MTEP15 Book 3: Policy Landscape Studies – View All

  • 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

     
  • MTEP15 Chapter 7.2: Demand Resource, Energy Efficiency, and Distributed Generation

    Applied Energy Group (AEG) developed a 20-year forecast of existing, planned and potential demand response (DR), energy efficiency (EE) and distributed generation (DG) resources and costs for MISO. This is a refresh of the MISO 2009-2010 Demand Response and Energy Efficiency study. As compared to the 2009-2010 study, this study added the South region, provided analysis at the local resource zone (LRZ) level, adds DG, adds behavioral programs and accounts for appliance standards and programs not currently in use. This forecast meets both ongoing and emerging business needs. The industry is increasing its focus on initiatives that include DR, EE and DG in order to meet federal or state policy requirements and other enacted or emerging enviromental regulations. MISO needed to refresh its models for DR and EE and explicitly include DG for modeling of future transmission capacity as well as understand the potential and cost of these programs both internally and for its stakeholders. This forecast allows MISO to analyze the impacts related to DR, EE and DG programs for transmission planning, real-time operations and market operations (including resource adequacy). This forecast positions MISO well for Clean Power Plan (CPP) analysis as there is a greater emphasis on EE as a compliance option in the final version of the CPP. Additionally, this forecast will be incorporated into the Independent Load Forecast models. AEG received utility program data through a survey it conducted. Survey responses accounted for 93 percent of the load, and that data was supplemented with information from EIA Form 861. In this report, the Existing Programs Plus case uses existing program data for 2015 from the utility survey and assumes a small annual increase in participation in current programs through 2035. Savings are broken down by LRZ and different cases are analyzed in the full report. Preliminary summary results for the Existing Programs Plus case are:
    • Peak demand savings from DR programs are 5 percent of the baseline summer demand in 2015. This increases to 13 percent of the baseline summer demand by 2035.
      • On the residential side, appliance incentives, direct load control and whole home audits are the programs with the greatest estimated impact in the 20-year forecast.
      • On the commercial and industrial side, curtailable and interruptible, custom incentives and direct load control are the programs with the greatest estimated impact in the 20-year forecast.
    • Annual energy savings from EE and DG programs are 0.4 percent of the baseline annual energy in 2015. This increases to 5 percent of the baseline annual energy in 2035.
      • On the residential side, appliance incentives, lighting and whole home audits are the programs with the greatest estimated impact in the 20-year forecast.
      • On the commercial and industrial side, custom incentives, perscriptive rebates and retro-commissioning are the programs with the greatest estimated impact in the 20-year forecast.
      • DG is a negligible percentage of these estimates with only a 0.2 percent cumulative effect by 2035.
    • Overall, DR, EE and DG programs offset 55 percent of summer peak demand growth and 25 percent of annual energy load growth by 2035.
    Editor’s Note: Will link to full report if posted in time.
                                   
  • MTEP16 Chapter 7.3: Independent Load Forecasting

    MISO procured an independent vendor, State Utility Forecasting Group (SUFG), to develop three 10-year horizon load forecasts. SUFG provides data used to develop an independent regional load forecast for the MISO Balancing Authority (BA). The first 10-year forecast (2015-2014) was delivered in November 2014. The second 10-year forecast (2016-2025) is due November 2, 2015. SUFG produces econometric models for 15 states. The SUFG independent load forecast includes a seasonal peak forecast (summer and winter) that is MISO coincident and a coincident forecast for each of the 10 Local Resource Zones. The long-term forecast will be based on MISO Business As Usual (BAU) planning future each year. The independent load forecast will be a 50/50 forecast, meaning there is a 50 percent probability that the load will either be higher or lower than the forecasted value. The load forecast (demand and energy) for the MISO BA will be forecasted for each state, and then aggregated into each MISO Local Resource Zone (LRZ) through the use of allocation factors. The MISO BA has 36 Local Balancing Authorities (LBA). The LBAs are aggregated into ten Local Resource Zones (LRZs) (Figure 7.3-1).
    Figure 7.3-1: MISO LRZ map for planning year 2015.

    Figure 7.3-1: MISO LRZ map for planning year 2015.

    The independent load forecast is not intended to replicate or replace an individual Load Serving Entity (LSE) or Transmission Owner (TO) forecast. This is an independent and transparent approach to develop a MISO load forecast that relies on publically available data, limiting dependence on confidential or vendor data and new data requests. Each state forecast model and the associated assumptions will be made available to stakeholders, and will require no vendor-specific software. SUFG is using common industry econometric forecast data and software (Global Insight, EViews).

    Project Schedule and Deliverables

    This project is a three-year effort (Figure 7.3-2), with forecast deliverables due annually at the beginning of November 2014, 2015 and 2016. Key activities and milestones are outlined for the 2016-2025 forecast (Table 7.3-1). The scope of the 2016-2025 forecast was updated based on stakeholder feedback received in the first quarter of 2015. LRZ 10, previously a part of LRZ 9, was added in Mississippi. SUFG updated state econometric models and the conversion of the energy forecast to the peak forecast. SUFG also modeled multiple weather stations in the state econometric models, as well as improved modeling of demand response, energy efficiency and distributed generation. Finally, SUFG incorporated uncertainty in the drivers of the econometric models into the high and low forecast bands by estimating confidence intervals based on the historical variance of the drivers. MISO also made progress on a load forecast comparison between the Independent Load Forecast and the Aggregated LSEs Forecast. The objective of this comparison is to identify where the forecasts differ in order to determine if model, methodology or inputs can explain these differences. The load forecast comparison does not test whether one forecast is more accurate than the other; the goal is to understand where and why there are differences. Data inputs that explained some of the differences were identified. MISO used historical energy and demand data from 2010 to 2014 to attempt to put forecast starting points and trends in perspective. Since forecasts assume normal weather, this MISO historical data was then weather normalized so that historical data without the effects of weather would be available..
    Figure 7.3-2: Independent Load Forecasting Project high-level schedule

