Minnesota Electric Transmission Planning

Chapter 6 contains information on each of the present and reasonably foreseeable future inadequacies identified in the six transmission zones. First, for each zone, a table of present inadequacies is presented. The table is ordered by when the inadequacy was first identified, so the older inadequacies are listed first. Following the table of inadequacies, a discussion of each pending project, by Tracking Number, is provided. Finally, a table of completed projects is included.

For each transmission planning zone, the discussion begins with a table that looks like this.

MPUC Tracking Number
The first column in the table is labeled “MPUC Tracking Number.” Each inadequacy is assigned a Tracking Number. This numbering system was created in 2005 and has been utilized in every report since. The Tracking Number has three parts to it: the year the inadequacy was first reported, the zone in which it occurs, and a chronological number assigned in no particular order. Tracking Number 2015-NE-N10, for example, indicates this matter is first reported in the 2015 Report and is an inadequacy in the Northeast Zone. An inadequacy with a Tracking Number beginning with 2017, on the other hand, was first identified in the 2017 Report.

MISO Project Name
The second column contains the MISO Project Name for each project. This is the name used in the pertinent MTEP Report for that project. In some cases, for projects that were first identified in earlier years and are still under development, the MISO Project Name may not be exactly the same as the name given in an earlier biennial report, but the project is the same.

MTEP Year & Appendix
The third column contains a reference to a MTEP Report and an Appendix in the report. The MTEP Report is prepared annually by MISO, and each utility that is a member of MISO must participate in the MTEP process. Each report is referred to by the year it is adopted. Thus, the most recent report is MTEP23, although it won’t be finally approved by MISO until the end of the year. Additional information about the MISO planning process and the MTEP reports is included in section 3.3.1 of this Biennial Report, and an explanation of how to find a particular MTEP Report and an Appendix is provided in subsection 6.2.

MTEP Project Number
The fourth column of the table provides a Project Number assigned by MISO for each project. This Project Number is important for finding a particular project in the appropriate MTEP Report. The only utility reporting transmission needs in this biennial report that is not a member of MISO is Minnkota Power Cooperative, and all the MPC projects are in the Northwest Zone. The other non-MISO utilities are East River Electric Power Cooperative (EREPC), and L&O Power Cooperative (L&O), but these utilities are not reporting any transmission needs in this report.

As shown in the table in section 6.3.1, the Minnkota Power Cooperative projects are shown to be “Non-MISO” projects in column three of the table of Needed Projects. Nonetheless, several of these “Non-MISO” projects do include an MTEP Project Number in column four. The reason for this is even though Minnkota is not a MISO member. MISO performs some of Minnkota’s transmission planning work.

Certificate Of Need (CON)
The MPUC rules state the biennial report shall contain an approximate timeframe for filing a CON application for any projects identified that are large enough to require a CON.18 This column provides a simple “Yes” or “No” indication of whether a CON is required. If a CON has already been applied for, the MPUC Docket Number for that filing can be found in the discussion for that particular project. If a Docket Number is given, that docket can be checked to determine whether the CON has already been issued by the Commission.

Non-wires Alternative
This column provides a “Yes” or “No” indication as to whether a non-wires alternative is potentially viable for the identified inadequacy. Section 2.7 of this Report provides a summary of the types of non-wires alternatives able to address certain categories of inadequacies. Where a non-wires alternative was considered, further discussion of the alternative is included in the narrative provided for that particular project.

In the 2005, 2007, and 2009 Biennial Reports, the utilities provided a separate subsection for each pending project by Tracking Number and included certain information about each project. In the 2011 and 2013 Report, those discussions were eliminated because the Commission had understandably authorized the utilities to rely on the MTEP Reports to provide all the necessary information regarding each project, because transmission facility approval was being conducted by and through MISO.

In 2014, as part of its approval of the 2013 Biennial Report, the Commission determined perhaps the MTEP Reports did not satisfy one requirement of the state statute to “identify [in the biennial report] general economic, environmental, and social issues associated with each alternative.”19 The utilities did not object to providing that information in the 2015 Report, but would raise the caveat that for many of the projects, particularly those several years into the future, detailed information is often not available at this stage of development of the project. Also, for many smaller projects, like replacing a transformer, there are no likely alternatives available and not much information is available.

To assist the Commission, and other readers of the report, the utilities have included in this Biennial Report a separate discussion of various matters relating to each project, even though nearly all that information can be found in the MTEP Reports. As part of this discussion, the utilities provide available information on the general impacts associated with the project. In those cases where a certificate of need or a routing permit or both have been applied for, or even granted, most of this type of information is available in the records created in those dockets, and a reference to the MPUC Docket Number is provided. Any reader desiring in-depth information about a project that has been approved or is being considered by the Commission can review the record in that matter for more detailed information.

The table for Completed Projects is similar to the table for Needed Projects described above.

Most of the columns contain the same information provided for the ongoing projects. However, the last column provides the date the project was completed, and the second column contains a more precise description of the project than just the MISO title. If a certificate of need or a route permit or both were required from the Commission, the docket numbers are provided in the last column. While the last column is entitled “Date Completed,” in some cases the project is being removed from the list because the need once perceived is no longer present, and the project is being withdrawn. Readers interested in more information about a completed project can consult earlier Biennial Reports, the MTEP Report, or the MPUC Docket, whichever are applicable.

Because nearly all the projects identified in this Report are being undertaken by utilities that are members of MISO, this subsection is provided to assist the reader in finding information about the MISO planning process and the annual MTEP Report prepared each year. Much of the information provided in this subsection was also available in the 2013, 2015, 2017, 2019, and 2021 Biennial Reports.

The MTEP process is ongoing at all times at MISO. Generally, utilities submit a list of their newly proposed projects in September. MISO staff evaluates these projects over the next several months, and prepares a draft of the annual MTEP Report around July of the following year. After review by utilities and other interested parties, the MISO board of directors approves the report, usually in December. The process continues with another report finalized the following December. The MTEP23 Report should be approved by the MISO Board of Directors in December of this year.

Each of the MTEP Reports separates transmission projects into two categories and lists them in Appendices as follows:

Generally, as projects are first identified, they are listed in Appendix B, and then they move up to Appendix A as they are further studied and ultimately brought forth for construction. Some projects never advance to the final stage – Appendix A – of actually being approved and constructed.

The MTEP Report is an excellent source of information about ongoing transmission studies and projects in Minnesota and throughout a wide area of the country.

For each zone, a table is included to describe certain information about each project by Tracking Number. The table looks like this (MPUC Tracking Number 2019-NE-N17 is used for illustrative purposes):

MPUC Tracking Number 2019-NE-N17 is the Running Capacitor Bank Retirement Project. The project can be found in Appendix A of the MTEP19 Report by following these steps:

Similar steps can be followed for all other projects identified in Chapter 6, including those few that are not Appendix A projects (recommended by MISO for approval). If the MTEP Report you are seeking is an older one, you may have to click on Study Repositories to find these other reports at Step 2.

Project Facilities
Appendices A and B also contain information on the specific facilities (such as transmission lines, substations, etc.) that are part of a particular project. The steps below show how to find this information for the example project.

Step 1. To find information on specific facilities (transmission lines, substations, etc.) that are part of a project click on the “Facilities” tab located at the bottom of the spreadsheet that was downloaded at Step 5 in the above example.

Step 2. Hold down the “Ctrl” key and hit the “F” key to bring up the “Find” dialog box. Enter the MTEP Project Number, “16145” in this example, in the dialog box and then click on “Find Next.” The “Find Next” link can be clicked until all rows containing information about Project Number 16145 have been found. There will usually be more than one row since most projects involve more than one transmission line or substation or other facility.

This same procedure can be used to find this kind of information for other projects and their associated facilities for the projects listed in the tables in Chapter 6 using the MTEP Report and the MTEP Project Number.

Detailed Project Information
Starting in 2008, if the project has been either approved or recommended for approval by the MISO board of directors (i.e., designated an Appendix A project), additional, more detailed information about the project can be found in Appendix B in the MTEP Report for the year the project was approved by MISO. For large projects, this information includes a project map, project justification and information about the system inadequacy the project is intended to correct. For smaller projects, a subset of this information is included. Starting with the MTEP08 Report, projects located in Minnesota are contained in the “West Region Project Justifications” portion of Appendix A or Appendix B in the MTEP Report year that the project was approved or recommended for approval. For information on Minnesota projects approved by MISO prior to 2008, see the appropriate year Minnesota Biennial Transmission Projects Report for the appropriate year.

Continuing with our example of the Running Capacitor Bank Retirement Project, Tracking Number 2019-NE-N17, which is an approved Appendix A project, this additional information can be found by going to Appendix B through the following steps.

Step 1. After following the first three steps described above to get to the appropriate MTEP report, click on the MTEP19 Appendices link.

Step 3. Once the desired Appendix B is downloaded, use the .pdf search tool to find Project Number 2019-NE-N17and locate information about this project.

This same procedure can be used to find more detailed information on most projects shown in the tables in Sections 6.3 through 6.8 that have moved to MISO Appendix A since 2008. In addition, if you search for a specific utility’s name, you can find information on projects that utility has submitted and have been or are being considered for approval by the MISO board of directors.

Specific Utility Projects
One additional useful tool with the MTEP Reports is the ability to find projects an individual utility has submitted to MISO. Also, the Appendices can be sorted to show all projects for a particular utility, (or, depending on the version of Excel you are using, a group of utilities). To do this, select the most recent MTEP Appendix A Status Report,20 click on the down arrow located in the column D heading “Geographic Location by TO Member System,” and then select the code for the individual utility you are interested in from the drop-down list. (NOTE: some versions of Excel will allow you to select multiple utilities).

It is also possible to sort other columns in the Appendices in a similar manner. For example, only projects or facilities in Appendix A can be identified by clicking on the arrow in Column A and selecting the desired choice from the drop-down list.

The following table provides a list of transmission needs in the Northwest Zone. As explained in Section 6.1.1, even though Minnkota Power Cooperative is not a member of MISO, some of its planning work is done by MISO. A MTEP Project Number is provided for those Minnkota projects reported in the MTEP reports.

Utilities: Minnkota Power Cooperative (MPC) & Otter Tail Power Company (OTP)

Project Description: A suite of 115 kV projects including a second Winger 230/115 kV transformer in 2023, a new 230/115 kV substation (Lake Ardoch), including one new 230/115 kV transformer, tapping the existing Drayton-Prairie 230 kV line and associated new transmission to the Oslo 115 kV switching station in 2024, and a 115 kV line from Lake Ardoch to Oslo. Depending on future load growth, a potential second Winger-Plummer 115 kV line and associated substation expansions may also be needed sometime after 2028. This was previously called “The Winger-Thief River Falls 230 kV Line Project.” Automatic Under Voltage Load Shedding (UVLS) will be added to ~100 MW of peak demand in the area.

Need Driver: The Northwestern Minnesota area is a developing hub of crude oil pipelines, and those pipelines require pumping stations. These pumping stations are served by a network of 115 kV lines with three 230 kV sources at Drayton, Grand Forks and Winger. Loss of any one source forces the load to be served from the remaining two sources. Additionally, loss of any transmission between Drayton, Grand Forks and Winger weakens the reliability of the Northwest Minnesota transmission system. The automatic UVLS is needed to mitigate N-1-1 issues.

Analysis: Reliability improvements from the previously mentioned projects were evaluated in the “2018 NW MN Timing Analysis,” which was performed by OTP with support from MPC. The study showed that a fault on one of the 115 kV lines into Northwest Minnesota from the three 230 kV sources caused violations within Northwest Minnesota. The study demonstrated a final upgrade requirement of several new 230 kV sources between 2021 and 2028.

Schedule: The 230/115 kV transformer addition at Winger is expected to be completed in early 2024. The Lake Ardoch – Oslo 115 kV line and associated substations are expected to be completed by the end of 2024. The associated UVLS has been implemented. A Certificate of Need is not expected to be filed in Minnesota unless load growth warrants the construction of the second Winger – Plummer 115 kV line.

General Impacts: The area where this project will occur is almost entirely rural. There are no notable sites or locations along the route of any new transmission line between the endpoints. Any new transmission line will likely have to navigate through some wetlands and avoid some lakes along any route. There may be some impact on farmland from the location of a new transmission line, but assuming a one-hundred-and-thirty-foot right-of-way and some general estimates on electrical poles and farm equipment navigation, of a project area of 741 acres, only 65 acres will actually be impacted.

The economic and social impacts will be slight for any project to address this situation. The project may require a temporary project crew to construct the equipment, which could bring some business to the area in the form of room and board. Some landowners may receive a financial payment as a result of this project. Finally, the project will improve the reliability of the system in the area, although it is difficult to measure the quantified value of improved reliability.

Project Description: The scope and schedule of the project has changed to increase reliability to a larger number of area loads.

A new 69 kV line from Richwood Distribution Substation to Oakland Distribution Substation (with conversion of White Earth distribution substation onto the 69 kV system) has been deemed necessary sometime in the future. The proposed project includes 20.0 miles of transmission line work (all new line) and a potential conversion of White Earth 41.6 kV to 69 kV. Previously, this project contained additional transmission in the Erie and Audubon areas; however, that has been moved to project 2019-NW-N5 for administrative purposes.
Need Driver: In response to a neighboring system’s request, a new transmission line and substation conversion are being planned for the White Earth Substation. The intent is to transfer load off their system that has grown beyond available back-up capacity. Additionally, a member cooperative has requested service improvements for Richwood and Oakland Substations.

Analysis: Reliability impacts from the new transmission lines are currently evaluated in the annual MTEP assessments (in terms of forecasting the existing White Earth load). Impacts to the bulk power system are not the reason for these projects. Limitations of the 41.6 kV transmission and member systems are the reason for the transmission projects (and load transfers).

Schedule: The study efforts mentioned above determined that the new transmission lines do not have a strict completion date. A schedule will be developed as definite plans are determined.

General Impacts: This project is primarily rural in location. The route will have to navigate around some lakes, forested areas, and potentially some reservation land within the area. Assuming a one-hundred-foot right-of-way, the project area will be nearly 275 additional acres (some existing transmission may be used for the project), but the affected farmland should only be about 15 acres, assuming some general estimates on electrical poles and farmland equipment navigation. No notable environmental, human, or health concerns exist beyond the aforementioned new transmission. This project is still in its early stages of planning, so all of this information is subject to change.

This project may require a short-term project crew. If so, this may bring some business to the area in the form of room and/or board. In terms of local government benefits, it is possible that permit costs may be enforced on this project, but this is determined on a case-by-case basis. Also, some landowners may receive income as a result of this project, and the income may be taxable.

This project is the result of a reliability measure, and will probably not have a substantial or lasting impact on the community in terms of the environment or health. It will likely impact some farmland; however, it should only amount to about 15 acres, as stated in the environmental considerations.

Project Description: This project consists of a new Erie 230/115 kV substation that will tap the existing Audubon to Hubbard 230 kV line. The 115 kV side of the Frazee substation will be rebuilt to a ring bus configuration to accommodate a new 115 kV line from Erie. Approximately 9 miles of 115 kV line will be constructed between the new Erie substation and the Frazee substation. A 30 MVAr capacitor bank will be installed at the Frazee substation.

Analysis: The Erie – Frazee project was determined to be the most reliable and cost-effective solution for addressing existing reliability issues and facilitating growth in the transmission system.

Schedule: The Erie – Frazee project is planned to be in-service by winter 2023.

General Impacts: The project will require approximately 9 miles of new 115 kV transmission line from the Erie Junction substation to the Frazee substation. The project is located in predominantly agricultural lands. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design is along existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 9 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas. The MPUC’s environmental assessment was issued May 14, 2021. The MPUC issued the route permit for this project in October 2021.

Project Description: From the planned Erie Jct. 230/115 kV substation which taps the Audubon-Hubbard 230 kV line, a new 69 kV or 25 kV 7-mile line with associated transformer will be constructed to MPC’s Erie distribution substation.

In order to provide alternate service to MPC’s Audubon distribution substation, an optional conversion of OTP’s Oak Lake-Erie Jct. 41.6 kV line may be converted to 69 kV. This line is part of a previous project (2015-NW-N7) and there is some overlap between these projects.

