MTEP Chapter 7.1 Voltage and Local Reliability Planning Study

MTEP Chapter 7.1 Voltage and Local Reliability Planning Study

Under the MTEP14 planning cycle, MISO, in collaboration with stakeholders, performed a study of the South Region load pockets. The study was to determine whether or not there are transmission alternatives that may lower overall cost-to-load by reducing Voltage and Local Reliability (VLR) resource commitments necessary to maintain system reliability. MISO identified such transmission upgrades necessary to maintain reliability that are cost effective by providing production cost savings in excess of their cost. More specifically, MISO recommends network upgrades with an estimated cost of $300 million that provide production cost savings of about $498 million on a 20-year present value basis. This analysis was an outcome of the study of reliability issues driven by new firm load additions, existing and planned future generation with signed interconnection agreements and confirmed generation retirements via Attachment Y process.

Figure 7.1-1:

Figure 7.1-1: List of cost effective Reliability Network Upgrades recommended in MTEP15

The VLR study additionally looked at mitigating all transmission issues resulting from potential shutdown of approximately 7,200 MWs of VLR units. Transmission costs for mitigating all such issues are estimated to be more than $1.8 billion. When compared against the 2014 year cumulative make whole payments for these VLR units of approximately $70 million, it was concluded that the network upgrades are not cost effective.

The VLR study further investigated potential scenarios involving the shutdown of a subset of VLR units without re-dispatching around transmission constraints using additional VLR units. Various scenarios studied resulted in different transmission issues. Transmission costs for mitigating these issues in the various scenarios are estimated to be in the range of $23.5 million to $1.8 billion. Once again, it was concluded that these network upgrades are not cost effective.

During the study process, MISO received an overwhelming stakeholder feedback that production cost savings was the most appropriate metric to evaluate benefits of eliminating VLR costs, which aligns with the benefit metric of MISO Market Congestion Planning Study (MCPS). Further, recognizing the uncertainties in the region on potential size and locations of future generation additions, retirements and new load growth, stakeholders provided extensive feedback that led to formulation of four futures. These are:

  • Business as Usual (known out-year load growth, fuel prices, generation additions and retirements)
  • South Industrial Renaissance (modeling increase in projected load growth)
  • Generation Shift (modeling future age related generation retirements despite lack of firm notifications)
  • Public Policy (modeling future RPS goals and standards in addition to age related generation retirements)

Given the breadth of uncertainties successfully captured within the futures used in economic studies, the analysis of understanding the benefits of eliminating or reducing VLR generation commitments was appropriately carried into the MTEP15 MCPS. Please refer to MTEP report Chapter 5.3, for further information on the MCPS.

Introduction

The southern load pockets contain a significant amount of generating units but a lack of quick-start units. By definition, load pockets have limited import capability, limiting the choices system operators have to keep the system secure. As such, generating units necessary to maintain reliability are committed for operation in advance of system events beyond the next contingency, even if a more economical generator is available to dispatch. Complicating the dispatch selection are factors such as minimum run time, cold lead time and minimum down times (up to three days for some units). These out-of-market commitments ensure that adequate generation is online to avoid firm load shed following the first contingency because no quick-start units are available that could be brought on post-contingency. Maintenance and forced outages further complicate the unit commitment algorithm. These factors lead to VLR-triggered resource commitments in the southern load pockets, which in turn leads to higher production costs.

MISO’s transmission planning process focuses on minimizing the total cost of delivered power to consumers. Therefore, in 2014, MISO began a targeted planning study to ascertain whether there are cost‐effective transmission alternatives to serve load at a lower overall cost by eliminating or reducing VLR-triggered resource commitments. The variable operating costs of these generation resources are currently higher than other market alternatives and their dispatch results in an increase in production cost. The study hypothesis was that the incremental costs may be significant enough to support the development of transmission upgrades as a more economic means of reliably serving load.

This study also considered upgrades identified through other processes during MTEP14. Additionally, the study considered mitigation options such as generation, demand-side and transmission solutions consistent with planning provisions under Attachment FF of the MISO tariff. Identified transmission alternatives were evaluated for any associated adjusted production cost benefits compared to current and predicted VLR unit commitments. MISO identified upgrade recommendations during the second quarter of 2015.