    Figure 7.3-2: Independent Load Forecasting Project high-level schedule

    Key Activities And Milestones Target Dates
    2016-2025 Independent Load Forecast 11/1/2015
    Stakeholder Workshop #1 – Review 2015 project plan, discuss potential improvements, load forecast comparison 1/22/15
    Stakeholder Comments Due 2/3/15
    Acquire (update) state level historical data 3/2015
    Update econometric forecasting models for each state 4/2015
    Stakeholder Workshop #2 4/23/2015
    Stakeholder Workshop #2 Comments Due 5/14/2015
    Determine allocation factors to convert state energy forecasts to each Local Resource Zone forecast 6/2015
    Review energy to peak demand conversion model for each Local Resource Zone 7/2015
    Incorporate econometric model drivers 6/2015
    Generate a 10 year annual energy forecast for each state using its econometric forecast model 7/2015
    Stakeholder Workshop #3 7/23/2015
    Stakeholder Workshop #3 Comments Due 8/6/2015
    Determine 10 year annual energy forecast for each Local Resource Zone 8/2015
    Determine 10 year seasonal peak demand for each Local Resource Zone 8/2015
    Determine MISO’s 10 year forecast for annual energy and seasonal peak demand 9/2015
    Stakeholder Workshop #4 – Review 2016-2025 Forecast results 9/17/15
    Stakeholder Comments Workshop #4 Due 10/8/15
    Independent 10 year (2015-2024) Demand and Energy forecast report completed 11/2/15
    Stakeholder Comments Due 11/13/15
    Table 7.3-1: Independent Load Forecasting Project detailed project schedule 2015.

    Project Justification

    The MISO transmission system needs to be planned such that it is prepared for changes in the resource mix caused by changing environmental regulations, commodity prices, renewable integration and economic conditions. More than 141 LSEs and approximately 41 TOs submit demand forecasts annually; each with potentially different assumptions and methodologies. Each LSE and TO uses its own parameters, making it impossible to develop a MISO region-wide load forecast based on a common set of economic conditions for scenario analysis in long-term studies. An unaccounted-for deviation in a load forecast can result in increased reliability risk from the industry reliability standard (one day in 10 years) because it is difficult — if not impossible — to understand the drivers and changes in an aggregated bottom-up, long-term forecast. A single, MISO region-wide load forecast can be viewed as a top-down approach for the region; it has the benefits of one set of assumptions, and can be used in other regional studies and future analysis. This top-down approach for load forecast fits in with MISO’s “Top Down, Bottom Up” transmission planning process. This is an alternative forecast methodology. It is not intended to replicate or replace each LSE’s or TO’s forecast process. MISO will continue to use the load forecasts provided by the LSEs and TOs in MTEP and Module E: Resource Adequacy as required by the MISO Tariff.
  • MTEP15 Chapter 7.4: EPA Regulations – Clean Power Plan Draft Rule Study

    On June 2, 2014, the U.S. Environmental Protection Agency (EPA) proposed a rule to reduce carbon dioxide (CO2) emissions from existing fossil-fired generation units. The draft rule, also known as the Clean Power Plan (CPP), included state-by-state, CO2 emissions targets based upon a set of “building blocks”. MISO’s analysis of the draft CPP encompassed three phases, each designed to provide specific insights into the potential impacts of the rule. The two overarching goals of these analyses were:
    • To inform stakeholders as they evaluate compliance options
    • To establish a framework for analysis of the final rule
    The first two phases of MISO’s study focused on the potential costs of generation capital investment and energy production based on application of the proposed rule. Numerous CO2 reduction strategies were evaluated including implementation of the EPA’s building blocks on a regional (MISO-wide) basis, as well as the application of alternative compliance strategies at the regional (MISO footprint) and sub-regional (MISO Local Resource Zone) levels. High-level takeaways from these efforts include the following:
    • Application of the EPA’s building blocks on a region-wide (MISO-wide) basis resulted in compliance costs of approximately $90 billion in net present value (NPV) over the 20-year study period, which equates to $60/ton of CO2 emissions avoided from existing fossil-fired units.
    • Application of alternative compliance strategies (for example, retiring and replacing coal units with combined-cycle gas capacity) for the MISO region as a whole, resulted in compliance costs of approximately $55 billion (20-year NPV) which translates to $38/ton of CO2 emissions avoided.
    • A similar outside-the-blocks alternative compliance strategy applied at a sub-regional level (using the MISO Local Resource Zones) resulted in compliance costs of approximately $83 billion in net present value, or $57/ton of CO2 emissions avoided. A regional compliance approach therefore results in an annual cost avoidance of approximately $3 billion compared to the sub-regional approach.
    • MISO also found that the EPA’s draft proposal could put up to 14 GW of additional coal capacity at risk of retirement in order to achieve CO2 reductions at lower compliance costs.
    Study design for Phase III was informed by the results of these initial analyses, as well as stakeholder requests for state-level modeling, inclusion of electric transmission and consideration of gas infrastructure. Phase III quantified potential power system ramifications of the CPP, such as increased cost for energy production, and impacts to generation dispatch and transmission system utilization. Potential reliability impacts were identified, along with transmission congestion trends. The study also served as a first step in developing transmission solutions to facilitate reliable and cost-effective implementation of the changes required for compliance with the CPP. The analysis tested five compliance scenarios and a reference scenario (Figure 7.5-1) to understand the impacts of how the MISO region may comply with the emissions limitations.
    Figure 7.5-1 Phase III Scenarios

    Figure 7.5-1 Phase III Scenarios

    The five compliance scenarios were modeled for three years (2020, 2025 and 2030) and three types of compliance (state-by-state, sub-regional and regional). Both economic and reliability analysis were performed, using PLEXOS and PSS/E models, respectively. Additionally, preliminary evaluation of rate versus mass emissions constraints was performed to understand these different options for compliance. High-level takeaways based on study results include:
    • State by state compliance is shown to be about $4 to $1 billion (in 20-year NPV) more expensive compared to regional (MISO-wide) compliance approach. Similarly the state approach would be about $2.5 to $11.5 billion (in 20-year NPV) more expensive than the sub-regional compliance approach.
    • Electric and gas infrastructure costs for interconnection of new or converted gas units are comparable regardless of where they are sited (closer to existing gas infrastructure versus the existing electric transmission).
    • CPP constraints significantly increase congestion regardless of compliance approach, and transmission congestion is higher under a state approach than a regional approach.
    • Multi-billion dollar transmission build-out would be necessary for reliable and cost-effective compliance in the scenarios studied, driven by the level of generation retirements and the location and type of replacement capacity.
    • Generation dispatch would change dramatically from current practices, requiring additional study to fully understand the ramifications.
    The results offer valuable insights into how the energy landscape may change as a result of carbon restrictions on the electric generation. The process of draft rule analysis also yielded valuable lessons that will shape MISO’s study of the final rule. In particular, it highlighted the value of a phased approach to analysis, which produced useful information prior to completion of the entire study. Additional lessons learned on study process and design include:
    • Stakeholder feedback throughout was essential to producing relevant outputs
    • The PLEXOS model is a good fit for analysis of the CPP, allowing for explicit modeling of constraints on CO2 emissions, as well as state-by-state compliance
    • Studying one or two compliance actions (e.g. coal retirements, renewables build-out, re-dispatch) at a time allowed for developing a better understanding of the impacts of pulling these individual compliance levers
    The draft rule analysis was a significant undertaking, based on a complex and sometimes ambiguous regulation. Though the study of the final rule will necessitate similar efforts of rule interpretation and technical analysis, MISO is well-positioned to address these challenges. Over the course of the next year, MISO will continue to work closely with stakeholders, state regulators and neighboring ISOs to understand how this regulation will change the energy landscape and to plan for its implementation.
  • MTEP15 Chapter 7.5: MTEP15 MVP Limited Review