Need Driver: There is about 10 MW of load in the Detroit Lakes, MN area served by one substation (Erie) on the OTP 41.6 kV system. Extended outage times have been required for planned maintenance and emergency repairs because no alternate source is available. This is a concern for the Detroit Lakes, MN area. Low load management signals are also a concern.

Analysis: Reliability impacts from the new transmission lines are currently evaluated in the annual MTEP assessments (in terms of forecasting the existing Audubon and Erie area loads). Impacts to the bulk power system are not the reason for these projects. Limitations of the 41.6/69 kV transmission and member systems are the reason for the transmission projects (and load transfers).

Schedule: This project is budgeted for completion in 2024 to coincide with the construction of the Erie Jct. load tap (2009-NW-N2). A schedule will be developed as definite plans are determined.

General Impacts: This project is primarily rural in location. The route will have to navigate around some lakes, forested areas, and potentially some reservation land within the area. Assuming a one-hundred-foot right-of-way, the project area will be nearly 121 additional acres (some existing transmission may be used for the project), but the affected farmland should only be about 7 acres, assuming some general estimates on electrical poles and farmland equipment navigation. No notable environmental, human, or health concerns exist. This project is still in its early stages of planning, so all of this information is subject to change.

Need Driver: Installation of two-line termination breakers were necessitated to prevent faults on Henning – Inman 230 kV line or Henning – Silver Lake 230 kV line from tripping off entire substation.

Analysis: Installation of breakers at the existing substation is the best value plan that would enhance reliability in all areas that are served by the Henning 230/41.6 kV substation.

General Impacts: This project is located on GRE owned property. Construction is expected to be completed in 6 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Add a 230 kV breaker at the Inman substation on the line to Wing River.

Need Driver: This project was needed to prevent faults on the Inman – Wing River 230 kV line from tripping off the 230/115 kV transformer.

Project Description: Install storm structures in the Cormorant – Pelican Rapids 115 kV line.

Need Driver: GRE is continuing to look at making the system more resilient. GRE has H-frame construction on multiple lines that have shown to be prone to line cascading (domino effect) resulting in long duration outages. One way is to limit the damage of cascading is to install stop structures, such as a storm structure. GRE is proposing to install storm structures that will limit damage from cascading to 5 to 10-mile sections rather than without storm structures, whereby significantly longer mileage of damage could occur.

General Impacts: The project will be constructed on the existing 115 kV transmission line from Cormorant substation to Pelican Rapids substation. The project is located in predominantly agricultural lands. Construction is expected to be completed in 2 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Build new dead-end structure to re-terminate the Maynard Tap - Willmar line to a southern position at the Willmar sub to accommodate GRE’s substation reconfiguration

Need Driver: Projected needed to address multiple N-2 low voltage and thermal violations in the area.

General Impacts: The project will be constructed on the existing 115 kV transmission line from Maynard Tap to Willmar substation. During construction Xcel and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Replace existing 230/41.6 kV transformer with a new 56 MVA unit, install 2-41.6 kV breakers with switches and move existing transformer for use as a spare.

Need Driver: A spare unit for this voltage class is needed for continued reliable service to the area. The existing Silver Lake transformer will be used as a spare and the new transformer will be installed in its place. The addition of two-line termination 41.6 kV breakers is needed to prevent tripping at the Silver Lake substation during line faults.

Analysis: The spare transformer will enable GRE to promptly address transformer failures, aligning with GRE's strategy to maintain a spare transformer for every voltage class that serves loads.

Need Driver: The existing line has a low composite reliability grade and is overdue for replacement due to its age and deteriorating condition. This transmission line has historically experienced congestion issues, impeding the integration of renewables into the transmission system. The rebuild will boost capacity, ensuring a reliable service and creating opportunities for interconnection or transfer of renewables within the transmission system.

Analysis: The line rebuild project is intended to address the historical reliability issues stemming from the line's age and condition. Furthermore, the increased capacity of the new line will enable interconnection of renewable resources into either the distribution or transmission systems, addressing previous congestion concerns.

General Impacts: The project will be constructed on the existing 115 kV transmission line from Cormorant Junction switch to Tamarac substation to Pelican Rapids substation. The project is located in predominantly agricultural lands. Construction is expected to be completed in 6 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

The table below identifies projects that have been completed since our 2021 report.

The following table provides a list of transmission needs identified in the Northeast Zone by MISO utilities. There were no projects identified in this zone by non-MISO utilities.

Project Description: Add a second 230/115 kV transformer at the Hilltop Substation and upgrade an existing line from 115 kV to 230 kV between the Arrowhead and Hilltop substations.

Need Driver: Reliability and load growth in the Duluth area. Retirement of local generators on the 115 kV system. Maintaining sufficient 230/115 kV transformer capacity for load serving in the Duluth area during a maintenance outage of one of the existing Arrowhead 230/115 kV transformers or following certain single contingency events.

Analysis: In 1993, Minnesota Power constructed a new 230 kV substation (the Hilltop Substation) in Duluth. This project involved the rebuilding of existing 115 kV lines for 230 kV operation in order to provide a single 230 kV source to the Hilltop Substation and upgrades of several unshielded 115 kV lines to improve reliability. As part of the application for the Hilltop Project MP laid out long range plans which identified the future need for a second 230 kV source to the Hilltop Substation once Duluth load dictated its need. The Commission recognized this future need and approved rebuilding of portions of the unshielded 115 kV lines as part of the Hilltop Project for future 230 kV operation.

Because Minnesota Power anticipated this future need, a relatively minimal amount of transmission line and substation construction will be required to implement the Duluth 230 kV Project when it becomes needed. Due to the configuration of the existing Duluth area transmission system, the Duluth 230 kV Project is expected to be the most cost effective and least environmentally impactful solution to this pending inadequacy. Other transmission alternatives would require longer 230 kV line construction and the establishment of a new substation site, increasing social, environmental and economic impacts associated with construction of such a project. Operational changes that limit through-flow on the Duluth-area 115 kV system have proven helpful in delaying the need for this project, as discussed below. The Duluth Loop Reliability Project (2019-NE-N12) will include incremental improvements at the Arrowhead and Hilltop Substations, such as a larger 230/115 kV transformer and a 230 kV breaker at Hilltop and sectionalization of the Hilltop 230 kV line at Arrowhead. These incremental improvements are expected to further delay the need for the more significant expansion of Duluth-area 230/115 kV transformer capacity that would be achieved with the Duluth 230 kV Project.

Schedule: Slower than anticipated load growth, external system improvements such as the Arrowhead-Stone Lake-Gardner Park 345 kV Line, and operational flexibility provided by the phase shifting transformer at the Stinson Avenue Substation in Superior, Wisconsin, have delayed the need for the Duluth 230 kV Project for many years. Based on recent studies indicating a need for improved reliability and capacity of Duluth-area 230/115 kV transformers in the first half of the 2020s, Minnesota Power has included incremental improvements at the Arrowhead and Hilltop Substations as part of the Duluth Loop Reliability Project (2019-NE-N12). The underlying system drivers behind the timing of the incremental improvements included with the Duluth Loop Reliability Project are related to the impact of a number of transitional changes in the nearby North Shore Loop transmission system and changing regional transfers in and through the Minnesota Power system. These incremental improvements will shift the primary need drivers for the Duluth 230 kV Project back to local Duluth-area load growth or retirement of the dispatchable generators at the Hibbard Renewable Energy Center, likely delaying the need for the Duluth 230 kV Project to the late 2020s or even into the 2030s.

General Impacts: The Duluth 230 kV Project will make optimal use of an existing transmission line that was designed for future conversion for 230 kV operation and existing substations designed with space in or adjacent to the existing footprint to accommodate additional 230 kV connections. Since the Duluth 230 kV Project is using existing substations, transmission line corridors and rights-of-way, it is anticipated that no new landowners would be impacted by the project. The Duluth 230 kV Project is needed to maintain adequate power delivery capability from the transmission system to the Duluth area in light of local generator retirements, regional transfers, load growth, and economic development. Therefore, the project contributes to the realization of significant environmental, social, and economic benefits associated with these contributing factors. Minnesota Power’s approach to this issue is intended to ensure that the most appropriate solution (in terms of cost and human and environmental impacts) is implemented at the most appropriate time to meet the reliability and capacity needs of Minnesota Power’s customers.

HVDC Modernization Project
Formerly Square Butte – Arrowhead HVDC Valve Hall Replacement

Project Description: Replace the existing Center (Square Butte) and Arrowhead high voltage direct current (HVDC) converter stations and associated assets with modern equipment. To modernize the terminals of the existing Square Butte HVDC Line and implement the latest VSC HVDC technology, new buildings and electrical infrastructure need to be constructed on a new site near the existing HVDC terminals. In Minnesota, to connect the new HVDC terminal to the existing AC system, the Project would require the construction of a new St. Louis County 345 kV/230 kV substation located less than one mile west of the current Arrowhead Substation. The new HVDC terminal would be connected to the St. Louis County Substation by less than one mile of 345 kV transmission line and the new St. Louis County Substation would be connected to the existing Arrowhead Substation by two parallel 230 kV transmission lines less than one mile in length. Additionally, a short portion of the existing ±250 kV HVDC Line in Minnesota will need to be reconfigured to terminate at the new HVDC terminal. Similar modifications will take place near the existing Center HVDC terminal in North Dakota.

Need Driver: The HVDC Modernization Project is needed to modernize aging HVDC assets, continue to position the transmission grid for clean energy transition, and improve the reliability of the transmission system. The existing HVDC terminal has operated for 45 years—15 years beyond its 30-year design life. In recent years Minnesota Power has experienced HVDC terminal outages due to failures in the control system, power electronics, transformers, and other components. Based on experience with other electric system components, the failure rate is expected to increase, which is of particular concern for the existing HVDC system because of limited parts availability. The orderly replacement of the HVDC terminal equipment is prudent to ensure continuous efficient delivery and expansion of Minnesota Power’s renewable, carbon-free energy resources into the future.

In addition to the replacement of the existing HVDC terminals, the new voltage source converter (VSC) HVDC technology implemented for the Project will be designed to provide key reliability attributes including voltage regulation, frequency response, blackstart capability, and bidirectional power transfer capability. These modernizations to the HVDC technology will enable Minnesota Power and the region to continue to support its clean energy transition.

Analysis: The HVDC Modernization Project will modernize aging assets that are critical to the reliable delivery of renewable energy to Minnesota Power’s customers, improve the reliability of the transmission system and thoughtfully position for continued clean energy system transformation. Under the “Do Nothing” alternative, failure rates of the existing HVDC Converter Station equipment are anticipated to increase, resulting in outages that impact the reliable and efficient delivery of Minnesota Power’s North Dakota wind energy and result in direct cost impacts to Minnesota Power’s customers and reliability impacts to the regional transmission system. As these outages increase in frequency and duration, the cost and reliability impacts will continue to grow. With no viable plan to modernize the existing HVDC converters, Minnesota Power would immediately need to determine if it were prudent to invest in relatively short-term fixes to keep the HVDC Line operating on a limited basis or to move on from the HVDC Line entirely and begin to develop alternative AC transmission solutions.

Under the “AC Alternative” the alternative AC transmission solutions required to facilitate continued delivery of Minnesota Power’s zero fuel cost North Dakota wind energy, mitigate system impacts caused by the retirement of the HVDC Line, and replace the grid support provided by the VSC HVDC converters would come at a substantially higher cost and with greater human and environmental impacts than the HVDC Modernization Project. Given that the AC Alternative would need to include multiple regional-scale 345 kV transmission lines, there would likely be prolonged exposure to outages of the HVDC Line during the 10 or more years it would take to develop these projects. At some point during that time, it may become impossible to continue operating the HVDC Line at its full capacity, leading to extended outages and associated impacts to Minnesota Power’s customers and regional reliability.

Were Minnesota Power to choose to invest in relatively short-term fixes to keep the HVDC Line operating on a limited basis, these fixes would result in significant risk of stranded investment as the regional transmission system develops. The “Technology Alternative” including targeted replacements of the existing control system, converter transformers, and thyristor valves could serve to keep the existing LCC HVDC system running for several more decades at its existing capacity. These replacements would not bring the additional grid-supporting attributes associated with VSC technology, and therefore additional investments in STATCOMs, synchronous condensers, or other solutions may become necessary as the clean energy transition continues to challenge the historical operating conditions of the grid. As MISO continues to advance proactive long-range transmission planning solutions to position the grid for the future of clean energy, VSC HVDC solutions will inevitably begin to play a major role in the regional grid. At that point, Minnesota Power’s short-term investments in keeping its existing LCC HVDC system may have to be replaced before the end of their useful asset life by a VSC HVDC upgrade similar to the Project in order to continue reliable operation of the Square Butte HVDC corridor and provide the best value for Minnesota Power’s customers and the region.

The HVDC Modernization Project is the only prudent solution to limit cost impacts to Minnesota Power’s customers in the near-term from increased exposure to HVDC outages, avoid substantial additional long-term cost for alternative projects to address reliability issues created by retirement of the HVDC Line, and align with opportunities to efficiently provide long-term bulk power transfer and grid support solutions for Minnesota Power and the region.

Schedule: Minnesota Power filed a combined Certificate of Need and Route Permit Application for the HVDC Modernization Project on June 1, 2023 [Docket Nos. E015/CN-22-607 and E015/TL-22-611]. It is anticipated that construction of the Project will begin in Q4 2024, with the expected Project in-service date between December 2028 – April 2030.

General Impacts: The modernization of Minnesota Power’s HVDC converter stations is a prudent and necessary activity to ensure the ongoing operation of this critical piece of transmission infrastructure for Minnesota Power’s customers, including the reliable delivery of Minnesota Power’s substantial North Dakota wind generation assets.
The HVDC Modernization Project is also a critical component of Minnesota Power’s efforts to leverage existing infrastructure to efficiently maintain the current load, gain additional access to renewable resources for customers, and keep momentum for reaching the state’s goal of 100 percent carbon-free energy by 2040. The Project innovatively proposes flexible design options to allow for future expansion and additional renewable energy transfer capability, leveraging the unique attributes of VSC HVDC technology—the most efficient way to transfer power over long distances. In addition to the replacement of the existing HVDC terminals, the new Voltage Source Converter (“VSC”) HVDC technology implemented for the Project will be designed to provide voltage regulation, frequency response, blackstart capability, and bidirectional power transfer capability, all of which will enable Minnesota Power and the region to continue to support its clean energy transition reliably. All of this will be implemented in a relatively small geographic area near the existing Arrowhead 230 kV Substation, limiting human and environmental impacts by leveraging the existing site and contiguous lands to the greatest extent possible.

HVDC 900 MW Transmission Line Upgrades
Formerly Square Butte – Arrowhead HVDC Upgrade

Project Description: Upgrade the capacity of the existing Square Butte – Arrowhead HVDC transmission line from 550 MW to 900 MW, generally by replacing existing structures with taller structures and reconductoring a short segment of line.

Need Driver: Transmission Service Requests (TSRs) have been filed with MISO for additional capacity to facilitate increased renewable energy transfers on the HVDC Line following the completion of the HVDC Modernization Project (Tracking No. 2013-NE-N16).

Analysis: Minnesota Power has assessed the capacity limitations associated with the existing HVDC Line and found that the total capacity of the HVDC Line may be reasonably increased from 550 MW to a maximum of 900 MW following completion of the HVDC Modernization Project (Tracking No. 2013-NE-N16). To achieve the higher capacity, upgrades would be needed at various locations along the length of the 465-mile HVDC transmission line. These upgrades are expected to include replacing existing structures with taller structures to increase conductor-to-ground clearance at a higher operating temperature, as well as replacement of a short segment of smaller conductor in North Dakota. Leveraging the opportunity to incrementally increase the capacity of the HVDC Line following completion of the HVDC Modernization Project provides an efficient solution for facilitating the interconnection and long-distance delivery of additional high-capacity renewable energy resources to Minnesota Power’s customers.