This planning study focused on the MISO South region, which includes parts of Louisiana and Texas.

The Amite South area encompasses all of Louisiana east of Baton Rouge, the greater New Orleans area, and includes the Down Stream of Gypsy (DSG) area. DSG is Entergy’s service area downstream of the Little Gypsy generating plant and includes the New Orleans metro area. The Amite South units included in the study are Little Gypsy and Waterford. The DSG units included in the study are Michoud and Nine Mile. Other units included in the Amite South area are Little Gypsy and Waterford.

The West of the Atchafalaya Basin (WOTAB) encompasses the southwest portion of the Entergy footprint including a portion of Texas and Louisiana. It also includes Western Region, which is the portion of Entergy’s service area west of the Trinity River. The WOTAB units included in the study are Sabine and Nelson; the Western Region units included in the study are Frontier and Lewis Creek. Other units included in the WOTAB area are Sabine and Nelson.

Deliverables

This study produced the following deliverables:

  • Potential transmission upgrades that provide comparable or improved system reliability performance as well as reduced VLR unit commitments in the following load pockets/areas:
    • Amite South (including DSG)
    • WOTAB (including Western Region)
  • Economic comparison of the cost of transmission alternatives versus predicted VLR generation commitment costs
  • Project classification for cost allocation to the extent transmission alternatives are recommended to be included in MTEP consistent with the existing MISO tariff

The study began during the MTEP14 planning cycle and took into consideration any upgrades identified for recommendation within MTEP14 (Table 7.1-1). Transmission upgrades determined to be cost-effective alternatives to VLR commitments will be recommended as projects for approval by the MISO Board when sufficient analysis and stakeholder vetting has occurred to establish the business case. The study went through four phases before project recommendations are issued.

Task Completion
Model development May 2014
Reliability Analysis June–Aug 2014
Solution Identification Aug.–Nov. 2014
Economic Assessment Nov. 2014–April 2015
Project Recommendations 2015 Q2
Table 7.1-1: VLR study schedule

Study Approach

Base Models

MTEP14 reliability and economic planning models were used for this study. The reliability assessment included steady-state and dynamics analyses for the 2019 and 2024 summer peak and shoulder load conditions. Economic assessment of preferred transmission solutions were performed using the latest available PROMOD models under the Market Congestion Planning Study (MCPS) process. Simulations were performed for the 2019, 2024 and 2029 timeframes to compute the economic value of transmission solutions.

Additionally, models for sensitivity analyses were developed as needed, which included facilities such as proposed transmission and generation-side solution ideas (including generators that may not have executed generation interconnection agreements).

Industrial Renaissance Models

Additional Models were developed due to the anticipated industrial load growth in the load pockets. The 2024 summer peak model was adjusted to match the load forecast submitted into Module E. This includes scaling up load in the south as well as adding new loads in industrial load centers like Lake Charles, Baton Rouge and the Sabine area. The Generation was adjusted accordingly, following the operational guides for each load pocket, to match the new load. The load increase was approximately 500 MW in the Amite South load pocket and 1,500 MW in the WOTAB load pocket.

Identification of System Limitations

Using the powerflow and dynamics models, the transmission system was analyzed to identify potential system limitations that may result due to VLR generators not being committed.

  1. Review of VLR operating guides: At the outset, available operating guides were reviewed to inform prioritization of VLR units for assessment. In general, units that have incurred the highest VLR costs were the initial focus.
  2. Study region: The study region comprised the entire MISO South region, which includes EES, Entergy Arkansas, Cleco Power, Southern Mississippi Electric, Louisiana Generating, Lafayette Utilities System and Louisiana Energy and Power Authority. Additionally, first‐tier neighboring companies including SOCO, Tennessee Valley Authority, AECI and Southwestern Power Pool were monitored for potential impact. Contingencies assessed include the set of planning events within the study region consistent with those required under NERC Standard TPL‐001‐4. Any additional contingencies dictated by standing operating guides were also evaluated as necessary. Facilities 100 kV and above in the study region were monitored consistent with ongoing MTEP14 evaluations.
  3. Analyses: Steady‐state thermal and voltage, voltage stability and angular stability analyses were performed across the study region.