    Analysis shows that projected benefits provided by the MVP portfolio have decreased since MTEP14, but are on par with the original MVP Review conducted in MTEP11
    The MTEP15 Multi-Value Project (MVP) Limited Review provides an updated view into the projected congestion and fuel savings of the MVP Portfolio. The MTEP15 MVP Limited Review’s business case is on par with the review of the original business case in MTEP11. Although there are reduced benefits from the MTEP14 Triennial Review, the MTEP15 Limited Review provides evidence that the MVP criteria and methodology works as expected. The MTEP15 analysis shows that projected MISO North and Central Region benefits provided by the MVP Portfolio are comparable to MTEP11, the analysis from which the portfolio’s business case was approved. The MTEP15 results demonstrate that the MVP Portfolio:
    • Provides benefits in excess of its costs, with its benefit-to-cost ratio ranging from 1.9 to 2.8; a decrease from the 2.6 to 3.9 range calculated in MTEP14
    • Creates $8.4 to $34.7 billion in net benefits (using MTEP14 benefits for all categories besides congestion and fuel savings) over the next 20 to 40 years, a decrease of up to 38 percent from MTEP14
    Decreased benefits related to the congestion and fuel savings are largely driven by natural gas price assumptions. The MTEP15 MVP Limited Review Business Case sheet is available on the MISO website. The fundamental goal of the MISO’s planning process is to develop a comprehensive expansion plan that meets the reliability, policy and economic needs of the system. Implementation of a value-based planning process creates a consolidated transmission plan that delivers regional value while meeting near-term system needs. Regional transmission solutions, or Multi-Value Projects (MVPs), meet one or more of three goals:
    • Reliably and economically enable regional public policy needs
    • Provide multiple types of regional economic value
    • Provide a combination of regional reliability and economic value
    MISO conducted its first limited MVP Portfolio review, per tariff requirement, for MTEP15. The MVP Review has no impact on the existing MVP Portfolio’s cost allocation. MTEP15 Review analysis is performed solely for informational purposes. The intent of the MVP Review is to use the review process and results to identify potential modifications to the MVP methodology and its implementation for projects to be approved at a future date.
    The MVP Limited Review has no impact on the existing MVP portfolio’s cost allocation. The intent of the MVP Review is to identify potential modifications to the MVP methodology for projects to be approved at a future date.
    The MVP Review uses stakeholder-vetted MTEP15 models and makes every effort to follow procedures and assumptions consistent with the MTEP14 analysis. Consistent with previous MTEP MVP Reviews, the MTEP15 MVP Review assesses the benefits of the entire MVP Portfolio and does not differentiate between facilities currently in service and those still being planned. Because the MVP Portfolio’s costs are allocated solely to the MISO North and Central regions, only MISO North and Central Region benefits are included in the MTEP15 MVP Limited Review.

    Economic Benefits

    MTEP15 analysis shows the MVP Portfolio creates $17.7 to $54 billion in total benefits[2] to the MISO North and Central Region members (Figure 7.5-1). Total portfolio costs have increased from $5.86 billion in MTEP14 to $6.46 billion in MTEP15. Even with the increased portfolio cost estimates and decreased gas prices from MTEP14, MVP Portfolio benefit-to-cost ratios are comparable to the original business case studied in MTEP11.
    Figure 7.5-1: MVP Portfolio economic benefits from MTEP15 MVP Limited Review with values from MTEP14 MVP Triennial Review

    Figure 7.5-1: MVP Portfolio economic benefits from MTEP15 MVP Limited Review with values from MTEP14 MVP Triennial Review

    The bulk of the decrease in benefits is due to a decrease in the assumed natural gas price forecast in MTEP15 compared to MTEP14. In addition, the MTEP16 natural gas assumptions, which will be used in the MTEP16 MVP Portfolio Limited Review, were studied and are comparable to the MTEP15 forecast. Under each of the natural gas price assumption sensitivities, the MVP Portfolio is projected to provide economic benefits in excess of costs (Table 7.5-1).
    Natural Gas Forecast Assumption Total Net Present Value Portfolio Benefits ($M-2015) Total Portfolio Benefit-to-Cost Ratio
    MTEP15 – MVP Limited Review 17,249 – 54,029 1.9 – 2.8
    MTEP11 17,875 – 54,186 2.2 – 3.2
    MTEP14 – MVP Triennial Review 21,451 – 66,816 2.6 – 3.9
    MTEP16 18,588 – 56,426 2.0 – 2.9
    Table 7.5-1: MVP Portfolio economic benefits and natural gas price sensitivities[3]