Schedule: At the request of Minnesota Power, MISO updated Transmission Service Request (“TSR”) System Impact Studies on varying levels of increased HVDC capacity in 2022-2023 and provided Facilities Studies documenting the costs assigned to the TSRs. Upon execution of a Facilities Construction Agreement (“FCA”) for the upgrades necessary to provide the requested incremental transfer capability, Minnesota Power will begin to implement the HVDC transmission line upgrades. Construction is anticipated to take place in phases over 4-5 years to limit HVDC Line outage impacts. The earliest potential completion date for the project is 4Q 2028.

General Impacts: The additional capacity facilitated by the HVDC 900MW Transmission Line Upgrades Project will facilitate increased wind development in North Dakota, more efficient market operation, and system reliability enhancements for both North Dakota and Minnesota. Since the project is anticipated to take place within the existing transmission line right-of-way, it is anticipated that no new landowners would be impacted by the project.

Project Description: Expand planned Iron Range 500 kV Substation to include two 1200 MVA 500/345 kV transformers and extend a double circuit 345 kV line from Iron Range to the existing Arrowhead 345 kV Substation.

Need Driver: When paired with the Great Northern Transmission Line (Tracking Number 2013-NE-N13), the Iron Range-Arrowhead 345 kV Line was found by MISO in the Manitoba Hydro Wind Synergy Study to facilitate significant regional benefits associated with the synergies between wind and hydroelectric generation resources. However, the near-term needs for incremental export capability from Manitoba to the United States were realized by the development of the Great Northern Transmission Line Project alone, without a 345 kV extension to Arrowhead. Because there were not sufficient transmission service requests to justify the 345 kV connection to Arrowhead at the time, Minnesota Power determined that it would not pursue construction of the Iron Range-Arrowhead 345 kV Project in the foreseeable future. Should the project become necessary in the future due to additional transmission service requests or other system reliability needs or regional transmission benefits – such as those currently being evaluated in the MISO Long Range Transmission Plan (LRTP) Study – it will be advanced at that time based on its own merits.

Analysis: Minnesota Power and Manitoba Hydro’s analysis of the transmission necessary to enable 883 MW of incremental Manitoba-United States transfer capability identified that the Iron Range-Arrowhead 345 kV Line was not needed or economically justified at the time to achieve the desired level of Manitoba Hydro export.

Schedule: Minnesota Power has no current plans to construct the Iron Range-Arrowhead 345 kV Project.

General Impacts: The optimization of the new Manitoba to United States interconnection that allowed for deferral of the Iron Range-Arrowhead 345 kV Line provided benefit to Minnesota Power’s ratepayers, local landowners, and the region by implementing a right-sized solution for the current need and avoiding extraneous transmission line construction. Should future additional transmission service requests or other regional transmission system needs justify construction of the Iron Range-Arrowhead 345 kV Line, the project could reasonably be expected to build upon the already-substantial social, economic, and environmental benefits provided by the Great Northern Transmission Line Project.

Project Description: The Little Falls Substation Modernization Project involves replacing aging equipment, structures, and civil works and correcting deficiencies at the existing Little Falls 115/34 kV Substation in an effort to improve substation safety and reliability for the foreseeable future. Multiple substation asset renewal needs will be combined with necessary distribution transformer upgrades and a reconfiguration of the existing 115 kV bus to move a line-connected transformer to a bus-connected configuration to make up the core of this project. This work at the Little Falls Substation was combined into one project in order to facilitate efficient coordination of engineering and construction.

Need Driver: The Little Falls Substation serves the City of Little Falls and the surrounding rural areas. The primary need driver for the Little Falls Substation Modernization is age and condition of existing transformers, distribution circuit breakers, disconnect switches, and site infrastructure. While transmission circuit breakers have been replaced in recent years, much of the remaining original equipment in this substation is nearing or beyond the end of its useful life, including many of the structures and foundations. In addition to these asset renewal concerns, the project will also address previously-identified low voltage concerns for the Little Falls area. Low voltage was identified at the Pepin Lake, Blanchard, Bellevue, and Little Falls Substations following contingency events involving the Little Falls 115 kV bus. These contingency events result in loss of the existing Little Falls capacitor bank plus all but one of the 115 kV lines serving the substation and will be resolved by transitioning a line-connected transformer to a bus-connected configuration.

Analysis: Across Minnesota Power’s system there are many transmission-to-distribution substations that require age-related upgrades. Much of the original equipment in these substations is nearing or beyond the end of its useful life. Minnesota Power’s Substation Modernization (Asset Renewal) Program involves coordinated replacement of end-of-life assets and holistic modernization improvements designed to extend the lives of these substations for the next several decades. The Program takes a holistic, site-by-site approach to facilitating the coordinated and efficient modernization of many aging substations throughout Minnesota Power’s system. In developing the scope for the Little Falls Substation Modernization Project, Minnesota Power considered the near-term and long-term needs of the area transmission and distribution system as well as the age and condition of existing site infrastructure and modern design standards for safety, accessibility, and maintainability. The resulting project involves significant improvements to equipment and infrastructure at the site, which is expected to ensure the site remains viable and continues to reliably serve Minnesota Power’s customers for many decades to come.

The low voltage issue was first identified in the MTEP15 assessment and has continued to show up in MTEP and Minnesota Power studies. The addition of a bus tie breaker at the Little Falls Substation was originally submitted as a potential Corrective Action Plan. However, further investigation of protective relaying and historical fault events in the area has proven that a more appropriate solution would be to change the connection point for one of the Little Falls 115/34.5 kV transformers so that it is not directly connected to the Little Falls – Blanchard 115 kV line. This reconfiguration will eliminate the potential low voltage concern at a reasonable cost and without degrading the reliability of the Little Falls Substation. The reconfiguration of the transformer connection will be packaged with the planned substation modernization project for the Little Falls Substation in order to realize efficiencies in engineering and construction.

Schedule: The project is currently planned as a multi-year project and has been prioritized behind nearer-term needs in the area, including Long Prairie and Verndale. Civil and site work is expected to begin in 2025, with above-grade construction taking place in stages for 1-2 years after that to manage outage and constructability constraints.

General Impacts: The Little Falls Substation Modernization Project will ensure a continuous and reliable power supply to the Little Falls area by replacing aging equipment before it fails and by resolving known post-contingent voltage issues. At present, it is expected that the impacts will be entirely contained within the existing Little Falls Substation yard and no expansion area will be necessary.

Project Description: Increase rating of Hibbing – Virginia 115 kV Line (25 Line). The project also includes rebuild, reconductor, and switch replacements in the vicinity of the existing Minntac Tap.

Need Driver: Post-contingent overloads under higher transfer scenarios and multiple-circuit contingency events, as well as age and condition of existing 25 Line structures and hardware.

Analysis: This issue has been identified in MTEP and in several Minnesota Power studies. The upgrade project provides the needed capacity increase as identified in the studies while also efficiently addressing asset renewal needs along the length of the line and particularly at the Hibbing substation termination.

Schedule: The project is currently planned for phased construction beginning in 2021 and continuing through 2031.

General Impacts: The 25 Line Upgrade Project will provide necessary system improvements and asset renewal on Minnesota Power’s 115 kV system without requiring the establishment of additional transmission line corridors.

Project Description: The Long Prairie Substation Modernization Project involves replacing aging electrical equipment, structures, and civil works, and correcting deficiencies at the Long Prairie 115/34 kV Substation in an effort to improve substation safety and reliability for the foreseeable future. Multiple substation asset renewal needs will be combined with necessary distribution transformer upgrades (replacing with higher-capacity load-tap changing transformers) to make up the core of this project. The work at the Long Prairie Substation was combined into one project to facilitate efficient coordination of engineering and construction.

Need Driver: The Long Prairie Substation serves Long Prairie and the surrounding rural area. The primary need driver for the Long Prairie Substation Modernization Project is age and condition of existing transformers, circuit breakers, disconnect switches, and site infrastructure. Much of the original equipment in this substation is nearing or beyond the end of its useful life, including many structures and foundations. In addition, these asset renewal concerns, the project will address previously-identified distribution reliability concerns including post-contingent overloading of the existing Long Prairie transformers and low post-contingent 34.5 kV bus voltage following 115 kV bus fault events.

Analysis: Across Minnesota Power’s system there are many transmission-to-distribution substations that require age-related upgrades. Much of the original equipment in these substations is nearing or beyond the end of its useful life. Minnesota Power’s Substation Modernization (Asset Renewal) Program involves coordinated replacement of end-of-life assets and holistic modernization improvements designed to extend the lives of these substations for the next several decades. The Program takes a holistic, site-by-site approach to facilitating the coordinated and efficient modernization of many aging substations throughout Minnesota Power’s system. In developing the scope for the Long Prairie Substation Modernization Project, Minnesota Power is considering the near-term and long-term needs of the area transmission and distribution system as well as the age and condition of existing site infrastructure and modern design standards for safety, accessibility, and maintainability. The resulting project involves significant improvements to equipment and infrastructure at the site, which is expected to ensure the site remains viable and continues to reliably serve Minnesota Power’s customers for many decades to come.

The Long Prairie Substation Modernization Project will provide firm capacity and improved voltage regulation to the 34.5 kV distribution feeders out of Long Prairie. This will allow MP to take an outage on one of the two transformers to perform maintenance work without having to transfer load to another substation. Reconfiguring the line-connected distribution transformer would eliminate outages on the transmission line when a fault occurs on the distribution system. In considering whether or not non-wires solutions such as distribution-connected generation or demand side management presented a viable alternative to the project, Minnesota Power considered the fact that the assets involved in the replacement project would need to be replaced due to age and condition within the next 5-10 years anyway. Since the non-wires solutions would not eliminate the need for age and condition based replacements, the replacement project was ultimately determined to be the only viable long-term solution.

Schedule: The project is currently planned as a multi-year project with construction taking place in stages from 2021-2023 to manage outage and constructability constraints.

General Impacts: The Long Prairie Substation Modernization Project will ensure a continuous and reliable power supply to the Long Prairie area by increasing transformer capacity, improving voltage regulation, and replacing aging equipment before it fails. Per the scope discussed above, the impacts will be entirely contained within the existing Long Prairie Substation yard and no expansion area will be necessary.

Project Description: Replace existing 230/115 kV transformer at Badoura substation. Add 230 kV line breakers.

Need Driver: Age and condition of Badoura transformer. Transformer is also non-standard and there is no direct system spare. Post-contingent overloads following multiple-circuit contingency events in the surrounding area.

Analysis: The Badoura 230/115 kV transformer is non-standard for Minnesota Power’s system, as it consists of an external 115 kV voltage regulating transformer rather than an internal load tap changer. The transformer is also nearly 60 years old. The project will replace it with a new standard-sized 230/115 kV transformer, for which Minnesota Power maintains a system spare. Studies have indicated that the voltage regulation from the transformer is not necessary and therefore the new transformer will be procured without load tap changers. Additionally, there are no breakers at the Badoura 230 kV Substation, which creates difficulties with relaying and contingencies that cause large parts of the area between Riverton and Park Rapids to lose critical transmission connections. Installing breakers will mitigate issues associated with these contingencies and provide for better protection of the transmission lines and transformer. Post-contingent overloads on the Badoura 230/115 kV Transformer were first identified in the MTEP18 2023 winter peak case.

General Impacts: The Badoura Transformer Replacement Project will ensure a continuous and reliable power supply to a large area of the Minnesota Power transmission system between Riverton and Park Rapids by replacing aging, non-standard equipment before it fails and by improving system protection through the addition of breakers. The Project will make use of space available inside the existing Badoura 230/115 kV Substation, as all modifications associated with the project will take place within the existing substation fence-line.

Project Description: Establish a high capacity, networked connection between the Embarrass Substation and the Mesaba Junction Switching Station by either acquiring and rebuilding 6 miles of existing customer-owned 115 kV transmission or constructing approximately 4 miles of new 115 kV transmission south from the existing Babbitt Tap to the Mesaba Junction 137 Line Extension.

Need Driver: Reliability for important load-serving substations in the Babbitt Area, as well as redundancy, voltage support, and transmission capacity to the Hoyt Lakes area and the North Shore Loop to support existing customers and enable load growth.

Analysis: The Babbitt Area 115 kV Project will connect two radially-operated transmission lines that are critical sources to the Babbitt area and provide an additional redundant connection to the North Shore Loop transmission system. The project will enhance the reliability of the Babbitt 115/46 kV Substation, which is a critical load-serving substation for Minnesota Power and Great River Energy customers in the Tower, Ely, and Babbitt areas, by networking the radial line that currently is the only source to the Babbitt Substation. The project will also build upon previous improvements from the Mesaba Junction 137 Line Extension (2021-NE-N14) to enhance redundancy and flexibility for the industrial load pocket in the Babbitt area, which requires near-constant availability of power. In doing so, the project makes optimal use of existing transmission line assets that are underutilized when operated as a radial system, taking advantage of the asset renewal improvements from the 137 Line Rebuild (2021-NE-N15) which are made possible by the Mesaba Junction 137 Line Extension Project (2021-NE-N14).

The Babbitt Area 115 kV Project also continues to support redundancy and power delivery enhancements for the Hoyt Lakes area and the North Shore Loop by establishing an additional transmission source to the Mesaba Junction Switching Station. Much has changed about how the North Shore Loop transmission system is operated following transition of local coal-fired baseload generators to retirement or idling over the last 5+ years. As the use of the system by existing customers in the Hoyt Lakes area and the North Shore Loop evolves over time, incremental long-term improvements like the Babbitt Area 115 kV Project will continue to become necessary to support the reliable operation of the system. The additional 115 kV source from Embarrass into the Mesaba Junction Switching Station established by this project prevents potential voltage collapse and transmission line overload concerns associated with loss of the Forbes – Mesaba Junction and Laskin – Mesaba Junction 115 kV lines, and therefore the project is crucial to enabling the long-term maintenance of these transmission lines in the area.

Schedule: The Babbitt Area 115 kV Project cannot be implemented until both the Mesaba Junction 137 Line Extension (2021-NE-N14) and the 137 Line Rebuild (2021-NE-N15) are constructed. Based on the anticipated schedule for those projects, preliminary plans are for project construction to take place in 2030-31.

General Impacts: The Babbitt 115 kV Project will ensure a continuous and reliable power supply to Minnesota Power and Great River Energy customers in the Tower, Ely, and Babbitt areas, as well as a nearby industrial load pocket. Establishing a high-capacity networked Embarrass – Mesaba Junction 115 kV Line (137 Line) enhances reliability to the local area and also allows for the continued reliable delivery of power into the North Shore Loop and the Hoyt Lakes area under a range of normal and maintenance conditions, effectively continuing to replace transmission system support previously provided by nearby baseload coal units as the system continues to evolve into the future. Utilizing most or all of existing 137 Line to complete this new connection makes optimal use of existing transmission assets while minimizing human and environmental impacts associated with establishing the new transmission connection.

Project Description: Construct approximately 14 miles of new 115 kV transmission between the existing Hilltop, Haines Road, and Ridgeview substations. Some existing 115 kV transmission lines in the area will be reconfigured and upgraded. At the existing Ridgeview Substation, the substation yard will be expanded to accommodate a new 115 kV ring bus with 4 new 115 kV circuit breakers and a new transmission line entrance. At the existing Haines Road Substation, a 115 kV circuit breaker will be added to an existing transmission line entrance. At the existing Hilltop Substation, the substation yard till be expanded to accommodate a new 115 kV line entrance, the existing 230/115 kV transformer will be replaced with a larger-capacity transformer, a new 230 kV circuit breaker will be added, and four existing 115 kV circuit breakers will be replaced. At the existing Arrowhead Substation, a new 230 kV transmission line entrance will be constructed. The existing Hilltop 230 kV tap will be disconnected from the Arrowhead – Iron Range 230 kV Line (98 Line) and extended approximately 0.7 miles to the new line entrance at the Arrowhead Substation. The existing Hilltop 230 kV tap transmission line will be upgraded to a higher operating temperature and existing polymer insulators will be replaced. Additional substation and transmission line components will also be replaced as part of the project due to age and condition.