Identification of Alternative Solutions

  1. Stakeholder input: After the reliability issues without VLR commitment had been identified, potential alternatives to VLR commitments including generation, demand-side and transmission solutions were solicited from impacted load-serving entities, transmission owners and other stakeholders. Solution ideas were discussed at the Planning Subcommittee (PSC). Solutions proposed in the parallel Market Congestion Planning Study (MCPS) in the MISO South region were considered to ensure a coordinated effort.
  2. Performance evaluation: Solution ideas were tested for effectiveness for each of the load pockets/sub‐pockets where reliability issues were identified. Performance was evaluated in the mid‐term as well as the longer term planning horizon (using the 2019 and 2024 models noted earlier). Costs of these transmission solutions were documented on a net present value of annual revenue requirement basis.

Economic Assessment of Transmission Benefit

  1. Economic evaluation: MISO utilized Ventyx PROMOD V11.1 to perform an economic evaluation of the preferred transmission solutions identified in the reliability analysis of VLR study. The Business as Usual future model, developed through the Planning Advisory Committee (PAC), for 2024 and 2029 was used to determine the 20-year Net Present Value (NPV) of benefits for the preferred transmission solutions. The economic model was built starting with the base data provided by Ventyx, the software vendor. Ventyx creates and compiles this data from publicly available information and their proprietary sources and processes. Economic analysis performed on the projects identified in the study showed that $300 million in network reliability upgrades resolve an appreciable amount of VLR commitments while realizing $498M in production cost savings to the MISO South region over a 20-year period.
  2. Results obtained include:
  • Comparison of alternatives including existing VLR commitments, alternative generation options and transmission upgrade options
  • Benefit-to-cost ratios for preferred solutions
  • Comparison of benefits against existing Market Efficiency Planning (MEP) criteria

3.  Potential generator retirements: Consideration was given to identifying, for informational purposes,
additional costs associated with possible future retirement of units under study. These costs will not be
used in the benefits calculation needed for classifying solutions as MEP per the MISO tariff.

Project Categorization and Recommendations

The intent of the study was to identify alternatives that allow reliable performance of the transmission system at a lower overall cost to loads. System upgrades identified through the reliability assessment were evaluated for their economic value and to determine if they are cost‐effective alternatives to VLR generation commitments. Results of the economic assessment were evaluated using existing Market Efficiency Project criteria to determine cost allocation of the upgrades. Projects will be recommended when a business case has been developed that shows benefits commensurate with the costs. The MTEP15 Market Congestion Planning Study South (MCPS) will further evaluate the transmission solution ideas identified in the reliability analysis of VLR study against a set of future scenarios developed in collaboration with the MISO stakeholders capturing a variety of economic and policy conditions as opposed to the least-cost plan under a single scenario. While the best transmission plan may be different in each policy-based future scenario, the best-fit transmission plan — or most robust — against all these scenarios should offer the most value in supporting the future resource mix.

VLR Commitment Cost

The planning study focused on the MISO South region, which included parts of Louisiana and Texas. The load pockets in this area are Amite South, Down Stream of Gypsy (DSG), West of the Atchafalaya Basin (WOTAB), and Western (Figure 7.1-2). The combined load for these areas in the 2024 base model is greater than 16,000 MW. The VLR units listed in the operation guides for these areas have a total capacity of about 10,850 MW.

VLR units in the load pockets that were considered for the study were:

  • Amite South: Waterford (1, 2 and 4), Little Gypsy (1-3), Union Carbide (1-4) and Oxy (1-4)
  • DSG: Nine Mile (3-5) and Michoud (2 and 3)
  • WOTAB: Nelson (4 and 6), Sabine (1-5) and Cypress (1 and 2)
  • Western: Frontier (1 and 2), San Jacinto (1 and 2) and Lewis Creek (1 and 2)
Figure 7.1-2: MISO South load pockets with available VLR units

Figure 7.1-2: MISO South load pockets with available VLR units

The Amite South area encompasses all of Louisiana east of Baton Rouge, which includes the Down Stream of Gypsy (DSG) area. DSG is Entergy’s service area downstream of the Little Gypsy generating plant and includes the New Orleans metro area.