    Increased Market Efficiency

    The MVP Portfolio allows for a more efficient dispatch of generation resources, opening markets to competition and spreading the benefits of low-cost generation throughout the MISO footprint. The MVP Review estimates that the MVP Portfolio will yield $14 to $47 billion in 20- to 40-year present value adjusted production cost benefits to MISO’s North and Central regions – a decrease of up to 21 percent from the MTEP14 net present value. The decrease in congestion and fuel savings benefits relative to MTEP14 is primarily due to a decrease in the out-year natural gas price forecast assumptions (Figure 7.5-2). The decreased escalation rate causes the assumed natural gas price to be lower in MTEP15 compared to MTEP14 in years 2024 and 2029 ‑ the two years from which the congestion and fuel savings results are based.
    A decrease in the natural gas price escalation rate, decreases congestion and fuel savings benefits by approximately 39 percent in MTEP15 compared to MTEP14
    The MVP Portfolio allows access to wind units with a nearly $0/MWh production cost and primarily replaces natural gas units in the dispatch, which makes the MVP Portfolio’s fuel savings benefit projection directly related to the natural gas price assumption. A sensitivity applying the MTEP14 Business As Usual (BAU) gas prices assumption to the MTEP15 MVP Limited Review model showed a 38.6 percent increase in the annual year 2029 MTEP15 congestion and fuel savings benefits (Figure 7.5-2). Post MTEP14 natural gas price forecast assumptions are more closely aligned with those in the original business case of MTEP11. A sensitivity applying the MTEP16 BAU natural gas prices to the MTEP15 analysis shows just a slight increase in year 2029 MTEP15 adjusted production cost savings. The MVP Portfolio is solely located in the MISO North and Central regions and therefore, the inclusion of the MISO South Region to the MISO dispatch pool has little effect on MVP-related production cost savings.
    Figure 7.5-2: Breakdown of congestion and fuel savings decrease from MTEP14 to MTEP15

    Figure 7.5-2: Breakdown of congestion and fuel savings decrease from MTEP14 to MTEP15

    Distribution of Economic Benefits

    Benefit-to-cost ratios have decreased since MTEP14, yet remain comparable to the original business case in MTEP11
    The MVP Portfolio provides benefits across the MISO footprint in a manner that is roughly equivalent to costs allocated to each local resource zone (Figure 7.5-3). The MVP Portfolio’s benefits are at least 1.6 to 2.0 times the cost allocated to each zone.
    Figure 7.5-3: MVP Portfolio total benefit distribution

    Figure 7.5-3: MVP Portfolio total benefit distribution

    Going Forward

    MTEP16 will feature a Limited Review of the MVP Portfolio benefits. Each Limited Review will provide an updated assessment of the congestion and fuel savings using the latest portfolio costs and in-service dates. Beginning in MTEP17, in addition to the Full Triennial Review, MISO will perform an assessment of the congestion costs, energy prices, fuel costs, planning reserve margin requirements, resource interconnections and energy supply consumption based on historical data.
    [2] Benefits 2 through 6 are from the MTEP14 MVP Triennial Review. The next MVP Triennial Review will occur with MTEP17. [3] Sensitivity performed applying MTEP16 natural gas price to the MTEP15 congestion and fuel savings model. MTEP11 and MTEP14 values come from the MTEP14 MVP Triennial Review Report.
  • MTEP15 Chapter 8.1: Policy Studies – Interregional PJM

    MISO and PJM Interconnection, a Pennsylvania-based regional transmission organization (RTO) that shares borders with MISO, concluded an 18-month MISO-PJM Joint Coordinated Planning Study in 2014 that looked at multiple futures and 80-plus major project proposals. While the joint study did not produce any actionable results, it identified additional areas for coordination. For 2015, MISO and PJM agreed to focus their joint study on FERC Order 1000 compliance, a Quick Hits study, targeted coordinated studies and continuation of the interregional process enhancement review.

    Quick Hits

    Due to appreciable levels of market-to-market congestion, MISO and PJM decided to focus on resolving the historical congestion while helping to inform future metric and process enhancements. A near-term study to evaluate historical market-to-market congestion and find small but important fixes, dubbed Quick Hits, was introduced to stakeholders at the end of 2014. For this study, MISO and PJM analyzed historically congested market-to-market flowgates. Flowgates with significant congestion — day ahead and balancing — in 2013 and 2014 were considered as well as market-to-market flowgates that caused Auction Revenue Rights infeasibilities. MISO and PJM worked to identify valuable projects on the seam. A valuable project would relieve known market-to-market issues; be completed in a relatively short time frame; have a quick payback on investment; and not be greenfield projects. MISO and PJM coordinated with facility owners to identify the limiting equipment and potential upgrades. Limited reliability and production cost analyses were used to confirm the projects’ effectiveness in relieving congestion. The Quick Hit Study analyzed 39 market-to-market flowgates with $408 million of historical congestion between January 2013 and October 2014. The majority of the flowgates (22), accounting for $295 million of congestion, have planned or in-service MTEP or Regional Transmission Expansion Plan (RTEP) upgrades. The remaining flowgates had either no recent congestion or no recommended projects. The MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC) identified two potential Quick Hit projects for MISO and PJM to jointly evaluate.
    • Beaver Channel – Sub 49 161 kV SCADA Upgrade
    • Michigan City – LaPorte 138 kV Sag Remediation and CT Replacement
    A key finding of the study was that most of the highest cost constraints already had an MTEP or RTEP project in the works. The RTOs will continue to track these projects to ensure the congestion is addressed. The two potential projects addressing historical congestion were evaluated for approval and funding. The Beaver Channel – Sub 49 flowgate SCADA upgrade was placed in-service mid-year by the Transmission Owner. The current level of congestion seen in production cost models does not support incremental upgrades beyond the SCADA work, so no additional Quick Hit is recommended. MISO and PJM will continue to monitor the historical congestion on this flowgate. The Michigan City – LaPorte Quick Hit project is not recommended at this time because the future congestion pattern is uncertain due to a new 138 kV substation that was recently placed in-service. The new station, a tap on the Michigan City – LaPorte 138 kV line, has additional 138 kV connectivity and changes the historical congestion flows, especially on Michigan City – LaPorte, during high West to East transfers. The IPSAC will continue to monitor the congestion in this area through the targeted study below.

    Targeted Studies

    Continuing on the Quick Hits work, MISO and PJM agreed to focus on smaller, targeted study areas to address seams issues. One such area is Southwest Michigan and Northern Indiana. MISO and PJM propose to evaluate the MTEP and RTEP projects in this area to determine whether the historical congestion, seen in the Quick Hits analysis, would be fully mitigated. This analysis will also evaluate the effect of expected operational reconfigurations on the performance of planned projects and whether additional solutions are needed. Another targeted area is the Quad Cities. This study is primarily reliability driven but will include economic analysis and will determine if there are projects to supplement or replace three MTEP Appendix B projects at the border of Iowa and Illinois. MISO and PJM aim to complete all targeted study analyses by the end of 2015. Potential projects identified will be recommended for further study in 2016 in the appropriate MTEP or RTEP process(es).