Need Driver: Following conversion, idling, or retirement of coal-fired baseload generators in the North Shore Loop, there is a risk of voltage collapse during maintenance outages of 115 kV lines between Arrowhead, Haines Road, Swan Lake Road, Ridgeview, and Colbyville Substations. Loss of a second transmission line during a maintenance outage would leave this part of Duluth on a single 140-mile transmission line originating in the Hoyt Lakes Area, and the transmission system is no longer able to support the load over that distance. The Duluth Loop Reliability Project will restore redundancy and load-serving capability to this area, mitigating the risk of voltage collapse. Duluth area 230/115 kV transformer loading also increases significantly without the local baseload generators online and connected to the 115 kV system. This causes a risk of severe overloads on the existing 230 kV line and the Hilltop 230/115 kV transformer during a maintenance outage of either of the Arrowhead 230/115 kV transformers. Upgrading the capacity of the existing Hilltop 230 kV tap line and Hilltop 230/115 kV transformer will mitigate these severe overloads. Extending the Hilltop 230 kV tap line into the new line entrance at the Arrowhead Substation will greatly improve the reliability of the 230 kV source at the Hilltop Substation by reducing over 64 miles of outage exposure to the sole source to the Hilltop Substation and eliminating a breaker failure event which could simultaneously disconnect two 230/115 kV transformers in the Duluth area. This reconfiguration will also allow significant relay protection improvements to the existing Iron Range – Arrowhead 230 kV Line (98 Line) and the newly established Arrowhead – Hilltop 230 kV Line (108 Line).

Analysis: The Duluth Loop is a network of 115 kV transmission lines and substations which form two parallel connections between the main Duluth-area transmission source of power and system support (the Arrowhead 230/115 kV Substation) and the North Shore Loop (beginning at the Colbyville Substation on the far eastern end of Duluth). Many of the customers in the Duluth area are served from substations connected to the Duluth Loop.

The Duluth Loop Reliability Project meets three critical needs for the Duluth area and the North Shore Loop, as discussed below.

First, the project addresses severe voltage stability concerns by providing another transmission source to the Duluth Loop and North Shore Loop. For most transmission outages in the Duluth Loop, the loss of a second Duluth Loop transmission line during the outage would leave all or part of the Duluth Loop and the North Shore Loop on a single 140-mile transmission line originating in the Hoyt Lakes area. Without the support previously provided by the local baseload generators on the North Shore Loop, the transmission system is no longer able to support the large amount of Duluth Loop load over such a long distance and the expected result would be a post-contingent voltage collapse in the Duluth Loop and extending up the North Shore toward Two Harbors. To manage the risk of voltage collapse in real-time operations, the Regional Transmission Operator (MISO) directs Minnesota Power to open the North Shore transmission connection at Colbyville, separating Duluth from the North Shore Loop during planned outages in the Duluth Loop. This causes Duluth Loop load to be served through a single transmission path from the Arrowhead substation and load along the North Shore to be served through a single transmission path from the Taconite Harbor substation. This operational solution serves mostly to contain the problem rather than resolve it, as the loss of a second Duluth Loop or North Shore Loop transmission line would still result in loss of power for many residential, commercial, and industrial customers. Constructing a new 115 kV transmission line between the Hilltop and Ridgeview substations will replace the redundancy once provided by the local baseload generators such that there is sufficient load-serving capability to support all loads in the area and sufficient flexibility to operate and maintain the system reliably without putting customers at risk.

Second, the project provides load serving capacity to the Duluth Loop and North Shore Loop. For most transmission outages impacting the Taconite Harbor Substation, a majority of load along the North Shore is served through the Duluth Loop. For this scenario, an outage along either connection between the Arrowhead and Colbyville substations could cause significant overloads along the remaining connection. Alternately, if the North Shore Loop is intact and an outage occurs on both transmission connections between the Arrowhead and Colbyville substations, significant overloads could occur on transmission lines between the Taconite Harbor, North Shore, and Big Rock substations. Constructing a new 115 kV transmission line between the Hilltop and Ridgeview substations will provide sufficient Duluth Loop and North Shore Loop transmission capacity to prevent transmission line overloads.

Third, the project improves the reliability of Duluth area transmission sources. Two 230/115 kV transformers at Arrowhead and one at Hilltop deliver power to 115 kV transmission lines in the Duluth area from the regional 230 kV transmission network. The reliance of the Duluth Loop and the North Shore Loop on these transformers has greatly increased with the idling of North Shore Loop coal generators. The Hilltop Substation is served by a single, 72-mile, 230 kV transmission line which also connects to the Arrowhead and Iron Range substations. Extending this 230 kV transmission line approximately 0.7 miles and adding a breaker at the Arrowhead Substation will reduce line mile exposure to Hilltop from 72 miles to 8 miles, greatly improving the reliability of the sole 230 kV source to the Hilltop substation at the same time an additional 115 kV line is being brought out of it to support the Duluth Loop. The additional breaker for this line connection at Arrowhead will eliminate a single point of failure which disconnects a 230/115 kV transformer at both Arrowhead and Hilltop, likely causing overloads on the remaining Arrowhead 230/115 kV transformer. Improving the reliability of Duluth Area 230/115 kV transformers will benefit customers in the Duluth Loop and along the North Shore as reliance on these transmission sources increases with the local baseload generators offline.

Schedule: Minnesota Power submitted a combined Certificate of Need and Route Permit application to the Commission in October 2021 [Docket Nos. E015/CN-21-140 and E015/TL-21-141], which was approved in February 2023. Following permitting and engineering activities, preliminary plans are for project construction to take place in 2023-26.

General Impacts: The Duluth Loop Reliability Project is a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. Replacing redundancy, voltage support, and power delivery capability previously provided by local baseload coal units in the area and improving the reliability of an increasingly-critical transmission connection for delivery of power into the North Shore Loop enables the realization of significant economic and environmental benefits from transitioning away from these units. The proposed project will require approximately 0.7 miles of new 230 kV transmission and 14 miles of new 115 kV transmission, some of which will be double circuited with an existing transmission line. New transmission line construction will be primarily along existing transmission line corridors and utilize existing rights-of-way to the greatest possible extent to help navigate areas of Duluth with varying land use and space constraints. Minnesota Power has taken into consideration all relevant human, environmental, and commercial interests in the area and has actively engaged impacted stakeholders in routing and siting of the project.

Project Description: Replace end-of-life circuit breakers and associated equipment at National Taconite 115 kV Substation.

Analysis: Five 115 kV oil circuit breakers from 1966 will be replaced as part of this project.

Schedule: The project is presently planned for staged construction in 2021-24.

General Impacts: The National Breaker Replacements Project will replace end-of-life substation equipment, supporting continued transmission system reliability in the area. The project will take place entirely within the existing National Taconite Substation, which is located on mine property, making optimal use of the existing site infrastructure to minimize human and environmental impacts.

Project Description: GRE will interconnect to Minnesota Power’s (MP) 13 Line (Riverton – Cromwell 115 kV) with a 4 position, 115 kV ring bus, to be called Portage Lake, at or near the existing Mille Lacs Electric Cooperative (MLEC) Kimberly substation. The new 115 kV Portage Lake ring bus will have four positions; 115 kV line to Riverton (13 Line), 115 kV line to Cromwell (158 Line), 115/69 kV transformer with a 9.5-mile line to Palisade, and a 115-kV position for MLEC’s Kimberly distribution substation.

Need Driver: This project is needed to address reliability concerns due to long radial line exposure, and thermal overloading during winter peak conditions.

Analysis: The 69 kV Palisade Radial Line is made up of 3 Lake Country Power (LCP) delivery points (Wright, Round Lake and Big Sandy) and one MLEC delivery point, Palisade, with 32 miles of total line exposure. The Palisade Radial peaks at 25.9 MW in the winter and 15.3 MW. For the loss of the Cromwell – Palisade Tap 69 kV line during winter peak loading, the whole Cromwell-Four Corners 69 kV system is sourced from the Four Corners 115/69 kV transformer and the thermal loading reaches 110%.

General Impacts: The project will require approximately 10 miles of new 69 kV transmission line from Portage Lake substation to Palisade substation. The project is located in predominantly agricultural lands. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 10 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: Targeted structure replacements on the Square Butte – Arrowhead HVDC line to install more robust anti-cascade structures at major infrastructure crossings along the 465-mile length of the line.

Need Driver: Reduce the likelihood of structure failures at locations where failures would have a more significant impacts to the surrounding area or be more difficult to restore.

Analysis: In coordination with the HVDC Modernization project (Tracking No. 213-NE-N16), Minnesota Power is also planning a transmission line “hardening” project. While the modernization of the converter stations will result in new state-of-the-art VSC HVDC components at the line terminals that should last for many years, the two converter stations will still be connected by a 40+ year old 465 mile transmission line. The existing original HVDC transmission line structures have proven to be susceptible to failure in extreme weather events. The transmission line hardening project planned for implementation in parallel with the HVDC Modernization Project will consist of targeted structure replacements at strategic locations – for example, near major infrastructure crossings – where anti-cascade structures that limit the impact of failures and allow for rapid line restoration would provide the most value. Executing the HVDC Line Hardening Project in coordination with the HVDC Modernization Project will limit on-the-ground impacts from structure failures near more heavily-trafficked areas and provide a more robust HVDC transmission line connection between the converter stations as the HVDC Line continues to be an important part of the transmission system for Minnesota Power and the region for many years following completion of the modernization project.

Schedule: The Project is expected to be constructed in phases over a 4-5 year period. To the extent it is possible to do so, construction of the Project will also be packaged with the modifications identified as part of the HVDC 900 MW Transmission Line Upgrades Project (2013-NE-N17). Engineering and construction on the first phase of the Project began in 2022-23. While additional phases are planned for construction through the end of the decade, execution on the second phase of the Project was temporarily put on hold in 2023 to enable the scope and timing of additional HVDC Line work, like the HVDC 900 MW Transmission Line Upgrades, to become clearer.

General Impacts: The hardening of the HVDC line structures at key locations is a prudent and necessary activity to reduce failure risks and impacts and ensure the ongoing operation of this critical piece of transmission for Minnesota Power’s customers, including the reliable delivery of Minnesota Power’s substantial North Dakota wind generation assets. Since the project is expected to take place at existing structure locations, it is anticipated that no new landowners would be impacted by the project.

Project Description: The Hibbing Substation is located west of Hibbing, Minnesota, south of the Hibbing Taconite mining operations. The Hibing Substation Modernization project involves replacing aging equipment, structures, and civil works and correcting deficiencies at the substation in an effort to improve substation safety and reliability for the foreseeable future. Multiple substation asset renewal needs were combined with necessary capacity upgrade projects on 14 Line (Hibbing – 14 Line Tap) and 25 Line (Hibbing – Virginia) to make up the core of this project. Hibbing-Maturi will be renamed to 180 Line, a 180 Line project will be double circuiting to 44 Line tap. This work at the Hibbing Substation was coordinated around the same schedules in order to facilitate efficient coordination of engineering and construction. This project will begin after the majority of the load has been permanently transferred to a nearby substation (Maturi). This minimizes the invested needed for this substation while still serving as a backup for some distribution load.

Need Driver: The Hibbing Substation serves the City of Hibbing as well as Minnesota Power retail customers in the area surrounding Hibbing and Chisholm. The primary need driver for the Hibbing Substation Modernization project is the age and condition of existing transformers, circuit breakers, disconnect switches, and site infrastructure. Much of the original equipment in this substation is nearing or beyond the end of its useful life, including many of the structures and foundations. The Hibbing 25L breaker is from 1976 and the 44L breaker is from 1988, both of which are historically problematic breaker models that are high on the breaker replacement priority list. Replacing these high-priority breakers in advance of failure is necessary to ensure safety and reliability, enhance long-term planning, and optimize lifecycle value. Although load will be shifted off the Hibbing Substation it is still part of the BES and needs to remain functional. The Distribution side will be needed to still serve some load and as a backup to Maturi and Nashwauk.

Analysis: Across Minnesota Power’s system there are many transmission-to-distribution substations that require age-related upgrades. Much of the original equipment in these substations is nearing or beyond the end of its useful life. Minnesota Power’s Substation Modernization (Asset Renewal) Program involves coordinated replacement of end-of-life assets and holistic modernization improvements designed to extend the lives of these substations for the next several decades. The Program takes a holistic, site-by-site approach to facilitating the coordinated and efficient modernization of many aging substations throughout Minnesota Power’s system. In developing the scope for the Hibbing Substation Modernization Project, Minnesota Power considered the near-term and long-term needs of the area transmission and distribution system as well as the age and condition of existing site infrastructure and modern design standards for safety, accessibility, and maintainability. The resulting project involves a nearly complete overhaul of the site, which is expected to ensure the site remains viable and continues to reliably serve Minnesota Power’s customers for many decades to come.

Schedule: The project is currently planned as a multi-year project. Civil and site work is expected to begin in fall 2026, with above-grade construction taking place in stages from 2026-27 to manage outage and constructability constraints.

General Impacts: The Hibbing Substation Modernization Project will ensure a continuous and reliable power supply to the Hibbing area by replacing aging equipment before it fails. While some minor fence expansion on Minnesota Power-owned property is necessary, the majority of impacts from the project will be entirely contained within the existing Hibbing Substation yard.

Project Description: The Verndale Substation Modernization Project involves replacing aging electrical equipment, structures, and civil works and correcting deficiencies at the existing Verndale 115/34 kV Substation in an effort to improve substation safety and reliability for the foreseeable future. Multiple substation asset renewal needs will be combined with necessary distribution transformer upgrades to make up the core of this project. This work at the Verndale Substation was combined into one project in order to facilitate efficient coordination of engineering and construction.

Need Driver: The Verndale Substation serves Verndale, Staples, Wadena and the surrounding area, including customers of Minnesota Power, Great River Energy, and Missouri River Energy Services. The primary need driver for the Verndale Substation Modernization Project is age and condition of existing transformers, circuit breakers, disconnect switches, and site infrastructure. Much of the original equipment in this substation is nearing or beyond the end of its useful life, including many of the structures and foundations. In addition to these asset renewal concerns, historical Verndale Substation loading exceeds firm capacity for loss of a single 115/34 kV transformer, and transformer load-tap changers are needed to provide more effective distribution system voltage regulation.

Analysis: Across Minnesota Power’s system there are many transmission-to-distribution substations that require age-related upgrades. Much of the original equipment in these substations is nearing or beyond the end of its useful life. Minnesota Power’s Substation Modernization (Asset Renewal) Program involves coordinated replacement of end-of-life assets and holistic modernization improvements designed to extend the lives of these substations for the next several decades. The Program takes a holistic, site-by-site approach to facilitating the coordinated and efficient modernization of many aging substations throughout Minnesota Power’s system. In developing the scope for the Verndale Substation Modernization Project, Minnesota Power is considering the near-term and long-term needs of the area transmission and distribution system as well as the age and condition of existing site infrastructure and modern design standards for safety, accessibility, and maintainability.

Schedule: The project is currently planned as a multi-year project with construction taking place in 2025-2026.

General Impacts: The Verndale Substation Modernization Project will ensure a continuous and reliable power supply to the Verndale, Staples, and Wadena areas by increasing transformer capacity, improving voltage regulation, and replacing aging equipment before it fails. At present, it is expected that the impacts will be entirely contained within the existing Verndale Substation yard and no expansion area will be necessary.

Project Description: Move existing 115 kV lines from straight bus in original Badoura 115 kV Substation into the open positions on the newer Badoura #2 Substation 115 kV ring bus. Build out bus work to connect existing cap bank. Demo original Badoura 115 kV Substation including removal of old 115 kV box structure and control house. Adding new alternate station service source to replace feed from 34.5 kV equipment at the Badoura site.

Need Driver: Age and condition of Badoura 40L and 48L 115 kV breakers and control house. Shifting capacitor bank position to mitigate post-contingent low voltage following loss of shared breaker with 230/115 kV transformer.

Analysis: The existing breakers protecting the two 115 kV lines into the straight bus at Badoura are 1960s-vintage oil breakers connected to a box structure of the same vintage. A newer ring bus was constructed adjacent to the original Badoura Substation in the 2000s as part of the Badoura 115 kV Project. The transmission lines connected to the original Badoura Substation are being relocated to open positions on the newer Badoura 115 kV ring bus to retire the original circuit breakers, box structure, and control house as well as establish a more reliable configuration for the 115 kV lines connected to the Badoura Substation.