The West of the Atchafalaya Basin (WOTAB) encompasses the southwest portion of the Entergy footprint including a portion of Texas and Louisiana. It also includes Western Region, which is the portion of Entergy’s service area west of the Trinity River.

The study concentrated on the most expensive and frequently committed units. Make Whole Payments (MWP) in the pockets were aggregated and the data of individual units was used to make a decision on how to group these units together. The groups of units were then used to identify transmission alternatives that have the potential of alleviating some MWPs in the pockets (Table 7.1-2).

Load Area VLR Units Under Consideration Max Generation (MW)
DSG Michoud 2 230
Michoud 3 540
Ninemile 3 128
Ninemile 4 723
Ninemile 5 737
Amite South Little Gypsy 1 250
Little Gypsy 2 410
Little Gypsy 3 535
Waterford 1 411
Waterford 2 411
Waterford 4 41
WOTAB Nelson 4 500
Sabine 1 210
Sabine 2 210
Sabine 3 420
Sabine 4 530
Sabine 5 450
Western Lewis Creek 1 260
Lewis Creek 2 260
Frontier 1 165
Frontier 2 165
Table 7.1-2: VLR units studied and generation

Total MWP for all of the VLR units inside the load pockets in 2014 was more than $72 million. The total MWP for the units considered in Table 7.1-2 is about $69 million of the total. DSG and WOTAB are the most expensive pockets. Cumulative MWP and commitments for each load area are in Figure 7.1-3. Overall Amite South/DSG and WOTAB/Western are very close to each other in total VLR commitment and cost.

Figure 7.1-3: a) Make Whole Payments (MWP) for 2014, b) Load Area and VLR Units Considered in Study, and c) Considered Units Annual Commitments and MWP

Figure 7.1-3: a) Make Whole Payments (MWP) for 2014, b) Load Area and VLR Units Considered in Study, and c) Considered Units Annual Commitments and MWP

VLR commitments change month to month with most of the commitments occurring in the summer (Figure 7.1-4). When it comes to frequency of commitments, as expected, the highest were happening during the summer months. Note that the MWP for September is higher than for summer months but the frequency of commitment is lower (Figure 7.1-5). This is because of planned outages in the area, generators being out. This led to some of the VLR units needing to be committed for longer time.

Figure 7.1-4: Monthly and cumulative MWP by month

Figure 7.1-4: Monthly and cumulative MWP by month

Figure 7.1-5: Monthly and cumulative VLR commitments by month

Figure 7.1-5: Monthly and cumulative VLR commitments by month

Reliability Study Results

Study Approach

All scenarios were performed on the MTEP14, 2024 Summer Peak model. The Amite South and West of the Atchafalaya Basin load pockets contain approximately 7,200 MW of generation designated as a VLR unit. Steady state NERC TPL category P1 (single transmission element) and P3 (generator plus single transmission element) contingencies were performed to identify transmission network upgrades needed to eliminate the dispatch of scenario specific VLR designated units.

Base Load Level Scenarios

Scenario 1B: All Voltage and Local Reliability Designated Units Unavailable

Units were forced offline at the Waterford, Little Gypsy, Ninemile, Michoud, Nelson, Sabine and Lewis Creek facilities in the Amite South and the West of the Atchafalaya Basin load pockets. The total VLR generation displacement was approximately 7,200 MW. Approximately $1.845 billion in transmission network upgrades were required to remove all thermal and voltage violations. Planning level estimates were used to determine the cost of all projects. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report. In this scenario, economic analysis was not performed because it did not represent the new load growth additions.

Scenario 1C: Groups of Voltage and Local Reliability (VLR) Designated Units Unavailable

Study Scenario 1C was performed on groups of VLR designated units. Groups were selected based on geographic location and the generation participation factor on areas of constraint. As noted earlier, no additional VLR units otherwise available for redispatch were turned on to relieve transmission constraints. In this scenario, economic analysis was not performed because it did not represent the new load growth additions.

