.3-8: LRZ8 (Arkansas) project benefit-to-cost ratios

The Mabelvale – Bryant – Bryant South: Rebuild 115 kV line has been identified as the best-fit solution to mitigate the congestion observed on the Mabelvale – Bryant 115kV line. Potential recommendation of this project by MISO to the Board for approval as part of MTEP15 is pending based on additional stakeholder feedback at this time.

Remainder of LRZ9

The identified congestion in the Remainder of LRZ9 was spread across the footprint with the majority of congestion showing in north Louisiana, Swartz – Alto 115 kV, and in central Mississippi, McAdams 500/230 kV transformer (Figure 5.3-12).

Figure 5.3-12: Remainder of LRZ9 top congested flowgates

Figure 5.3-13: Remainder of LRZ9 top congested flowgates

Twenty-seven projects were submitted to address congestion in the Remainder of LRZ9. After the completion of screening and refinement four projects was identified as a potential solution to address congestion, while the associated costs of the remaining projects well exceeded their associated benefits (Table 5.3-9).

Transmission Solution Cost ($M) ISD Benefit to Cost Ratios
BAU GS PP SIR Weighted
Alto Series Reactor $4.2 2024 12.20 4.18 6.98 4.27 7.49
Replace 2nd McAdams 500/230 kV XFMR $14.0 2020 1.56 2.04 1.45 1.78 1.70
3rd McAdams 500/230 kV XFMR $14.0 2020 2.26 1.29 0.88 2.36 1.80
3rd McAdams 500/230 kV XFMR & Pickens – Midway: Rebuild 115 kV & Attala – Conehoma: Rebuild 115 kV $43.4 2020 1.06 0.73 0.76 0.88 0.88
Table 5.3-9: Remainder of LRZ9 project benefit-to-cost ratios

The comprehensive solutions to address broader congestion identified in this area resulted in benefit-to-cost ratios below one. Considering this, the projects in the Remainder of LRZ9 are deemed not suitable for for recommendation at this particular time.

Benchmark Results and Next Steps

The difference between historical congestion and the simulation of out-years may be due, in large part, to approved transmission upgrades in the region but may also reflect the sensitivity of flows to model assumptions and limitations of the model. Over the last several months, MISO has made significant progress in benchmarking the PROMOD model to historical market. Chapter 5.4 has a detailed discussion of the benchmark study with specific recommendations on how to improve the modeling of this region.

With the recommendations of the benchmarking study incorporated, the congestion pattern will be revisited. Along with other relevant solutions, the submitted solutions will be re-evaluated in future MCPS cycles.