General Impacts: The Badoura 115 kV Modernization Project will improve safety and transmission system reliability around Badoura by relocating transmission lines from an aging 1960s era site and a straight bus configuration to a newer site in a ring bus configuration. The project will include small fence expansions to accommodate new line entrance equipment on the ring bus at the Badoura 115 kV site, but in general will make optimal use of the existing Badoura Substation site and enable retirement of most of the original Badoura Substation site.

Project Description: The 15th Avenue West Transformer Addition Project involves adding a new 115/34 kV transformer in an existing future transformer position at the 15th Avenue West Substation in downtown Duluth. Additional upgrades and reconfigurations will take place in the Duluth 34 kV system to integrate the new 34 kV source.

Need Driver: Load growth and reliability enhancements on Duluth 34 kV distribution system.

Analysis: The Duluth 34 kV distribution system has sources at the Swan Lake Road and LSPI substations, but the majority of the load is located near the midpoint of the 34 kV system in downtown Duluth and the medical district – relatively far from the existing substation sources. The 34 kV system was originally developed due to the significant challenges associated with the development of additional transmission-distribution substations in central and downtown Duluth. The 34 kV system also provides enhanced reliability to critical loads such as the hospitals by placing them on a high-capacity backbone system with automated fault location, isolation, and system restoration (FLISR) implemented. As more load has transitioned onto the 34 kV system, backing up the entire system from either LSPI or Swan Lake Road has become more challenging due to the feeder distance from the sources to the load. Additional load growth following near-term expansion of one of the two major hospitals in the medical district will further impact backup capability for the Duluth 34 kV system. The addition of a new 115/34 kV transformer at the 15th Avenue West Substation, which is located much closer to the Duluth 34 kV system loads, and integration of the new source into the automated 34 kV feeder system will ensure that the Duluth 34 kV system continues to be a very reliable source with sufficient load-serving capability for critical loads in Duluth.

Schedule: The 15th Avenue West Transformer Addition Project is presently planned for construction in 2023.

General Impacts: The 15th Avenue West Transformer Addition Project will preserve and enhance the reliability of the Duluth 34 kV distribution system. Since the 15th Avenue West Substation was designed originally to accommodate the transformer addition, the majority of impacts from the substation expansion part of the project will be contained within the existing 15th Avenue West Substation yard, making optimal use of the existing infrastructure to reduce human and environmental impacts.

Project Description: LSPI Cap Bank Asset Renewal Project involves refurbishing the existing 115 kV capacitor bank at the LSPI Substation in West Duluth by replacing fuses, fuse holders, and other components.

Need Driver: The existing fuses are supposed to release on failure but are not working properly, resulting in capacitor bank outages that decrease the availability of the capacitor bank and increase maintenance costs for the site.

Analysis: The LSPI Substation capacitor bank provides important voltage support and regulation for the West Duluth area. This project involves low-cost targeted asset renewal improvements that will enhance the reliability and availability of this capacitor bank. There is no more economical or less impactful solution than replacing the existing fuses and fuse holders.

General Impacts: The LSPI Cap Bank Asset Renewal Project will ensure continued reliable voltage support for West Duluth by replacing failing components. The impacts of the project will be entirely contained within the existing LSPI Substation yard, making optimal use of the existing infrastructure to reduce human and environmental impacts.

Project Description: The Canosia Road Substation 34 kV Expansion Project involves expanding the existing Canosia Road Substation into a four position ring bus by adding two 115 kV breakers in order to interconnect a new 115/34 kV transformer. Additional upgrades and reconfigurations will take place in the Cloquet-area distribution system to integrate the new 34 kV source.

Need Driver: Establish a new 34 kV source for the Cloquet area to achieve asset renewal and distribution voltage standardization, increased system capacity and constructability for the Cloquet Substation Modernization Project (2021-NE-N13), improved reliability, and prepare for grid modernization project implementation.

Analysis: The Canosia Road Substation 34 kV Expansion will be the first step and foundation in a multi-year plan to modernize and improve the Cloquet-area distribution system. There are several factors driving the need for improvements in the Cloquet area:
Asset Renewal & Standardization: Implementing a standard 34 kV backbone distribution network for the Duluth/Cloquet area. There are presently three different backbone distribution voltages between Duluth, Cloquet, and Hinckley. The Canosia Road Expansion and subsequent projects will convert existing 24 kV and 46 kV systems to 34 kV while addressing asset renewal needs for existing feeders and stepdowns associated with these systems
System Capacity & Asset Renewal Project Constructability: Enabling the Cloquet Substation Modernization Project (2021-NE-N13) to take place. Cloquet Substation is one of the highest-priority asset renewal sites in the Minnesota Power system, but the distribution system lacks sufficient capability to reliably support the Cloquet area during the extended outage of the Cloquet Substation that would be needed to implement the asset renewal project.
Reliability & Grid Modernization: Improving reliability for Cloquet-area customers by reducing feeder exposure, providing backup capability from new feeders and 34/14 kV stepdowns, and enabling feeder automation projects to be implemented for enhanced visibility and rapid system restoration.

Schedule: The project at the Canosia Road Substation is currently under construction with work having started in 2022, with associated distribution system upgrades taking place in 2022 and 2023.

General Impacts: The Canosia Road Substation 34 kV Expansion Project will enhance the reliability of the Cloquet-area distributions system while also addressing significant age and condition and maintenance-related issues on the distribution system. Since the Canosia Road Substation was designed originally to accommodate the expansion, the majority of impacts from the substation expansion part of the project will be contained within the existing Canosia Road Substation yard, making optimal use of the existing infrastructure to reduce human and environmental impacts.

Project Description: The Two Islands 115 kV Project involves the construction of a new switching station that will serve as the connecting point to replace the original Taconite Harbor Substation in the North Shore Loop transmission system. The new Two Islands Switching Station will be constructed across the highway from the original Taconite Harbor Substation and will consist of a 5-6 position ring bus and a new capacitor bank. Great River Energy hosts a 115/69 kV delivery point at the existing Taconite Harbor Substation that will be relocated to a new GRE Two Islands Substation adjacent to the MP Two Islands Switching Station. A second 115/69 kV transformer will be added at the GRE Two Islands Substation to provide redundancy for the GRE 69 kV system east of Taconite Harbor.

Need Driver: The new switching station will replace the original Taconite Harbor Substation, increasing reliability and safety by moving away from a compact original box structure in a straight bus configuration to a new ring bus configuration constructed according to modern standards for clearances, access, and maintainability. A major overhaul of the Taconite Harbor Substation would be required to extend the life of the existing site, but access and maintainability would still be limited due to the compact site layout. A complete overhaul of the Taconite Harbor Substation would require an extended outage that would leave the entire North Shore Loop on radial feeds for multiple weeks, which would increase risk of blackouts if any outage event should occur on the radial feeds.

Analysis: The existing Tac Harbor Substation is a compact site originally purpose-built by a mine for the generators at the Taconite Harbor Energy Center. This compact style of substation creates safety concerns and outage constraints during maintenance with the condensed equipment locations. With the retirement of the generators, the substation now serves the primary purpose of providing reliable transmission support to the North Shore Loop. The Taconite Harbor Substation also provides a 115/69 kV step-down to source a 50 mile long radial 69 kV line that provides service to four of Arrowhead Electric Cooperative Incorporated’s (AECI) distribution substations (Colvill, Maple Hill, Lutsen, and Cascade), one of Co-op Light & Power’s distribution substations (Schroeder) and one of SMMPA’s distribution substations (Grand Marais). GRE owns a generation station at the end of the line providing 18 MW of backup generation. The Taconite Harbor Substation is very critical to providing reliable power to a remote, radial system and is justified in rebuilding due to age and condition.

MP Schedule: The project is planned to be in service by the end of 2024, with civil work started in 2023.

General Impacts: The Two Islands 115 kV Project will improve reliability of the North Shore Loop with the new ring bus. A cap bank at this new facility will also improve voltage control on the North Shore Loop. The new ring bus will minimize outage concerns at the site with additional reliability and protection. As the Two Islands 115 kV Project will be a new facility, a new site location on Minnesota Power-owned property has been identified for all construction. The project will also require approximately 0.1 miles of new 69 kV transmission line from Two Islands Substation to the existing “SG” 69 kV line. The project is located in an area that is predominantly impacted by the historical utility usage of the nearby Taconite Harbor Energy Center. Prior to construction, MP and GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the 69 kV line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed over 18-24 months. During this time, MP and GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas and maximizes the use of existing utility-controlled lands and infrastructure.

Project Description: Replace end-of-life 230/115 kV transformer and 230 kV capacitor bank, circuit breakers, switches, relay panels, and associated equipment at the Forbes 230 kV Substation.

Analysis: One circuit breaker is oil-filled from 1979 and one circuit breaker is an early generation SF6 model of concern. The existing capacitor bank has failed components and a larger replacement capacitor bank will provide additional voltage support to the transmission system. The 230/115 kV transformer is a critical transformer to the surrounding 115 kV system, including the East Range and the North Shore Loop. This transformer has many age and condition-related issues. An extended outage due to failure of this transformer would likely require running local peaking generation for the duration of the outage. There are concerns with moving the aging transformer from another site which has been identified as a spare in the event of a failure. It is prudent to proactively replace this transformer in the near-term future before it fails.

General Impacts: The Forbes 230 kV Modernization Project will ensure that the Forbes 230 kV Substation continues to provide safe and reliable transmission support for Minnesota Power’s 230 kV and 115 kV transmission system. The impacts of the project will be entirely contained within the existing Forbes Substation yard, making optimal use of the existing infrastructure to reduce human and environmental impacts.

Project Description: The Cloquet Substation Modernization Project involves replacing aging electrical equipment, structures, and civil works and correcting deficiencies at the existing Cloquet 115/14 kV Substation in an effort to improve substation safety and reliability for the foreseeable future. Multiple substation asset renewal needs will be combined with necessary distribution transformer upgrades to make up the core of this project. This work at the Cloquet Substation was combined into one project in order to facilitate efficient coordination of engineering and construction.

Need Driver: The Cloquet Substation serves Cloquet, Esko, Scanlon, parts of the Fond Du Lac reservation and the surrounding area. The primary need driver for the Cloquet Substation Modernization Project is age and condition of existing transformers, circuit breakers, disconnect switches, and site infrastructure. Much of the original equipment in this substation is nearing or beyond the end of its useful life, including many of the structures and foundations.

Analysis: Across Minnesota Power’s system there are many transmission-to-distribution substations that require age-related upgrades. Much of the original equipment in these substations is nearing or beyond the end of its useful life. Minnesota Power’s Substation Modernization (Asset Renewal) Program involves coordinated replacement of end-of-life assets and holistic modernization improvements designed to extend the lives of these substations for the next several decades. The Program takes a holistic, site-by-site approach to facilitating the coordinated and efficient modernization of many aging substations throughout Minnesota Power’s system. In developing the scope for the Cloquet Substation Modernization Project, Minnesota Power is considering the near-term and long-term needs of the area transmission and distribution system as well as the age and condition of existing site infrastructure and modern design standards for safety, accessibility, and maintainability.

Schedule: The project is currently planned as a multi-year project with construction taking place in stages from 2027-2028 to manage outage and constructability constraints.

General Impacts: The Cloquet Substation Modernization Project will ensure a continuous and reliable power supply to the Cloquet area by replacing aging equipment before it fails. At present, it is expected that the impacts will be entirely contained within the existing Cloquet Substation yard, making optimal use of the existing infrastructure to reduce human and environmental impacts.

Project Description: Extend a new 115 kV line approximately 8 miles from the Mesaba Junction Switching Station to the end of a customer-owned segment of 115 kV line connecting back to the existing Embarrass – Babbitt 115 kV Line (137 Line). A normal open point will be established near the Argo Lake tap due to the relatively small existing conductor on 137 Line. At the Mesaba Junction Switching Station, a 115 kV line entrance will be constructed, including a circuit breaker and deadend structure, in an existing ring bus position at the substation.

Need Driver: Age and condition of existing 137 Line and redundancy of service to Babbitt-area customers served from 137 Line.

Analysis: The Mesaba Junction 137 Line Extension Project meets three critical needs for the Babbitt area:

For an outage affecting the Mesaba Junction end of 137 Line, the issue can be isolated and service can be restored from Embarrass end by closing the normal open point. For a planned outage affecting the Mesaba Junction end of 137 Line, the normal open point can be closed and a segment of the line can be isolated without a customer outage.

Schedule: Due to wetlands in the area traversed by the transmission line, transmission line construction is advantageous during frozen ground conditions. Below grade construction at the Mesaba Junction Switching Station is presently planned for the 2025 fall season. Transmission line construction and above grade construction at the substation is presently planned to be constructed in the 2025-2026 winter season.

General Impacts: The Mesaba Junction 137 Line Extension Project will preserve and enhance the reliable delivery of power to an important industrial load pocket in the Babbitt area. The project will also provide the opportunity to address significant age and condition and maintenance-related issues on the existing Embarrass – Babbitt 115 kV Line as part of the 137 Line Rebuild (2021-NE-N15). The project will require approximately 8 miles of new 115 kV transmission in a remote area of northern Minnesota that has been heavily impacted by historical mining operations.

Project Description: Rebuild existing Embarrass – Babbitt 115 kV Line (137 Line) from the Embarrass Substation to the North side of the Peter Mitchell Mine pit crossing with a larger conductor.

Analysis: Across Minnesota Power’s system there are many transmission lines that require age and condition-related upgrades. Many of the original wood pole structures and components on these transmission lines are nearing or beyond the end of their useful lives. As these transmission lines continue to age, the risk of structure and component failures – and therefore the risk of outages, property damage, and safety concerns – will increase. Minnesota Power’s Transmission Line Asset Renewal Program involves identification, prioritization, and coordination of transmission line asset renewal projects to address end-of-life wood poles and other components while holistically considering long-term reliability, capacity, and communications needs. The program is designed to extend the lives of these transmission lines so they can continue to reliably serve Minnesota Power’s customers and the region for many decades to come.

Schedule: Due to wetlands in the area traversed by the transmission line, construction is advantageous during frozen ground conditions. The 137 Line Rebuild is presently planned to be constructed in stages from 2027-2029, maximizing use of the winter construction season.

General Impacts: The 137 Line Rebuild Project will ensure that the existing Embarrass – Babbitt 115 kV Line continues to provide a safe and reliable transmission path for Minnesota Power’s customers. The project involves replacement of existing assets on the existing transmission line right-of-way, therefore making optimal use of the existing transmission line with little or no additional human or environmental impacts.

Project Description: The West Cohasset Substation Project involves re-establishing a 115/23 kV transformer at the Boswell SES 115 kV Substation and extending new 23 kV feeders from the substation. The Boswell SES Substation will be renamed as part of the project to eliminate redundant naming with the adjacent Boswell 230/115 kV Substation.

Need Driver: The West Cohasset Substation Project is necessary to upgrade the reliability and capacity of the existing 23 kV distribution system in the Cohasset area.

Analysis: The West Cohasset Substation Project will enhance the existing Minnesota Power 23 kV distribution system while enabling new loads to be interconnected in the Cohasset area.

General Impacts: The West Cohasset Substation Project will make optimal use of an existing substation site to preserve and enhance the reliability of the Cohasset-area distribution system. Since the Boswell SES 115 kV Substation was originally designed to accommodate a transmission-distribution transformer, the majority of impacts from the substation expansion part of the project will be contained within the existing substation yard, minimizing human and environmental impacts.

Project Description: The 105 Line & 106 Line Upgrade Project involves reconductoring segments of the two existing Iron Range – Blackberry 230 kV lines and replacing limiting terminal equipment at the Blackberry Substation.

Analysis: This issue has been identified in Minnesota Power internal and MISO MTEP studies, and is also discussed in Minnesota Power’s Integrated Resource Plan as it relates to changes in operation of the Boswell Energy Center units. With at least one Boswell unit moving from baseload operation to economic dispatch, overloads on these transmission lines are expected to show up more frequently as they are critical outlets for the delivery of replacement energy from the Iron Range and Forbes 500/230 kV sources.