Group A: Waterford 1, 2 and 4; Little Gypsy 1, 2 and 3

The Waterford and Little Gypsy units consist of nearly half the output of the VLR designated units in Amite South: more than 2,000 MW. These units were grouped together due to their geographic location. Little Gypsy is located 2 miles from Waterford, in Amite South on the DSG load pocket interface. The industrial corridor, a 60-mile span of 230 kV lines from Willow Glen to Waterford, is subject to severe thermal constraints with the loss of the Waterford and Little Gypsy units.

The transmission network upgrades to remove all thermal and voltage violations that result from the displacement of generation at the Waterford and Little Gypsy plants is approximately $261 million.

Group B: Ninemile 3, 4 and 5; Michoud 2 and 3

The Ninemile and Michoud units produce approximately 2,350 MW of generation output in the DSG load pocket. These units were grouped together due to their similar impact on constrained elements. Both the Ninemile and Michoud units provide relief to the DSG load pocket import lines from Little Gypsy and Waterford. The industrial corridor, a 60-mile span of 230 kV lines from Willow Glen to Waterford, is subject to severe thermal constraints with the loss of the Ninemile and Michoud units. Additionally, low-voltage violations occur throughout the DSG pocket, and thermal constraints also occur from Little Gypsy to Ninemile substations. The transmission network upgrades to remove all thermal and voltage violations that result from the displacement of generation at Ninemile and Waterford plants is approximately $419 million.

Group C: Nelson Unit 4

Nelson Unit 4 produces 500 MW of local generation in the Lake Charles area of Louisiana. The loss of this unit causes local voltage and thermal issues around the 230 kV network. The transmission network upgrades to remove all thermal and voltage violations that result from the displacement of generation at Nelson is approximately $118 million. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Group D: Sabine Units 1, 2 and 3

Group D consisted of the Sabine units 1, 2 and 3. With the reduction of 840 MW of total generation from the 138 kV units at Sabine, the WOTAB pocket suffers from limited import capability from the east. The system also requires more transmission capability to get power into the demand-heavy Sabine area. Low voltage issues exist around the Sabine 230 kV area. The transmission network upgrades to remove all thermal and voltage violations that result from the displacement of generation from Sabine units 1, 2 and 3 is approximately $395 million. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Group E: Sabine 4 and 5

Group E consisted of the Sabine units 4 and 5. With the reduction of 980 MW of total generation from the 230 kV units at Sabine, the WOTAB pocket suffers from limited import capability from the east. The system also requires more transmission capability to get power into the demand-heavy Sabine area. Low voltage issues exist around the Sabine 230 kV area. The transmission network upgrades to remove all thermal and voltage violations that result from the displacement of generation at Sabine units 4 and 5 is approximately $392 million. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Group F: Lewis Creek 1 and 2

Group F consisted of the Lewis Creek 1 and 2. With a reduction of 520 MW of total generation from Lewis Creek units 1 and 2, the Western pocket suffers from limited import capability through the Sabine area. Widespread low voltage issues exist in the Western pocket without the Lewis Creek units online to provide reactive power support. The transmission network upgrades to remove all thermal and voltage violations that result from the displacement of generation at Lewis Creek units 1 and 2 is approximately $556 million.

Industrial Renaissance Load Level Scenarios

Additional models were developed due to the anticipated industrial load growth in the load pockets. The 2024 summer peak model was adjusted to match the load forecast submitted into Module E. This includes scaling up load in the south as well as adding new loads in industrial load centers like Lake Charles, Baton Rouge and the Sabine area. The generation was adjusted accordingly, following the operational guides for each load pocket, to match the new load. The load increase was approximately 500 MW in the Amite South load pocket and 1,500 MW in the WOTAB load pocket.

Scenario 2A: Industrial Renaissance Load Increase Impact

Contingency analysis was performed on the Industrial Renaissance 10-year-out summer peak model. This model followed the VLR operation guides to dispatch units in the load pockets. The goal was to see the impact the new load had on the reliability of the system. Six projects were identified as reliability-driven and MISO worked with the transmission owner to add those projects into MTEP15. Those and other MTEP15 projects in the load pocket were assessed for their economic benefit in lowering VLR unit commitment.