    FERC Order 1000

    On December 18, 2014, FERC conditionally accepted the MISO-PJM interregional FERC Order 1000 filing, subject to a further compliance filing date of July 31, 2015. FERC rejected MISO’s proposal to eliminate cost allocation for Cross-Border Baseline Reliability Projects. FERC also noted that MISO and PJM had not addressed how public policy projects would be coordinated and cost shared. MISO, PJM, and their stakeholders collaboratively developed Joint Operating Agreement language to address all FERC compliance directives. MISO and PJM agreed to use an avoided cost methodology for cost sharing reliability and public policy interregional project types. Timely compliance filings were submitted by MISO and PJM on July 31, 2015.

    IPSAC

    In the second half of 2015, the MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC) continued discussions from 2014 on interregional metric and process enhancements. In this effort, MISO and PJM work with stakeholders to identify changes to lower or remove undue hurdles to approve interregional projects.
  • MTEP15 Chapter 8.2: Policy Studies – Interregional SPP

    The MISO-Southwest Power Pool (SPP) Coordinated System Plan (CSP) Study jointly evaluated seams transmission issues and identified transmission solutions to the benefit of MISO and SPP. This study incorporated two parallel efforts:
    • Economic evaluation of seams transmission issues
    • Assessment of potential reliability violations
    The CSP study, beginning January 2014, concluded on June 30, 2015. This chapter will provide a high-level summary of the analysis performed by MISO and SPP staff. Additional details can be found in the MISO-SPP CSP Coordinated System Plan Study Report. With approval from the Interregional Planning Stakeholder Advisory Committee (IPSAC) and the Joint Planning Committee (JPC), three potential Interregional Projects showing benefits to both MISO and SPP were recommended for regional review. The following projects will be evaluated in both the MISO and SPP regional planning processes:
    • Elm Creek to NSUB 345 kV
    • Alto Series reactor
    • South Shreveport – Wallace Lake 138 kV rebuild.
    MISO’s regional review process is underway and updates will be presented at the Planning Advisory Committee (PAC) meetings. MISO is targeting a completion date of the regional review process to be in October 2015. The scope of the regional review conducted by MISO staff can be found toward the end of this chapter. SPP’s regional review process updates will be presented at their Economic Studies Working Group (ESWG) with a target completion date in October 2015l. Upon completion of the regional review processes, potential Interregional Projects may advance to both the MISO’s and SPP’s Board of Directors for project approval and interregional cost allocation.

    Background

    As part of the pending FERC-filed MISO-SPP Joint Operating Agreement (JOA), and in an effort to enhance interregional coordination and plan transmission efficiently, MISO and SPP conducted a joint annual issues review with stakeholders. The IPSAC met on January 21, 2014, and the general consensus from stakeholders was that there are many transmission issues needing evaluation. The range of issues include:
    • Congestion
    • Integration of the MISO South region
    • Expanded market operation by SPP
    • Real-time operational issues
    • Reliability issues
    • Public policy requirements
    The JPC, during the development of the CSP scope, took into consideration those proposed issues. After further review with stakeholders the study scope was finalized in June 2014. The proposed Order 1000 interregional coordination procedures, pending at FERC, were used to guide the process for this study. Previous coordinated efforts included development of a joint future that included discussions around the uncertainty variables in a joint and common model coincident in both the MISO and SPP planning processes. This joint study provided an initial effort to enhance interregional coordination, to jointly evaluate seams transmission issues, and to identify efficient transmission solutions to the benefit of both MISO and SPP.

    Economic Evaluation and Issues Identification

    The JPC reviewed 34 transmission issues submitted by stakeholders for study consideration. In addition to the submitted transmission issues, the JPC included in the study scope an evaluation to review economic congestion utilizing historical top congested flowgates from market reports and projected congestion resulting from the joint economic model developed for this study effort. The projected congestion analysis identified the top congested flowgates based on the 2024 CSP Study model (Table 8.2-1). The flowgates were ranked using these indicators:
    1. Binding Hours — number of hours in a year the flowgate binds
    2. Shadow Price — reduced production cost for 1 MW increase of thermal rating on the flowgate
    3. Congestion Costs — flowgate shadow price multiplied by MW flow on the flowgate
    Issue Id Constraint Name Contingency
    M-1 Frederick Town AECI – Frederick Town AMMO 161 kV Lutesville – St. Francois 345 kV
    S-2 North East – Charlotte 161 kV Iatan – Stranger 345 kV
    M-5 Blue Earth – Winnebago 161 kV Lakefield Junction – Lakefield 345 kV
    M-6 Wapello 161/69 kV Transformer T1 Wapello 161/69 kV Transformer T2
    M-9 Prairie 345/230 kV Transformer T2 Prairie 345/230 kV Transformer T1
    M-10 Swartz – Alto 115 kV Baxter Wilson – Perryville 500 kV
    M-11 Reed – Dumas 115 kV Sterlington – El Dorado 500kV
    S-12 Essex – Idalia 161 kV Essex – New Madrid 345 kV
    M-13 Grimes – Mt Zion 138 kV Grimes – Ponderosa 230 kV
    S-14 South Shreveport – Wallace Lake 138 kV Dolet Hills 345/230 kV Transformer
    Table 8.2-1: MISO-SPP Coordinated System Plan Economic Issues List

    Economic Transmission Solution Development

    The historical and projected congestion analysis, combined with the issues submitted by stakeholders, guided the development of transmission solution ideas evaluated as potential MISO-SPP Interregional Projects. The solution development and evaluation focused on the set of identified congested flowgates that captured a majority of congestion costs (e.g., greater than 70 percent). RTO staff and stakeholders could propose transmission solutions to address the identified transmission issues. Solutions were solicited through the MISO-SPP IPSAC meetings. MISO and SPP staffs solicited a request for stakeholders to submit potential projects addressing congestion identified in the issues list presented at the October 7, 2014, IPSAC meeting. Stakeholders submitted a total of 39 projects addressing approximately 75 percent of the issues posted. In addition to stakeholder submissions, staff submitted 15 additional projects for consideration. A preliminary screening analysis performed on all proposed transmission solution ideas determined the solution ideas with the greatest potential that warranted further evaluation. All consolidated transmission solution ideas and all transmission solution ideas with potential value were evaluated for adjusted production cost (APC) benefits to MISO and SPP. The screening index was calculated by using results of model year 2024 of APC benefits compared to that model year’s project costs. If the screening index was at least .5 and the project provided significant benefits to both MISO and SPP, the project passed screening. These projects passed the screening process:
    • St. Francois – Fletcher 345 kV
    • St. Francois – Taum Sauk – Fletcher 345 kV
    • Walker Tap – Rivtrin 138 kV
    • Series Reactor on Alto – Swartz 115 kV
    • S. Shreveport – Wallace Lake 138 kV
    • Elm Creek – Mark Moore 345 kV
    • Elm Creek NSUB 345 kV