General Impacts: The 105 Line & 106 Line Upgrade Project will provide necessary system improvements for Minnesota Power’s 230 kV system without requiring the establishment of additional transmission line corridors. In addition to making optimal use of existing facilities, the project supports changes in operation at the Boswell Energy Center that have social, environmental, and economic benefits.

Project Description: The 230 kV STATCOM Project involves the establishment of a new STATCOM at the existing Iron Range or Riverton 230 kV Substation.

Need Driver: The new STATCOM is needed to ensure a continuous and reliable source of steady state and dynamic voltage support during times when no large dispatchable generators are online in Northern Minnesota.

Analysis: The Boswell Energy Center units are the last remaining baseload generators operating in Northern Minnesota. As the last remaining baseload generators, the Boswell units provide voltage support and system strength on a continuous basis that support consistent and predictable system operations and properly function protection systems for the transmission system and the lower-voltage distribution systems that depend on it. In addition, Minnesota Power’s significant concentration of large industrial customers depend on predictable voltages and fault currents historically and presently provided by the Boswell units to support their large industrial processes and power quality needs. It is typical for large industrial plant design, like utility distribution system design, to take into account as a design basis the fault current contributions and normal operating voltages of the utility transmission system. Without the Boswell units online, the Northern Minnesota transmission system would operate for extended periods of time without any local generators online to provide fault current and voltage regulation. This mode of operation would be unprecedented in the modern history of the Northern Minnesota transmission system and, if not adequately assessed and mitigated, would lead to a great deal of uncertainty and potential degraded operation in the transmission system and lower-voltage industrial, municipal and Minnesota Power distribution system connected to it.

As Minnesota Power has continued to evaluate the issue and potential solutions, studies have consistently demonstrated significant degradation of steady state and dynamic voltage regulation when the Boswell units are offline. Less predictable steady state voltages, lower transient voltage dips during and after fault events, slower transient voltage recovery after fault events, and greater susceptibility to impacts from far-away regional fault events have all been identified as concerns on Minnesota Power’s system and propagating out on the regional 230 kV system. To address these concerns, a voltage support solution is needed to provide a continuous, predictable, and redundant source of steady state voltage regulation and dynamic voltage response on Minnesota Power’s 230 kV system. Based on Minnesota Power’s analysis and experience, a STATCOM is the ideal solution for meeting these steady state and dynamic voltage support needs. STATCOMs require no fuel for continuous operation and produce only reactive power. STATCOMs are capable of providing voltage regulation during normal system operations as well as dynamic voltage response during system disturbances. STATCOMs also provide inherently faster voltage response compared with Synchronous Condensers, and are less maintenance-intensive.

Schedule: Minnesota Power is presently in the late stages of identifying the preferred location on its 230 kV system to maximize the benefits of the proposed STATCOM solution. The STATCOM is anticipated to be sized between ±250 to ±350 MVAR and interconnected at either the existing Iron Range 230 kV Substation or the existing Riverton 230 kV Substation. Minnesota Power anticipates placing the STATCOM in service in 2027.

General Impacts: The establishment of one or more STATCOMs on Minnesota Power’s transmission system will provide necessary voltage support for Minnesota Power’s customers during times when no large dispatchable generators are online in Northern Minnesota. To the extent possible, new STATCOMs will be located at existing substation facilities. In addition to making optimal use of existing facilities, the establishment of one or more STATCOMs enables the transmission system to continue to operate reliably and predictably during and after changes in operation at the Boswell Energy Center that have social, environmental, and economic benefits.

Project Description: The 126 Line Asset Renewal Project involves replacement of transmission line components on the Little Fork – International Falls 115 kV Line (126 Line) due to age and condition. The project will also include age-related replacements of a 115 kV circuit breaker and relay panel at the Little Fork Substation and a relay panel at the International Falls Substation.

Need Driver: The project will address asset renewal needs on 126 Line related to the age and condition of existing structures and transmission line components, an oil-filled 115 kV circuit breaker, and older relay panels that have been found to be susceptible to component failures.

Similarly, there are many transmission assets across Minnesota Power’s system that require age-related upgrades. In developing the scope for the 126 Line Asset Renewal Project, Minnesota Power is also considering targeted replacements at the substations that will address age-related concerns and contribute to more reliable operation of the transmission system.

Schedule: The 126 Line Asset Renewal Project is presently targeted for construction in 2023.

General Impacts: The 126 Line Asset Renewal Project will ensure that the existing Little Fork – International Falls 115 kV Line continues to provide a safe and reliable transmission path for Minnesota Power’s customers in the International Falls area and the region. The project involves replacement of existing assets on the existing transmission line right-of-way and within existing substations, therefore making optimal use of the existing transmission facilities with little or no additional human or environmental impacts.

Project Description: The 13 Line Rebuild Project involves replacement of transmission line structures and conductor on the Portage Lake – Riverton 115 kV Line (13 Line) due to age and condition. The project will also include the addition of shield wire and fiber-optic communications on the rebuilt transmission line.

Need Driver: The project will address asset renewal needs on 13 Line related to the age and condition of existing structures and transmission line components, add shield wire to improve reliability by reducing lightning-related outages that directly impact Minnesota Power and Great River Energy customers, and add fiber-optic communications to enhance transmission line protection systems.

Schedule: The 13 Line Rebuild Project is in early stages of project scoping and is presently targeted for 3-4 years of phased construction beginning at the earliest in 2025.

General Impacts: The 13 Line Rebuild Project will ensure that the existing Portage Lake – Riverton 115 kV Line continues to provide a safe and reliable transmission path for Minnesota Power and Great River Energy’s customers and the region. The project involves replacement of existing assets on the existing transmission line right-of-way, therefore making optimal use of the existing transmission facilities with little or no additional human or environmental impacts.

Project Description: Install storm structures in the Riverton – Wing River 230 kV line.

Need Driver: GRE is continuing to look at making the system more resilient. GRE has H-frame construction on multiple lines that have shown to be prone to line cascading (domino effect) resulting in long duration outages. One way is to limit the damage of cascading is to install stop structures, such as a storm structure. GRE is proposing to install storm structures that will limit damage from cascading to 5- to 10-mile sections rather than without storm structures, whereby significantly longer mileage of damage could occur.

Alternatives:
Transmission Alternatives
Storm Structures were considered the most cost-effective solution to limit outages from line cascading.
Non-Wires Alternatives
This a reliability improvement to an existing line to prevent cascading structure failure and no alternatives were considered.

General Impacts: The project will be constructed on the existing 230 kV transmission line from Riverton substation to Wing River substation. The project is located in predominantly agricultural lands. Construction is expected to be completed in 2 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Minnesota Power (MP) and Great River Energy (GRE) are jointly developing the Northland Reliability Project (Project), located in northern and central Minnesota. The Project consists of two major segments of transmission line construction:

The Project will also involve the following new or modified substation and series compensation facilities:

The proposed Big Oaks 345 kV Substation on the south end of Segment 2 is being permitted, engineered, and constructed by Xcel Energy as part of a separate project, and is not included in this scope of work.

Need Driver: The Northland Reliability Project is needed to address some of the most challenging transmission system reliability issues related to the transition away from fossil-fueled generation. These reliability issues include serious regional voltage and transient stability issues identified by MP and GRE and the Midcontinent Independent System Operator (MISO). The Project addresses these issues and also provides enhancements to voltage support and system strength, local sources of power delivery, and the ability to move power between regions. The Project was studied, reviewed, and ultimately approved as part of the MISO Long-Range Transmission Plan (LRTP) Tranche 1 Portfolio by MISO’s Board of Directors in July 2022. The Project will ensure that the power grid in northern and central Minnesota continues to operate safely and reliably as energy resources in Minnesota and the regional power system continue to evolve.

Analysis: New transmission lines are required for voltage stability in the northern Minnesota area.
Schedule: The project is planned to be in service by June 1, 2030.

General Impacts: The project will be constructed along the existing 230 kV transmission line from the Iron Range substation to the Benton County substation, with additional construction along the existing 230 kV transmission line from the Benton County substation to the Monticello substation, terminating at the new Big Oaks substation, and construction along the existing 345 kV transmission line from the Benton County substation to the Sherco substation. The project is located in both forested and agricultural lands across its length. Construction is expected to be completed over 3 years. During this time, MP/GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Rebuilding the existing 40 Line, a 115 kV transmission line between the Badoura Substation and Dog Lake Substation. The project will upgrade conductors on the line and add OPGW for a communications path between the sites.

Need Driver: This project is primarily an age and condition rebuild project, replacing structures from the 1970s.

Alternatives:
Transmission Alternatives
This project is an age and condition rebuild project so no alternatives were evaluated.

General Impacts: The project will be constructed on the existing 115 kV transmission line from the Dog Lake substation to the Badoura substation. Construction is expected to be completed within 6 months starting in late summer 2023 and extending through the winter months into 2024. During this time, MP and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Need Driver: New customers are connecting to the Brainerd 115 kV substation through the local 34.5 kV network. As the substation load grows, due to these customer connections, post-contingent overloads and low voltage violations were identified by MISO as part of the expedited project review process as part of MTEP.

Alternatives:
Transmission Alternatives
None.
Non-Wires Alternatives
Minnesota Power enacting an operational guide for load shedding at Brainerd as a temporary mitigation.
Analysis: This is a cost-effective system resiliency solution.

Schedule: The project is currently shown in MISO MTEP for in-service in 2025.

General Impacts: The rebuild of 12 Line would allow for additional load growth in Brainerd area. The rebuild would also replace an aging asset. The project would match new standards for conductor and structure designs. The cap bank would supply reactive sources to the Brainerd area to support the voltage during heavy load conditions.

Project Description: Expanding the Maturi Substation to accommodate new 23 kV lines to serve local MP loads, looping 25 Line in and out of the substation to replace the tap in 25 Line.

Need Driver: The Maturi Substation serves Minnesota Power retail customers in the area surrounding Hibbing and Chisholm. The primary need driver for the Maturi Substation Expansion project is to unload the Hibbing Substation and create a better source for the City of Chisholm and the surrounding area.

Alternatives:
Transmission Alternatives
None.
Non-Wires Alternatives
This a reliability improvement at the substation and no alternatives were considered.

General Impacts: The Maturi Expansion Project will ensure a continuous and reliable power supply to the City of Chisholm and the surrounding area. The project involves looping 25 Line in and out of the substation on the existing transmission line right-of-way, therefore making optimal use of the existing transmission line with little or no additional human or environmental impacts.

Project Description: Substation expansion of the Mahtowa Substation to facilitate back-up of Cloquet feeder. Mahtowa is currently a tap located on 26 Line that spans from Thomson to GRE_Cromwell. This project will break this tap into two different lines so that the Mahtowa substation is no longer a radial tap.

Alternatives:
Transmission Alternatives
There is no more economical or less impactful solution than replacing the existing substation equipment.
Non-Wires Alternatives
Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Mahtowa Substation.

General Impacts: The 115/23 kV transformer located at Mahtowa has reached its end of life and poses a reliability issue. This transformer and the 115/46 kV transformer also at this site will be replaced with a single 115/34 kV transformer. This will increase the reliability of this site and remove the last of the 23 kV voltage class in the Minnesota Power central area. This will help keep the distribution system consistent in the area for operation and maintenance. Second, this project will loop 26 Line in and out of the substation to remove Mahtowa as a radial tap.

Project Description: The 158 Line Rebuild Project involves replacement of transmission line structures and conductor on the Portage Lake – Cromwell 115 kV Line (“158 Line”) due to age and condition. The project will also include the addition of shield wire and fiber-optic communications on the rebuilt transmission line.

Need Driver: The project will address asset renewal needs on 158 Line related to the age and condition of existing structures and transmission line components, add shield wire to improve reliability by reducing lightning-related outages that directly impact Minnesota Power and Great River Energy customers, and add fiber-optic communications to enhance transmission line protection systems.

Alternatives:
Transmission Alternatives
There are no reasonable alternatives that will address the asset renewal needs for the existing transmission line.
Non-Wires Alternatives
Non-wire alternatives are not viable because they cannot address concerns related to age and condition of the existing transmission line.

Schedule: The 158 Line Rebuild Project is in early stages of project scoping and is presently targeted for 1-2 years of phased construction beginning at the earliest in 2025.

General Impacts: The 158 Line Rebuild Project will ensure that the existing Portage Lake – Riverton 115 kV Line continues to provide a safe and reliable transmission path for Minnesota Power and Great River Energy’s customers and the region. The project involves replacement of existing assets on the existing transmission line right-of-way, therefore making optimal use of the existing transmission facilities with little or no additional human or environmental impacts.

Project Description: Adding monitoring and redundant controls to mitigate single point of failure concerns around DC supply systems.

Alternatives:
Transmission Alternatives
Significant existing transmission line rebuilt to a larger conductor to mitigate all violations present after the P5 contingency.
Non-Wires Alternatives
The P5 contingency can only be mitigated with extra monitoring and control redundancy.

General Impacts: This project will introduce redundant monitoring and controls at the Arrowhead 115 kV site. The specifics of the project and are still being determined. At the end of this project, the Arrowhead 115 kV P5 contingencies can be retired due to enough redundant monitoring at the site.

Project Description: Adding monitoring and redundant controls to mitigate single point of failure concerns around DC supply systems.

General Impacts: This project will introduce redundant monitoring and controls at the Forbes 115 kV site. The specifics of the project are still being determined. At the end of the project, the Forbes 115 kV P5 contingencies can be retired due to enough redundant monitoring at the site.

Project Description: Expanding the Ridgeview 115 kV Substation to add a new 115/34 kV transformer.

Alternatives:
Transmission Alternatives
None.
Non-Wires Alternatives
Distribution project to address capacity need. This a reliability improvement at the substation and no alternatives were considered.

General Impacts: This project will be the start of a series of projects that will shift the Duluth distribution network to allow more load addition while also increasing reliability. The Ridgeview 115/34 kV transformer addition will take over the stepdowns located on the Swan Lake 34 kV feeder so that the Miller Hill Mall can be added to Swan Lake. The Miller Hill Mall does not have and adequate backup source presently and shifting its feeder will mitigate the issue.

Project Description: Adding monitoring and redundant controls to mitigate single point of failure concerns around DC supply systems.

Need Driver: The Wrenshall Substation is in need of asset replacement due to age and condition of the site.

Alternatives:
Transmission Alternatives
None.
Non-Wires Alternatives
No alternatives for an age and condition project.

Analysis: This project will replace old equipment to strengthen reliability to the local loads.

General Impacts: This project will ensure a continuous and reliable power supply to the Wrenshall area by replacing old assets prior to failure.

Project Description: Rebuilding 115 kV Transmission Line between Verndale and Wing River Substations.

General Impacts: The project will be constructed on the existing 115 kV transmission line from the Verndale substation to the Wing River substation. During construction, MP and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

The table below identifies those projects by Tracking Number in the Northeast Zone that were listed as ongoing projects in the 2021 Biennial Report but have been completed or withdrawn since the 2021 Report was filed with the Minnesota Public Utilities Commission in October 2021. Information about each of the completed projects is summarized briefly in the table below. More information about these projects and inadequacies can be found in earlier reports. Projects that were listed as being complete in the 2021 Report are not repeated here, but more information about those projects can be found in these earlier reports.

The following table provides a list of transmission needs identified in the West Central Zone by MISO utilities. There were no projects identified in this zone by non-MISO utilities.

Project Description: Build the Orrock 345/115 kV Substation northwest of Elk River. Build 115 kV lines from Orrock to Enterprise Park & Liberty.

Need Driver: This project is needed to address load growth and thermal overloading during a two overlapping single contingency event (NERC TPL-001-4 P6).

Alternatives:
Transmission Alternatives
Reconductor the Crooked Lake-Parkwood line to ACSS conductor and add a second 345/115 kV transformer at Elm Creek.
Non-Wires Alternatives
This project is still being studied. Non-transmission alternatives will be studied and considered prior to project initiation.