Scenario 2B: Industrial Renaissance Load Profile and with All VLR Generators Off

Study Scenario 2B was not performed. The goal of this sensitivity is to find the transmission alternative to running all VLR generators with the industrial renaissance load level. This was completed for the base-case load level in scenario 1B. From there MISO found that the solution would be approximately $1.84 billion. Engineering judgement reasons that the high load level will not drive that cost down and since the base-case solution is not cost effective, the decision was made to allocate resources towards other areas of sensitivities. MISO may revisit this scenario if the change in fundamental load/generation assumptions drives a review.

Scenario 2C: Industrial Load Growth, Groups of VLR Designated Units

Study Scenario 2C was performed on groups of VLR designated units with the Industrial Renaissance Load Profile. Groups were selected based on geographic location and the generation participation factor on areas of constraint. As noted earlier, no additional VLR units otherwise available for redispatch were turned on to relieve transmission constraints.

Group A: Waterford 1, 2 and 4; Little Gypsy 1, 2 and 3

When compared to the proposed solution set in Scenario 1C, the increased load projection caused new violations along the 230 and 138 kV transmission lines between Baton Rouge and New Orleans. The Scenario 2C-Group A solution requires an additional 230 kV line to link the 230 kV circuits on the west and east sides of the Mississippi River. The 138 kV loop north of the Amite South interface is also looped into the 230 kV transmission system to limit flows from Willow Glen. The Industrial Renaissance Load Profile increases the estimated cost of projects associated with Scenario 1C-Group A to $303 million, up from $261 million.

Group B: Ninemile 3, 4 and 5; Michoud 2 and 3

Similar to Scenario 2C-Group A, the increased load projection caused new violations along the 230 and 138 kV transmission lines between Baton Rouge and New Orleans. The Scenario 2C-Group B solution requires an additional 230 kV line to link the 230 kV circuits on the west and east sides of the Mississippi River. The 138 kV loop north of the Amite South interface is also looped into the 230 kV transmission system to limit flows from Willow Glen. The Industrial Renaissance Load Profile increases the estimated cost of projects associated with Scenario 1C-Group B to $552 million, up from $419 million.

Group C: Nelson Unit 4

When compared to the solution set in Scenario 1C, the Scenario 2C requires an increased amount of reactive support in the Lake Charles area.

A 230 kV line from Richard to Lake Charles Bulk—near Nelson—provides for increased import capability from the east, and mitigates very high contingent loading on the 138 kV system underlying the 500 kV line from Richard to Nelson. Capacitor banks at Lake Charles Bulk 230, Port Acres Bulk 230, and Michigan 230 provide voltage support.

The Industrial Renaissance Load Profile increases the estimated cost of projects associated with Scenario 1C-Group C to $133 million, up from $118 million. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Group D: Sabine Units 1 and 2 or Sabine 3

Due to the increased load profile from the industrial Renaissance, the WOTAB load pocket import limit is encountered with less VLR generation reduction. Due to the import limitations, the Sabine units 1 and 2 were studied separately from the Sabine Unit 3 as in Scenario 1.

Scenario 2C-Group D consisted of the Sabine 1 and 2 or Sabine Unit 3. With the reduction of 420 MW of generation from Sabine units 1 and 2 (or Sabine Unit 3 on its own), the WOTAB pocket suffers from import issues from the north and east. The system also requires more transmission capability to get power into the demand-heavy Sabine area. Low voltage issues exist around the Port Acres 230 kV area, along with the 138 kV system to the southwest of Sabine.

The partial solution set for Sabine 1 and 2 after the industrial load growth costs approximately $416 million. It includes approximately 40 miles of 500 kV line and 100 miles of new 230 kV line, along with new substations and necessary transformers. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Group E: Sabine 4

Due to the increased load profile from the industrial Renaissance, the WOTAB load pocket import limit is encountered with less VLR generation reduction. Due to the import limitations, the Sabine units 4 and 5 were studied separately and do not directly compare with the results in Scenario 1C.

Scenario 2C-Group F consisted of the Sabine Unit 4. With the reduction of 530 MW of generation from Sabine Unit 4, the WOTAB pocket suffers from limited import capability from the north and east. The system also requires more transmission capability to get power into the demand-heavy Sabine area. Low voltage issues exist around the Port Acres 230 kV area, along with the 138 kV system to the southwest of Sabine.