    Benefit-to-Cost Analysis

    To calculate an indicative benefit-to-cost ratio for proposed transmission solutions, a 20-year net present value calculation of benefits and costs was used[1]. Benefits were calculated by the change in APC with and without the proposed Interregional Project. The APC accounted for purchases and sales. The APC benefit metric was calculated for the simulated years 2019 and 2024. Benefit calculations for intermediary years used interpolation and years beyond 2024 used extrapolation. The period covered by the benefit and cost calculation was 20 years, starting with the project’s in-service year.[2] The annual costs were calculated using an average carrying cost of existing Transmission Owners in MISO and SPP. The present value calculation assumed an 8 percent discount rate (Table 8.2-2).
    Project Description NPV Project Cost (2015-M$) B/C Ratio Benefit: MISO% Benefit: SPP%
    Walker Tap ‑ Rivtrin 138 kV $48.7 1.05 117% -17%
    St Francois ‑ Fletcher 345 kV $113 .51 88% 12%
    Elm Creek – Mark Moore 345 kV $156.3* 1.03 7% 93%
    Elm Creek – NSUB 345 kV $133.8* 1.22 20% 80%
    Series Reactor on Alto – Swartz 115 kV $5.4* 4.32 86% 14%
    S Shreveport ‑ Wallace Lake 138 kV $17.7* 2.61 80% 20%
    *Denotes study level cost estimates (+/- 30%)
    Table 8.2-2: Results of Benefit-to-Cost Analysis

    Sensitivity Analysis

    After receiving input from stakeholders, the study scope included a high natural gas price, carbon price and modeling of the Sub-Regional Power Balance Constraint as sensitivities. Additional analyses were performed on projects being considered for recommendation by the JPC using the three sensitivities. The proposed Interregional Projects identified in the assessment utilizing the Business As Usual Future were evaluated using the three sensitivities to determine how the projects perform under these scenarios. Results from the sensitivities were informational only and did not have an impact on the benefit split between MISO and SPP or the final calculated benefit-to-cost ratio. With input from the IPSAC, the JPC set the high natural gas price to $8.66/MMBtu for 2024 and the carbon price to $64/ton in 2024. The potential change in APC benefits for each project are the results of a one-year analysis utilizing the 2024 model (Table 8.2-3). As an example, the High Natural Gas Price Sensitivity indicated that the benefits attributed to the project Series Reactor on Alto – Swartz would increase by 43 percent if the gas price was set to $8.66/MMBtu.
    Project Description % Change in APC Benefits (MISO and SPP combined)
    High Natural Gas Price Carbon Tax SRPBC
    Series Reactor on Alto – Swartz 115 kV +43% +37% +73%
    S Shreveport ‑ Wallace Lake 138 kV -79% -58% -39%
    New Elm Creek – Mark Moore 345 kV +52% -62% -7%
    New Elm Creek – NSUB 345 kV +54% -67% -7%
    Table 8.2-3: Sensitivity Analysis Results

    Reliability Assessment

    The reliability assessment in this scope included multiple studies. This multi-faceted approach allowed MISO and SPP to evaluate various transmission issues near the MISO-SPP seam. The phases of the reliability assessment included in the CSP study were:
    • Review of reliability projects near the seam, identified in the respective regional planning processes of MISO and SPP, to determine if there were interregional alternatives to the currently proposed transmission solutions
    • A steady-state assessment using jointly developed powerflow models consistent with reliability processes used by each region
    • A dynamics assessment to test system stability using a light load powerflow case
    Solutions to address the identified reliability issues were developed and reviewed in coordination with the respective regional planning processes. These solutions, which may include alternative projects that more effectively mitigate identified issues, were submitted by:
    • Respective RTO staff
    • Stakeholders through regional planning processes
    • Stakeholders through MISO-SPP IPSAC meetings
    Transmission solutions to address identified reliability issues were evaluated to determine the most efficient and cost-effective method for the identified constraints. Projects addressing reliability issues were also evaluated for potential economic benefits to MISO and SPP. The projects identified to address the identified reliability issues were not found to provide substantial economic benefit to MISO or SPP in the context of this study scope.

    Steady State Contingency Analysis

    An N-1 contingency analysis was conducted using a joint powerflow model. The joint model merged the most recent powerflow cases used in the MISO and SPP regional planning processes. Specifics of the model development process can be found in the MISO-SPP Coordinated System Plan Study Report.

    Issues Assessment

    MISO and SPP staff compared criteria used in their respective regional planning processes to develop a methodology for use in the CSP study. Criteria used to determine the potential violations were:
    • Monitored
      • Facilities 100 kV and above in the MISO and SPP footprints
      • Thermal overloads greater than 100 percent
      • Base case voltages below .95 pu
      • Contingency voltages below .90 pu
      • More stringent local planning criteria
    • Contingencies
      • Full N-1
      • MISO and SPP Category B contingencies submitted by stakeholders
    MISO and SPP jointly performed separate base-case (N-0) and contingency (N-1) analyses that provided a list of potential thermal and voltage violations (Table 8.2-4; Figure 8.2-1).
    Needs Overall Unique MISO System SPP System
    Overloads 50 18 14 4
    Low Voltages 84 34 31 3
    Table 8.2-4: Steady-state thermal and voltage issues
    MISO and SPP jointly performed separate base-case (N-0) and contingency (N-1) analyses that provided a list of potential thermal and voltage violations. The results were compared and verified. Engineering judgment was used to filter out issues not electrically close to the seam. This initial issues list was provided to stakeholders along with a request for potential solutions to address the potential violations. After stakeholder feedback and additional validation was completed a final issues list was created (Table 8.2-4; Figure 8.2-1).
    Figure 8.2-1: Map of steady-state thermal and voltage issues

    Figure 8.2-1: Map of steady-state thermal and voltage issues

    MISO and SPP requested stakeholders submit any potential solutions that could address any of the listed issues. Staff received 12 project submissions from stakeholders. In addition to stakeholder-submitted projects, MISO and SPP staff leveraged previously identified regional projects from the MTEP and ITP processes, respectively. MISO and SPP analyzed these regional projects to determine if they addressed the issues identified in the CSP. MISO and SPP evaluated projects to determine:
    • If benefit was provided to both MISO and SPP
    • If thermal overloads were solved to under 100 percent
    • If base case voltages were solved to within applicable planning criteria
    • If contingency voltages were solved to within applicable planning criteria
    • If interregional solutions were more cost effective than MISO and SPP regional projects
    The transmission solution evaluation phase of the steady state assessment did not yield any Interregional Projects that were more cost-effective or efficient than previously identified regional solutions.