Analysis: The project is proposing a double circuit 115/69 kV line that would provide more capacity to a narrow transmission corridor than either a single circuit 115 or 69 kV line could offer. Furthermore, the Waco breaker station was designed to accept a 115/69 kV transformation and such a transformer would offload the Elk River 230/69 kV transformers. An Elk River Area 345/115 kV source would also offer a termination point for a 115 kV line going east towards the Crooked Lake Substation.

Schedule: This schedule for this project will be driven by the area load growth. Some portions of the 69 kV transmission will be converted to 115 kV design when needed due to age and condition.

General Impacts: The project will be constructed on an existing 69 kV transmission right-of-way that is located on residential and agricultural lands. The existing line will be upgraded from 69 kV to 115 kV construction and operation. A new substation will be built on approximately 22 acres near where the Xcel Energy 345 kV 0984 & 0992 transmission lines cross the GRE 69 kV EB line. No new landowners will be impacted by construction, although some additional temporary workspace may be required. GRE has completed a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction schedule and duration is uncertain at this time but will likely be spread out over several years. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Replace existing Ortonville 115/41.6 kV transformer with a new 40 MVA 115/41.6 kV transformer.

Need Driver: This area is experiencing local load growth and continual growth may cause the current 115/41.6 kV Ortonville transformer to become overloaded and created reliability concerns.

Analysis: The replacement of the Ortonville 115/41.6 kV transformer with a larger transformer will address the local load growth that this area is experiencing and will provide reliable service to the customers in the area. This project is the most cost-effective and environmentally responsible project to address the local needs in the Ortonville area.

Schedule: While prior studies identified this need, current load growth projections show no need to replace this transformer based on OTP’s Ten Year Development Study. However, faster load growth could create a need for this project, and continued studies will monitor this transformer’s loading.

General Impacts: The new transformer would replace the existing transformer and would require no additional new land or expansion. Since it will replace the existing transformer, there likely would be no major environmental impacts. This project may require a temporary project crew. If so, this may bring some business to the area in the form of room and board. This is an existing substation and would likely not require any permits or fees from the local government. This project is the product of a reliability measure, and will probably not have a substantial or lasting impact on the community in terms of population or other social characteristics.

Project Description: Convert the Westwood I substation to 115 kV service and provide a loop feed to the LeSauk and Five Points distribution substations. The following will be accomplished as part of this project:

Need Driver: Improve service reliability to Westwood I, LeSauk and Five Points distribution substations. The West St. Cloud to Little Falls 115 kV line has been a congested interface. Removing Le Sauk and Five Points substations from this line will provide some relief to this congestion. The upgrade of Westwood I distribution substation to 115kV service will address current safety concerns arising from high current flow in the distribution system when switching between Westwood I and Westwood II, or vice versa.

Analysis: The Westwood I conversion to 115 kV will be accomplished by upgrading existing 69kV transmission lines that serve the Westwood I substation. This is a project that is most economical and least impactful to landowners. This project addresses safety issues at the Westwood substations and the reliability improvement needs in the area.

General Impacts: The project will be constructed on an existing 70-foot right-of-way that is largely located on agricultural lands. The approximately 2.5 miles of existing line will be upgraded from 69 kV to 115 kV construction and operation. No new landowners will be impacted by construction, although some additional temporary workspace may be required. GRE has completed a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 3 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Rebuild and upgrade conductor on approximately 6.64 miles from Black Oak to Sauk Center.

Need Driver: Structures exceed planned service life - built in 1951. 4/OA and 3/#6 CU line sections overloading on N-1 contingencies.

Analysis: Upgrading conductor on this line to current 69 kV standards will mitigate the thermal issues seen online as well as increase load serving capability in the area.

General Impacts: Line rebuild to take place along existing centerline in rural setting adjacent to roadways. Structure heights are likely to increase. Road lane closure may be required during some construction.

Project Description: Howard Lake to Big Swan - Rebuild 16.0 miles, Delano to Howard Lake – Rebuild 19.7 miles, Cokato to Winstead – Rebuild 14.3 miles to current 69 kV standard for end of life asset renewal.

Need Driver: Re-occurring system reliability issues increase, public safety concerns
Inability to serve load in long term.

Analysis: Upgrading the line to current 69 kV standards will reduce losses as well as improve load serving capability in the area.

General Impacts: Primarily rural/agricultural land use with scattered urban/ developed areas; main environmental concerns are storm water control, environmental reclamation, and bird flight diverters. DNR water crossing permits will be required, as necessary.

Project Description: Rebuild 90% of line from Panther – Big Swan to current 69kV standard, replace Litchfield hard tap structure with double circuit structure, installation of a breaker station at Adams Wind Tap.

Need Driver: Panther – Big Swan 69 kV is one of NSP’s worst performing lines with 60+ miles of line exposure. This project will cut the line exposure into thirds in addition to mitigating thermal issues, voltage issues, and 3-terminal relay issues.

Analysis: Upgrading the line to current 69 kV standards will reduce losses as well as mitigate thermal, voltage, and 3-terminal issues seen in the area.

General Impacts: Project will be split into four stages and coordinated with other rebuilds occurring in that area within a similar timeframe. Line will be rebuilt using existing right-of-way.

Utility: Great River Energy (GRE), Otter Tail Power (OTP), Missouri River Energy Services (MRES)

Project Description: Construct approximately 28 miles of 115 kV transmission line from the MRES Appleton substation to GRE Benson substation. Rebuild the Appleton Substation to a ring bus with four breakers and a 25 Mvar capacitor bank. Convert 2 GRE and 2 OTP 41.6 kV distribution substations to 115 kV service. Add 2 115 kV breakers to the Benson Municipal substation. Reconfigure line terminations at GRE Benson and Benson Municipal.

Need Driver: This project is needed to address load serving issues and make capacity available to serve future load growth in the area. Additionally, it will address low voltage concerns during N-2 contingencies that may otherwise result in voltage collapse within the project areas.

Alexandria – Benson 115 kV ~47-mile line
MN Valley – Benson 115 kV ~44-mile line
Willmar – Benson 115 kV ~35-mile line
Six Mile Grove 230/115 kV substation

Both technical and economic analysis proves that the NWA is not viable for the area of study. In addition to that, the technical solution shows that NWA fails to address some of the issues which can be addressed by the proposed transmission solution, for example P6 contingency low voltage concerns in the Morris to Canby 115 kV system. A report is available upon request.

Analysis: The Appleton – Benson 115 kV line is the best value plan that addresses the load serving reliability issues in the area that in part was caused by generation retirement in the area. By in large, this project utilizes existing transmission line corridor and will upgrade existing 41.6 kV transmission lines to 115 kV. As such, among the alternatives considered, it is the most environmentally friendly project that addresses reliability issues and fosters economic development in wider area.

General Impacts: The project will require approximately 28 miles of new 115 kV transmission line from Appleton substation to Benson substation. The project is located in predominantly agricultural lands. Prior to construction, GRE and/or OTP will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 24 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: Rebuild the Big Swan 115 kV side of the Big Swan substation in a ring bus configuration to accommodate installation of a new capacitor bank and to reterminate the Big Swan to Crow River 115 kV line into a breaker position. Upgrade 115 kV and 69 kV relaying to ensure all protection is redundant. Add a new 40 MVAr capacitor into a position in the ring bus.

Need Driver:
Ring bus addition:
The Big Swan 115 kV bus has an incomplete topology, missing a 115 kV breaker on the Big Swan 115 kV line. For 115 kV line faults between Big Swan and Crow River, three 115 kV lines (all BES) and Big Swan 115/69 kV TR1 need to be tripped to clear the fault. The addition of a 115 kV breaker and 115kV bus connected capacitor bank in the current configuration would create a five-position straight bus. GRE cannot add the new positions to the existing box structure and maintain required electrical clearances. A 115 kV ring bus will allow for safe clearances, higher system reliability/resilience, allow for future expansion, and aligns with GRE standards for a 115 kV facility.

Cap bank addition:
The Hutchinson area study identified low voltage concerns in the 115 kV system that is between Hutchinson, Wakefield and Crow River. NERC category P6 contingencies involving prior outages, such as McLeod – Hutchinson 115 kV line, Crow River – Brooks Lake 115 kV line and Wakefield – Stockade 115 kV line causes low voltage problems at 115 kV side of GRE member substations and Hutchinson Mun’s substation.

The Hutchinson area study also identified low voltage and overload concerns in the 69 kV transmission system for the loss of the Hutchinson 115/69 kV transformer. Several options have been evaluated to address the voltage concerns and all the options involved installation of capacitor bank at Big Swan to improve the 115 kV system post contingent voltage profile and a second Hutchinson 115/69 kV transformer to address low voltage and overload concerns in the 69 kV system. Per discussion with the Xcel Energy and MRES, GRE will be responsible for the installation of the 40 MVAr capacitor bank at Big Swan and Hutchinson Municipal Commission will be responsible for the installation of a second 115/69 kV transformer at Hutchinson substation.

Several transmission alternatives were considered, including installation of the capacitor bank at the Hutchinson substation. However, this option was not favored due to the proximity of Hutchinson substation to an industrial plant that could be highly sensitive to voltage transients. As for reterminating the 115 kV line from Crow River with a breaker at Big Swan, no other alternatives were considered.

NWA were not considered for this project. This project modifies existing substations that lack a breaker to re-termination of an existing line. The installation of the capacitor bank is contained within the existing substation fence, making the NWA unnecessary.

Analysis: The addition of capacitor bank at the existing Big Swan substation was found to be the best value and environmentally friendly plan that addresses reliability issues in the area. The Big Swan 115 kV side of the substation is deficient of a line termination breaker for the Crow River to Big Swan 115 kV line and is not up to GRE’s current design standard. GRE plans to bring the Big Swan 115 kV side of the substation up to the current design standard while installing the capacitor bank and breaker at the Big Swan substation. This project is done with existing property of GRE’s. Therefore, it would have minimal impact on landowners in the area.

Project Description: Add two 115 kV line breakers at the Kerkhoven substation

Need Driver: The installation of two 115 kV breakers is necessary to prevent tripping at the Kerkhoven substation in the event of faults on the 115 kV transmission system.

The breaker addition was the only option considered to improve reliability due to cost effectiveness.

The project is for a reliability improvement to an existing substation that couldn’t be addressed with a NWA. Therefore, NWA was not considered for this project.

Analysis: The Kerkhoven substation currently lacks breaker protection on the 115 kV side. In the event of a fault on the 115 kV line on either side of the Kerkhoven substation, it would trip offline. The most cost-effective plan to improve resilience in the area served by the Kerkhoven substation is to install breakers to terminate the 115 kV lines at Kerkhoven. This solution offers a cost-effective enhancement to the system's reliability.

Schedule: The project is planned to be in service after completion of the Appleton – Benson 115 kV project.

Need Driver: The installation of two 115 kV breakers is necessary to prevent outages at the Walden substation in the event of faults on the 115 kV transmission system.

The breaker addition was the only option considered to improve reliability due to cost-effectiveness.

NWA was not considered as this project involves installation of breakers within the existing substation to prevent substation outages resulting from a 115 kV line fault.

Analysis: The Walden substation currently lacks breaker protection on the 115 kV side. In the event of a fault on the 115 kV line on either side of the Walden substation, it would trip offline. The most cost-effective plan to improve resilience in the area served by the Walden substation is to install breakers to terminate the 115 kV lines at Walden. This solution offers a cost-effective enhancement to the system's reliability.

Schedule: The project is planned to be in service after completion of the Appleton – Benson 115 kV project.

Project Description: Install storm structures in the Benson – Morris 115 kV line.

Need Driver: GRE is continuing to look at making the system more resilient. GRE has H-frame construction on multiple lines that have shown to be prone to line cascading (domino effect) resulting in long duration outages. One way is to limit the damage of cascading is to install stop structures, such as a storm structure. GRE is proposing to install storm structures that will limit damage from cascading to 5 to 10 mile sections rather than without storm structures, whereby significantly longer mileage of damage could occur.

General Impacts: The project will be constructed on the existing 115 kV transmission line from Benson substation to Morris substation. The project is located in predominantly agricultural lands. Construction is expected to be completed in 2 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Build three 1-way switches on line 0794 to accommodate new Sauk Centre Municipal distribution substation.

Need Driver: Interconnection request from Sauk Centre Municipal for a new substation to address reliability issues on the distribution system.

General Impacts: The project will install a new substation along existing 69 kV line. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Phase 1 of the project will consist of constructing a new 12-mile 115 kV line from the Big Stone 230/115 kV substation (located near Big Stone City, SD) to a new 115/12.5 kV substation located near Milbank, SD. In addition, a portion of the town of Milbank, SD will be moved to the 115 kV system. Phase 1 of the project is located entirely within South Dakota. Phase 2 of the project will consist of construction a new 18.5-mile 115 kV line from the new 115/12.5 kV substation located near Milbank, SD to a new switching station on the Big Stone – Marietta 115 kV line located in Minnesota.

Need Driver: Planned load growth in Milbank, SD will bring the area’s 41.6 kV transmission system beyond its capacity. Low voltages have been identified on the 41.6 kV transmission system in studies for the loss of the Highway 12 115 kV source. This project will move load to the 115 kV system and free up capacity on the area’s 41.6 kV system.

Several transmission alternatives were studied. The selected project is able to maintain system reliability at a low cost and is able to meet the timelines of the load expansion.

This project is related to a load expansion, and non-wires alternatives would not provide sufficient availability or reliability to support the load.

Analysis: OTP performed a study to investigate projects to serve a load expansion in Milbank, SD. This analysis reviewed the selected project, as well as the transmission alternatives listed above. The analysis identified the selected project as the lowest-cost option while maintaining system reliability and meeting the timeline of the load expansion.

Schedule: The Minnesota portion of the project is expected to be completed by the end of 2026. A CON will be required due to the line crossing the South Dakota border. OTP expects to file the CON in Q2 of 2024.

General Impacts: This project will require approximately 30.5 miles of new 115 kV transmission line (approximately 4 miles in Minnesota) from the Big Stone 230/115 kV substation to a new 115/12.5 kV substation near Milbank, SD to a new switching station on the Big Stone – Marietta 115 kV line. The project is located in predominantly agricultural lands. Prior to construction OTP will acquire the necessary right-of-way and permits for construction of the project. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. During this time, OTP and/or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Utility: Great River Energy (GRE), Minnesota Power (MP), Missouri River Energy Services (MRES), Otter Tail Power Company (OTP), Xcel Energy (XEL)

Project Description: GRE, MP, MRES, OTP, and XEL are jointly developing the Big Stone South – Alexandria – Big Oaks 345 kV line, located in western and central Minnesota. The project consists of two major segments of transmission line construction:

Need Driver: With growth of wind energy projects in the Dakotas and Western Minnesota, there is not enough capacity on the transmission system to transfer that energy from the Dakotas and Western Minnesota to the Twin Cities load center.

Analysis: Full details of MISO’s LRTP Tranche 1 analysis are available in the LRTP Addendum to the MTEP21 report.

Schedule: The Eastern Segment is expected to be completed in 2027. The Western Segment is planned to be completed by the end of 2030.

General Impacts: This project will require approximately new 115 kV transmission line from the Big Stone 345 kV substation to the Alexandria 345 kV substation. The project is located in predominantly agricultural lands. Prior to construction necessary right-of-way and permits will be acquired for construction of the project. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. During this time, GRE, MP, MRES, OTP, and XEL and/or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Install (2) new storm structures every 5 miles along the ME-BW line between structures 306 and 415 as there are no full stop deadends in this section of line. Possible locations are structures 349 and 383.

Need Driver: Historical cascading failures on h-frame lines in ND as well as on the WB line for 19 miles. Majority of line is cross country, so would be difficult to re-construct in an emergency.

General Impacts: The project will be constructed on the existing 115 kV transmission line from Big Swan substation to Wakefield substation. The project is located in predominantly agricultural lands. Construction is expected to be completed in 2 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Utility: Great River Energy (GRE), Missouri River Energy Services (MRES), Southern Minnesota Municipal Power Agency (SMMPA)

Project Description: Rebuild existing 69 kV transmission lines: Willmar to Litchfield Muni Tap, Litchfield to Litchfield Muni Tap, Hutchinson to Litchfield Muni Tap to 115 kV standard with high-capacity conductor for continued operation at 69 kV. Build a new 115 kV line from Litchfield Muni to Stockade substation. Convert upgraded facilities to 115 kV operation.