The partial solution set for Sabine 4 after the industrial load growth costs approximately $455 million. It includes approximately 40 miles of 500 kV line and 120 miles of new 230 kV line, along with new substations and necessary transformers. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Group F: Sabine 5

Due to the increased load profile from the industrial Renaissance, the WOTAB load pocket import limit is encountered with less VLR generation reduction. Due to the import limitations, the Sabine units 4 and 5 were studied separately and do not directly compare with the results in Scenario 1C.

Scenario 2C-Group D consisted of the Sabine unit 5. With the reduction of 450 MW of generation from Sabine unit 5, the WOTAB pocket suffers from limited import capability from the north and east. The system also requires more transmission capability to get power into the demand-heavy Sabine area. Low voltage issues exist around the Sabine 230 kV area.

The partial solution set for Sabine 5 after the industrial load growth costs approximately $400 million. It includes approximately 40 miles of 500 kV line and 100 miles of new 230 kV line, along with new substations and necessary transformers. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Group G: Lewis Creek 1 and 2

Group E consisted of the Lewis Creek units 1 and 2. With a reduction of 520 MW of generation from Lewis Creek units 1 and 2, the Western pocket suffers from limited import capability, including through the Sabine area. Widespread low voltage issues exist in the pocket without the Lewis Creek units online to provide reactive power support.

When compared to the solution set in Scenario 1C-Group F, the increased load modeled in Scenario 2C-Group H requires a significant increase in import capability. In order to achieve a higher import capability additional 230 and 500 kV upgrades are required. The Industrial Renaissance Load Profile increases the estimated cost of projects associated with Scenario 1C-Group F to $967 million, up from $566 million.

Economic Evaluation (Scenario 2c): Transmission inside load pocket plus generation outside load pocket

In the scenario where no future generation is considered within MISO south load pockets, transmission portfolios were evaluated for each respective load pocket. As a result, the cost of the transmission solution portfolios is greater than the benefits realized within each respective load pocket.

Scenario Load level Generation Retirements Transmission Tested Estimated B/C Ratio
2c Industrial Renaissance Signed GIA only Approved Att. Y only Amite S: Portfolio: $333-$534M 0 – 0.26
WOTAB: Portfolio: $144M-$1.02B
Table 7.1-3: Name and Reference Needed

Scenario 2D and 3A: Industrial Load Growth, Groups of VLR Designated Units, Additional Local Generation

This scenario represents a case in which an Industrial Renaissance has taken place in Louisiana and Texas, and additional generation has been sited within the load pockets to support this increase in demand. This scenario takes the model from Scenario 2 and adds approximately 1,500 MW of generation in WOTAB, and 764MW of generation in Amite South. The site of the generation was selected based on existing infrastructure and a Request for Proposal by Entergy Inc. for the Amite South load pocket.

Scenario 2D-Group A: Waterford 1, 2 and 4; Little Gypsy 1, 2 and 3

When compared to the constraints associated with Scenario 2D-Group A, the violations are significantly reduced due to the location and magnitude of the new generation at Little Gypsy. The 760 MW unit offsets the loss of approximately 2,000 MW of generation from the Waterford and Little Gypsy VLR units. The estimated cost of the projects associated with Scenario 2D-Group A is $23.5 million, down from $303 million in Scenario 2C-Group A.

Scenario 2D-Group B: Ninemile 3, 4 and 5; Michoud 2 and 3

With respect to the Amite South interface, the Little Gypsy plant is downstream of the west to east power flow. The additional generation at Little Gypsy reduces the flow across the Amite South tie lines and reduces the solution requirements. However, with respect to the DSG load pocket, the generation is upstream and has no effect on the binding constraints into the load pocket. The Scenario 2B and 2C constraints are nearly identical, with slight alterations in the severity. The estimated cost of the projects associated with Scenario 2D-Group B is $327 million, down from $552 million in Scenario 2C-Group B.