    Dynamic Assessment

    The dynamics assessment utilized a joint model developed from MISO’s and SPP’s regional models in a similar approach to the joint model used for the steady-state assessment. A 2019 light-load case was developed in an effort to highlight seasonal transient instability issues most likely to occur. MISO and SPP selected areas to be monitored that were adjacent to the MISO-SPP seam (Table 8.2-5).
    SPP Areas MISO Areas
    515 SWPA 645 OPPD 333 CWLD 600 XEL
    520 AEPW 650 LES 356 AMMO 635 MEC
    523 GRDA 652 WAPA 360 CWLP 615 GRE
    536 WERE 608 MP 327 EES-EAI
    540 GMO 613 SMMPA 332 LAGN
    541 KCPL 620 OTP 351 EES
    542 KACY 661 MDU 502 CLEC
    544 EMDE 627 ALTW 503 LAFA
    546 SPRM 633 MPW 504 LEPA
    640 NPPD 694 ALTE
    Table 8.2-5: Areas modeled in Dynamics Assessment
    The study used POM-TS’s Fast Fault Screening (FFS) Tool to determine disturbances. The POM-TS FFS takes a single set of contingencies (N-1) and determines a severity ranking index (RI) and a critical clearing time (CCT). The ranking index takes into account kinetic energy, torque and voltage deviations to determine a score. A shorter clearing time and higher severity index score indicate a more severe disturbance. Contingencies resulting in a CCT of less than nine cycles to clear were chosen for further evaluation. Study results showed that no instability was found for the simulated events. All machines were stable with good oscillation damping and bus voltages were within tolerances. Detailed results of the disturbances can be found in the MISO-SPP Coordinated System Plan Study Report.

    Review of Regional Projects

    MISO and SPP staff reviewed reliability projects from their respective regional processes. No regional projects of either RTO were identified as replacing the need for a project in the other respective regional process. Additionally there were no regional projects that could be replaced by an Interregional Project.

    No-harm Test on Economic Projects

    Interregional projects identified to address congestion were evaluated to ensure they do not create reliability issues. The evaluation may result in the modification of the Interregional Project or identification of additional interregional facilities that are needed to mitigate the projected reliability issue. After the conclusion of the no-harm evaluation for the four economic projects considered, it was determined that no new reliability issues were identified due to the inclusion of the economic projects and that no mitigations were needed. In addition to running each of the tested projects individually, they were analyzed as a group and again no new reliability issues were identified due to the inclusion of the projects as a group.

    Recommended Interregional Projects

    Based on the results of the economic assessment, MISO and SPP identified three projects for consideration as potential Interregional Projects:
    • Elm Creek to NSUB 345 kV
    • Alto Series reactor
    • South Shreveport – Wallace Lake 138 kV rebuild
    Each of these projects individually demonstrate benefit to both MISO and SPP as well as APC benefits that exceed the costs of the projects over the initial 20 years of the project life.

    Interregional Cost Allocation

    As agreed to by MISO and SPP, and accepted by FERC, MISO and SPP used the APC benefit metric to allocate the costs to each planning region of proposed Interregional Projects addressing primarily economic congestion. If the recommended Interregional Projects are approved by both the MISO and SPP Board of Directors, the costs will be allocated between MISO and SPP (Table 8.2-8).
    Project E&C Cost M$ MISO Cost % SPP Cost %
    Elm Creek – NSUB 345 kV $140.7 20% 80%
    Alto Series Reactor 115 kV $5.3 86% 14%
    S. Shreveport – Wallace Lake 138 kV Rebuild $18.5 80% 20%
    Table 8.2-8: Interregional cost allocation for potential MISO-SPP Interregional Projects

    Regional Review Process Results

    Editor’s Note: this information will be included at a later date as analysis is ongoing.

    FERC Order 1000

    On February 19, 2015, the MISO-SPP interregional FERC Order 1000 filing was conditionally accepted at FERC, subject to a further compliance filing date of August 18, 2015. FERC directed MISO and SPP to propose a cost allocation methodology for interregional transmission facilities addressing regional transmission needs driven by public policy. FERC also directed MISO to adopt SPP’s proposed methodology of using a combination of avoided cost and adjusted production cost benefits for interregional transmission facilities addressing regional reliability needs. MISO, SPP and their stakeholders collaboratively developed language to address all FERC compliance directives. The updated Joint Operating Agreement language was filed on August 18, 2015. MISO and SPP agreed to use an avoided cost plus adjusted production cost methodology for reliability driven Interregional Projects and to use an avoided cost methodology for public policy driven Interregional Projects. MISO and SPP maintained the previously accepted adjusted production cost methodology for economically driven Interregional Projects.
    • Alto Series reactor
    • South Shreveport – Wallace Lake 138 kV rebuild
    Each of these projects individually demonstrate benefit to both MISO and SPP as well as APC benefits that exceed the costs of the projects over the initial 20 years of the project life.

    Interregional Cost Allocation

    As agreed to by MISO and SPP, and accepted by FERC, MISO and SPP used the APC benefit metric to allocate the costs to each planning region of proposed Interregional Projects addressing primarily economic congestion. If the recommended Interregional Projects are approved by both the MISO and SPP Board of Directors, the costs will be allocated between MISO and SPP (Table 8.2-8).  
    Project E&C Cost M$ MISO Cost % SPP Cost %
    Elm Creek – NSUB 345 kV $140.7 20% 80%
    Alto Series Reactor 115 kV $5.3 86% 14%
    S. Shreveport – Wallace Lake 138 kV Rebuild $18.5 80% 20%
    Table 8.2-8: Interregional cost allocation for potential MISO-SPP Interregional Projects

    Regional Review Process Results

    Editor’s Note: this information will be included at a later date as analysis is ongoing.

    FERC Order 1000

    On February 19, 2015, the MISO-SPP interregional FERC Order 1000 filing was conditionally accepted at FERC, subject to a further compliance filing date of August 18, 2015. FERC directed MISO and SPP to propose a cost allocation methodology for interregional transmission facilities addressing regional transmission needs driven by public policy. FERC also directed MISO to adopt SPP’s proposed methodology of using a combination of avoided cost and adjusted production cost benefits for interregional transmission facilities addressing regional reliability needs. MISO, SPP and their stakeholders collaboratively developed language to address all FERC compliance directives. The updated Joint Operating Agreement language was filed on August 18, 2015. MISO and SPP agreed to use an avoided cost plus adjusted production cost methodology for reliability driven Interregional Projects and to use an avoided cost methodology for public policy driven Interregional Projects. MISO and SPP maintained the previously accepted adjusted production cost methodology for economically driven Interregional Projects.
    [1] There is not a B/C ratio requirement in the CSP study. [2] Initially MISO and SPP have made the assumption that the in-service date for all projects is 2024. [3] There is not a B/C ratio requirement in the CSP study. [4] Initially MISO and SPP have made the assumption that the in-service date for all projects is 2024.
  • MTEP15 Chapter 8.3 MISO/ERCOT Study Scope

    A collaborative effort between MISO and ERCOT is in progress with the purpose of understanding each system’s unique transmission issues along the seam. The potential benefits of joint planning will be evaluated with transmission solutions that efficiently address the identified issues. An economic evaluation will identify solutions that benefit both systems, and the effort will include an assessment of potential reliability violations. The scope of the collaborative effort is in a preliminary stage with an unspecified timeframe.        
  • 8.4 Southeastern Regional Transmission Planning

    The SERTP process consists of the following FERC-jurisdictional sponsors:
    • Duke Energy (Duke Energy Carolinas LLC and Duke Energy Progress Inc.)
    • Louisville Gas and Electric Co. and Kentucky Utilities Co. (LG&E/KU)
    • Ohio Valley Electric Corp. (OVEC), including its wholly owned subsidiary Indiana-Kentucky Electric Corp.
    • Southern Co. Services Inc. (Southern)
    • Dalton Utilities
    • Georgia Transmission Corp. (GTC)
    • Municipal Electric Authority of Georgia (MEAG)
    • PowerSouth
    • Associated Electric Cooperative Inc. (AECI)
    • Tennessee Valley Authority (TVA)
    Throughout 2015, MISO and SERTP collaborated on meeting the directives from the January 23, 2015, FERC Order related to FERC Order 1000 interregional transmission planning. Additionally, Section X of MISO’s Attachment FF describes the coordination procedures for interregional transmission coordination with SERTP. This collaboration and the work completed to date are described in more detail below.

    FERC Order 1000

    On January 23, 2015, FERC conditionally accepted the MISO-SERTP FERC Order 1000 interregional transmission planning compliance filing, subject to further compliance filing. MISO and the SERTP companies requested and were granted a 90-day extension to June 22, 2015. MISO and the SERTP parties collaborated and came to agreement on tariff language to address the FERC directives, which was circulated to MISO and SERTP stakeholders. For cost allocation, MISO and SERTP will use an avoided cost methodology that accounts for reliability, economic and public policy benefits. On June 22, 2015, MISO and SERTP filed their compliance filings to FERC, which included redlined and clean tariff versions of Attachment FF as well as transmittal letters from both regions.

    Interregional Coordination

    MISO and SERTP have tariff requirements requiring interregional transmission coordination as described in Section X of Attachment FF of MISO’s Tariff. This includes a meeting at least once per year to facilitate interregional coordination procedures although meetings may occur more frequent. At least annually, MISO and the SERTP will exchange their most current regional transmission plans including power-flow models and associated data used in the regional transmission planning processes. This exchange typically occurs during the first calendar quarter of each year. Additional transmission-based models and data may be exchanged between the SERTP and MISO as necessary and if requested. The data will be posted on the pertinent regional transmission planning process’ websites, consistent with the posting requirements of the respective regional transmission planning processes, and subject to the applicable treatment of confidential data and Critical Energy Infrastructure Information (CEII). At least biennially, MISO and the SERTP will meet to review the respective regional transmission plans. Such plans include each region’s transmission needs as prescribed by each region’s planning process. This review will occur on a mutually agreeable timetable, taking into account each region’s regional transmission planning process timeline. If, through this review, MISO and the SERTP identify a potential interregional transmission project that may be more efficient or cost-effective than regional transmission projects, the Transmission Provider and the SERTP will jointly evaluate the potential interregional transmission project pursuant to Section X.C.4 of Attachment FF of MISO’s Tariff. In 2015, MISO and the SERTP sponsors met on several occasions. The first meeting was a conference call on January 22, 2015, where MISO and SERTP reviewed each other’s regional processes and timelines. MISO and SERTP exchanged ideas on how data can and will be shared between the regions for interregional coordination. In the latter part of 2015, once NDA/CEII’s are in place, data exchange will occur. The data used for the purposes of interregional coordination will be posted to each of the respective regional transmission planning process websites. In early 2016, MISO and the SERTP companies will meet to discuss each other’s regional transmission plans to determine if there may be interregional transmission projects that are more cost-effective or efficient than regional projects. If potential interregional transmission projects are identified through the review of the regional transmission plans, MISO and SERTP will jointly evaluate those projects pursuant to the processes outlined in Section X.C.4 of Attachment FF of MISO’s Tariff.    
  • 8.5 Mid-Continent Area Power Pool

    No interregional studies were performed in MTEP15 with the Mid-Continent Area Power Pool (MAPP). Northwestern Energy, the sole FERC jurisdictional member in MAPP, will join Arkansas-based Southwest Power Pool (SPP) in October 2015, removing FERC Order 1000 interregional compliance obligations with MAPP. MISO, Northwestern Energy and SPP filed FERC Order 1000 comments articulating this point on May 1, 2015. Per the filing, “MISO shall monitor developments in MAPP and continue to collaborate with the remaining MAPP members as part of MISO’s open and transparent planning process.”