Scenario 3A-Group A: Nelson 4

Group A consisted of the Nelson Unit 4. With the reduction of 500 MW of generation from Nelson Unit 4, the WOTAB pocket suffers from import issues from the east. The partial solution set for Nelson 4 after the industrial load growth and with additional generation at Nelson and Lewis Creek would cost approximately $113 million, down from $133 million in Scenario 2C-Group C. It includes approximately 60 miles of new 230 kV line and a new 230-138 kV transformer at a substation located to the east of Lake Charles. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Scenario 3A-Group B: Sabine 1, 2 and 3

Group B consisted of the Sabine units 1, 2 and 3. With the reduction of 840 MW of total generation from the 138 kV units at Sabine, the WOTAB pocket suffers from limited import capability from the north and east. The system also requires more transmission capability to get power into the demand-heavy Sabine area. Low-voltage issues exist around the Port Acres 230 kV area, along with the 138 kV system to the southwest of Sabine.

The partial solution set for the 138 kV Sabine units after the industrial load growth and with additional generation at Nelson and Lewis Creek costs approximately $490 million. Due to the WOTAB import limit in Scenario 2C, there is no direct comparison in Scenario 2C. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Scenario 3A-Group C: Sabine 3 and 4

Group C consisted of the Sabine units 4 and 5. With the reduction of 980 MW of total generation from the 230 kV units at Sabine, the WOTAB pocket suffers from limited import capability from the north and east. The system also requires more transmission capability to get power into the demand-heavy Sabine area. Low-voltage issues exist on the 230 kV and 138 kV systems around Sabine.

The partial solution set for the 230 kV Sabine units after the industrial load growth and with additional generation at Nelson and Lewis Creek costs approximately $414 million. Due to the WOTAB import limit in Scenario 2C, there is no direct comparison in Scenario 2C. The cost estimate associated with this scenario and group of VLR units does not include the projects from Table 7.1-1 of this report.

Scenario 3A-Group D:

Group D consisted of the Lewis Creek units 1 and 2. With a reduction of 520 MW of total generation from Lewis Creek units 1 and 2, the Western pocket suffers from limited import capability through the Sabine area. Significant low voltage issues exist in the pocket even with a new Lewis Creek CCGT online.

The partial solution set for Lewis Creek 1 and 2 after the industrial load growth and with additional generation at Nelson and Lewis Creek costs approximately $651 million, down from 967 million in Scenario 2C- Group G.

Economic Evaluation (Scenario 2d/3a): Transmission plus generation inside load pocket

In the following scenarios, Little Gypsy, Nelson and Lewis Creek locations where selected in collaboration with stakeholders and publicly announced Request for Proposal (RFP) to model inclusion of new generation in MISO south load pockets to compliment the transmission portfolios as a base case assumption. In conclusion, when evaluating the transmission portfolios in each respective load pocket it was established that the cost of the transmission solutions outweighs the benefits.

Scenario Load level Generation Retirements Transmission Tested Estimated B/C Ratio
2d Industrial Renaissance Signed GIA plus RFP generation in Amite S Approved Att. Y only Amite South Portfolio: $30-$294 million 0 – 0.19
3a Signed GIA plus Additional generation in Western/WOTAB plus RFP Generation in Amite S (WOTAB/Amite.S) Portfolio: $120-$625 million 0 – 0.32
Table 7.1-4: Name and Reference Needed

MISO completed the assessment to identify transmission upgrades to eliminate/minimize VLR costs under many different study assumptions (Table 7.1-5). A large number of solution ideas were developed and all transmission alternatives considered were summarized (Table 7.1-6).

Transmission solutions to reduce VLR commitments are not cost-effective. The current annual VLR costs support no more than $470 million in transmission costs, and much more than that is needed to mitigate even portions of the approximate 7,200 MW of VLR units.

MISO will continue to evaluate the solution ideas developed in every study scenario for economic benefit in the subsequent MCPS. Moving forward, MISO will continue to consider VLR cost saving benefits as it goes through their reliability and economic planning.

Table 7.1-3: VLR scenarios studied

Table 7.1-5: VLR scenarios studied

 

Table 7.1-4

Table 7.1-4.1

Table 7.1-4.2

Table 7.1-4.3

Table 7.1-4: Scenarios studied with cost

Table 7.1-6: Scenarios studied with cost