Need Driver: The lines between Willmar, Litchfield and Hutchinson have a need to be rebuilt due to age and condition concerns. These lines are some of the oldest 69 kV transmission lines in the area. The line rebuild projects will be done in such a way that it makes the load serving transmission system more resilient, creates opportunities for increased penetration of large loads and renewable resources, and solves existing or future reliability concerns in the transmission system.

Transmission system assessment studies have shown that the existing transmission system is not resilient and doesn't have margin to serve new or growing loads in the Hutchinson and Glencoe areas. The Hutchinson and Glencoe areas experience low voltage problems for NERC category P6 contingencies. To improve system, post contingent voltage, address reliability concerns due to the transmission line age and condition, and make capacity available to serve large loads in the system, GRE will coordinate with SMMPA and MRES to construct a 115 kV line between Willmar and Hutchinson substations, via Litchfield and Stockade. Most of this future 115 kV line will involve an upgrade of existing 69 kV lines to 115 kV voltage that will continue to operate at 69 kV until the line is permitted for 115 kV operation.

Operating the transmission at 115 kV would require double circuiting the line between Willmar and Svea (SH), rebuilding the line between Svea substation and Hutchinson (DS/HN), rebuilding the SMMPA operated line between Litchfield Municipal and the Willmar-Hutchinson line (LT) to a double circuit for an in-and-out configuration to Litchfield Municipal, rebuilding the GRE line between Litchfield Municipal and the Big Swan-Atwater line (LN) and construction of 8 miles of new 115 kV line from Litchfield Municipal North Tap to connect to the Stockade substation.

GRE, SMMPA and MRES would first complete the following projects to address age and condition concerns in the transmission system:

Following the completion of the above age and condition related line rebuild projects, GRE, SMMPA and MRES will work on the following projects to operate the transmission system at 115 kV:

Analysis: The line rebuild projects bring efficiency improvement as there will be less power loss on the transmission line. It also provides better load serving reliability as it will be new, consist of larger conductor and be constructed to the 115 kV standard. The line rebuild makes capacity available in the transmission system for a new load that may come to the areas.

General Impacts: The project will be constructed on an existing 70-foot right-of-way that is largely located on agricultural lands. While this project is at the end of the planning phase and although some additional temporary workspace may be required, no new landowners are expected to be impacted due to the line rebuild projects. Construction of a new 8-mile 115 kV line from Litchfield Municipal North to the Stockade substation require acquiring new route and easement and will impact new landowners along the transmission line.

Project Description: Convert and relocate the Lake Mary substation from 41.6 kV to 115 kV service. Installing a 3-way 2000A load break switch and construct the new 115 kV tap line to the new Lake Mary substation location east of highway 29.

Need Driver: Lake Mary substation is reaching capacity, and REA has been monitoring the substation load to determined that upgrade is needed. In addition to the substation capacity increase that will be needed, the existing location is not preferred as it is difficult to build out new feeders to the growing area that is north of the Lake Mary distribution substation. A reliability improvement to the Lake Mary substation was also needed as it is served from on a 2 mile tap line is of 1968 vintage. With the robust 115 kV transmission system in the vicinity, the reliability improvement need would be accomplished by the conversion of the Lake Mary substation from 41.6 kV to 115 kV service. RE plans to retire and remove the existing 41.6 kV tap line to Lake Mary after the conversion of the Lake Mary substation for 115 kV service.

Analysis: The relocation and conversion of the Lake Marion substation to 115 kV service was found to be the best value plan that results in a reliable and resilient service in the area that is served by the Lake Mary distribution substation. This project reduces system losses, reduces impacts landowners and fosters economic development in the area.

Schedule: The Lake Mary 115 kV Conversion project is planned to be in-service by August 2024.

General Impacts: The project will require approximately 0.2 miles of new 115 kV transmission line from the MRES-AA 115 kV line to new Lake Mary substation location. The project is located in predominantly industrial lands. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design minimizes impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 12 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: Install a 3-way manual load break 115 kV, 2000 A switch on GRE’s Walden – Morris 115 kV line and construct about 2 spans of 115 kV line with 477 ACSR conductor to the high side of Agralite’s new Hodges area distribution substation. Install metering/telecom and a new EEE for the distribution substation.

Need Driver: Agralite desires to establish a new substation in the Hancock area to serve fast growing loads in the area around Hancock. Currently, this area is served from Hancock and Alberta substation. The fast-growing load in the area is loading up the transformer and a new substation is required to unload the existing Hancock and Alberta substations and serve new loads in the area.

Analysis: This project establishes a distribution substation to serve growing load in the area. Existing distribution substations are located far from the load center. Extending long feeders were found to be unreliable and lossy. This project was found to be the best value plan to reliably serve existing and growing load in the area.

Schedule: The Hodges Substation project is planned to be in-service by summer 2025.

General Impacts: The project will require approximately 0.05 miles of new 115 kV transmission line from the GRE AG-MB 115 kV line to the Hodges substation. The project is located in predominantly agricultural lands. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 12 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: The Mud Lake – Riverton (MR) 230 kV line is temperature rated at 189 degrees and is limited by seven spans. Make the necessary upgrades, six H-frame pole replacements, to get the Mud Lake – Riverton (MR) 230 kV line up to 212°F operating temperature and achieve a rating of 384.8/515.8 (summer/winter) MVA.

Need Driver: The Mud Lake – Riverton (MR) 230 kV line is temperature rated at 189 degrees which is limited by a couple of poles. This 212 degree F rating is needed post Boswell shutdown around 2029/2030.

Analysis: Replacing a handful of poles will be able to get the line to 212 degree F operating temperature which will meet the loading needs in this part of the transmission system. An age and condition assessment suggests that a full rebuild isn't necessary and would be premature. Another transmission line is significantly more costly than to replace a handful of structures.

Schedule: The Mud Lake – Riverton Line Upgrade project is planned to be in-service by winter 2024.

General Impacts: The project will be constructed on the existing 230 kV transmission line from Mud Lake substation to Riverton substation. The project is located in predominantly agricultural lands. Construction is expected to be completed in 6 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Installation of (2) 75 MVar capacitor banks, installation of 3 new 345 kV breakers to complete the breaker and a half.

Need Driver: MISO required installation these capacitor banks for voltage regulation due to Generator Interconnections on the MISO system.

Analysis: The need for the Cedar Mountain substation upgrades was evaluated as part of the MISO DPP system impact studies.

Schedule: The Cedar Mountain Substation Upgrade project is planned to be in-service by summer 2024.

Project Description: A new 115 kV breaker and a half row and tap line would be built out to accommodate the interconnection of the 100 MW solar farm for J1426.

Need Driver: J1426 Solar facility has requested interconnection to the 115 kV bus at Benton County.

Analysis: The expansion of facilities at Benton County are required to provide a point of interconnection for project J1426.

Schedule: The Benton County Solar Farm project is planned to be in-service by spring 2025.

Project Description: Increase the rating of 115 kV lines from Morris to Grant County to East Fergus Falls by installing phase raisers or structure replacements.

Need Driver: Market Participant requested that the line be upgraded due to local congestion.

General Impacts: The project will be constructed on the existing 115 kV transmission line from Morris to Grant County to East Fergus Falls substations. The project is located in predominantly agricultural lands. Construction is expected to be completed in 3 months. During this time, MRES and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Alexandria Light & and Power (ALP) will build a new distribution substation on the southeast part of town. The substation will tap and existing 115 kV line with an in and out substation. The substation will have a 115 kV to distribution transformer.

Need Driver: Distribution studies showed deficiencies present in the existing distribution system and to the need for a new distribution substation to support additional load growth within the City of Alexandria.

Analysis: The need for a new distribution substation to support load growth was identified in Distribution System Planning Update report. The new distribution substation allows for more load growth within the City of Alexandria

General Impacts: This project is located at the outer edge of town not near residential homes. Construction is expected to be completed in 18 months. During this time the ALP, and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Alexandria Substation will be expanded to add positions for new 345 kv transmission line to Big Oaks and Big Stone South substations.

Need Driver: The BSSA/ABP Project, along with the other LRTP Tranche 1 Portfolio of transmission projects, are needed to provide reliable, resilient, and cost-effective delivery of energy as the generation resource mix.

Analysis: The generation resource mix is changing as more renewable and variable energy, such as wind and solar, is added to the system and aging coal-fired generation plants are retired. The BSSA/ABP Project, along with the other LRTP Tranche 1 Portfolio of transmission projects, are needed to provide reliable, resilient, and cost-effective delivery of energy as the generation resource mix continues to evolve over the coming years.
Schedule: The project is planned to be in-service by Q4 2026/27.

General Impacts: The Alexandra Substation is located on the south end of Alexandria, MN. The substation will be expanded to accommodate the transmission lines to Big Oaks and Big Stone South . The project is located in predominantly agricultural lands. Construction is expected to be completed in 24 months. During this time, MRES and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Need Driver: This line has caused market congestion in the past and is projected to continue to cause market congestion into the future.

Analysis: The structure replacements will increase the ratings of the line, reducing the likelihood of the lines causing congestion in the market. It is expected that the rating increase from the structure replacement will mitigate projected congestion in the near term, and a full rebuild is not required.

General Impacts: The project will be constructed on the existing 115 kV transmission line from Inman substation to Miltona substation. The project is located in predominantly agricultural lands. Construction is expected to be completed in 6 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Need Driver: This terminal equipment has caused market congestion in the past and is projected to continue to cause market congestion into the future.

Analysis: The equipment upgrade will increase the ratings of the 230 kV lines out of Benton County, reducing the likelihood of these lines causing congestion in the market.

Need Driver: The line from Johnson Junction to Morris has caused market congestion in the past and is projected to continue to cause market congestion into the future.

Analysis: This upgrade will prevent switch from being the binding rating and allow for the line conductor capacity rating to be fully utilized, reducing the likelihood of the line causing congestion in the market.

General Impacts: This will be constructed on an existing 115 kV transmission line right of way. Construction is expected to be completed in 6 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

The table below identifies those projects by Tracking Number in the West Central Zone that were listed as ongoing projects in the 2021 Biennial Report but have been completed or withdrawn since the 2021 Report was filed with the Minnesota Public Utilities Commission in October 2021. Information about each of the completed projects is summarized briefly in the table below. More information about these projects and inadequacies can be found in earlier reports. Projects that were listed as being complete in the 2021 Report are not repeated here, but more information about those projects can be found in these earlier reports.

The following table provides a list of transmission needs identified in the Twin Cities Zone by MISO utilities. There were no projects identified in this zone by non-MISO utilities.

MPUC Tracking Number	MISO Project Name	MTEP Year/App	MTEP Project Number	CON?	Non-Wires Alt.	Utility
2021-TC-N5	Lawndale – Bass Lake 115 kV Line	2015/A	7912	No	No	GRE
2021-TC-N6	Rush City 230 kV Ring Bus	2023/A	23718	No	No	GRE
2021-TC-N7	Bunker Lake 345 kV Ring Bus	Future	TBD	No	No	GRE
2021-TC-N8	Medina Breaker Addition and Replacement	Future	TBD	No	No	GRE
2021-TC-N9	Parkwood 115 kV Ring Bus Expansion	2022/A	22025	No	No	GRE
2021-TC-N10	Bunker Lake – Elk River Storm Structures	2022/A	21826	No	No	GRE
2023-TC-N1	Blue Earth-South Bend Area Upgrades	2022/A	20505	No	No	XEL
2023-TC-N2	Elm Creek TR10	2022/A	21285	No	No	XEL
2023-TC-N3	NSPM Metro Steel Pole Replacement	2022/A	21845	No	No	XEL
2023-TC-N4	Hyland Lake TR1 and TR2 Upgrade	2022/A	21846	No	No	XEL
2023-TC-N5	Coon Creek Substation 345kV Breaker Additions	2022/A	21877	No	No	XEL
2023-TC-N6	Rogers Lake Breaker Addition	2022/A	21887	No	No	XEL
2023-TC-N7	Blue Lake Substation - FRM13	2023/A	23347	No	No	XEL
2023-TC-N8	West Shakopee Interconnection	2022/C	21892	No	No	XEL
2023-TC-N9	STY Install TR3 & 115kV Bus Tie	2023/A	23450	No	No	XEL
2023-TC-N10	Line 0811 - Riverside Substation - FRM13	2023/A	23453	No	No	XEL
2023-TC-N11	Line 0838 - Red Rock Substation - FRM13	2023/A	23454	No	No	XEL
2023-TC-N12	Parkers Lake TR09 ELR	2023/A	23455	No	No	XEL
2023-TC-N13	Line 0893 NSS-BCK Rebuild	2023/A	23458	No	No	XEL
2023-TC-N14	Line 0718 Arlington - Winthrop Rebuild	2023/A	23462	No	No	XEL
2023-TC-N15	Edina Switch Replacement	2023/A	24278	No	No	XEL
2023-TC-N16	Lyon County Substation - FRM13	2023/A	23712	No	No	XEL
2023-TC-N17	21829 - South Dayton Interconnection	2023/A	23547	No	No	XEL
2023-TC-N18	Line 0859 Str 16 to Chemo lite Rebuild	2023/A	23467	No	No	XEL
2023-TC-N19	Chisago County Substation - FRM13	2023/A	23468	No	No	XEL
2023-TC-N20	Scott County Substation - FRM13	2023/A	23469	No	No	XEL
2023-TC-N21	Line 0771 Rebuild	2023/A	23502	No	No	XEL
2023-TC-N22	Line 0840 Elliot Park Pumping Plants	2023/A	23501	No	No	XEL
2023-TC-N23	Lake Pulaski TR05 ELR	2023/A	23497	No	No	XEL
2023-TC-N24	Inver Grove TR02 ELR	2023/A	23496	No	No	XEL
2023-TC-N25	Prairie Island TR10 ELR	2023/A	23494	No	No	XEL
2023-TC-N26	Monticello TR06 & TR10 ELR	2023/A	23493	No	No	XEL
2023-TC-N27	Line 0892 RRK-BCK Rebuild	2023/A	23473	No	No	XEL
2023-TC-N28	Line 0736 Arden Hills - Lawrence Creek Rebuild	2023/A	23475	No	No	XEL
2023-TC-N29	Line 0721 STR 71 to 476 Rebuild	2023/A	23475	No	No	XEL
2023-TC-N30	Line 0822 Empire to STR 107 Rebuild	2023/A	23476	No	No	XEL
2023-TC-N31	Inver Hills Substation - FRM13	2023/A	23486	No	No	XEL
2023-TC-N32	Parkers Lake TR10 ELR	2023/A	23491	No	No	XEL
2023-TC-N33	Kohlman Lake Substation - FRM13	2023/A	23487	No	No	XEL
2023-TC-N34	Wilmarth Substation - FRM13	2023/A	23489	No	No	XEL
2023-TC-N35	Eidswold Distribution Substation	2023/A	23819	No	No	GRE
2023-TC-N36	Arbor Lakes II Distribution Substation	Future	TBD	No	No	GRE
2023-TC-N37	Pilot Knob to Deerwood Area Projects	2023/A	23921	No	No	GRE
2023-TC-N38	Laketown Distribution Substation	2023/A	23763	No	No	GRE
2023-TC-N39	Cedar Lake Tap Line Relocation	2023/A	22871	No	No	GRE
2023-TC-N40	Fischer Distribution Substation Rebuild	Future	TBD	No	No	GRE
2023-TC-N41	Lakeville Area Projects	2024/A	25405	No	No	GRE
2023-TC-N42	Burnsville Substation Upgrade	2024/A	25358	No	No	GRE

Project Description: Construct approximately 2 miles of new 115 kV transmission line from the new Lawndale #2 115 kV distribution substation to an interconnection with the GRE Bass Lake – Cedar Island 115 kV transmission line on existing GRE 69 kV corridor.

Need Driver: This project is needed interconnect the Lawndale #2 distribution substation and establish a looped transmission service to the Corcoran and Lawndale distribution substations.

Analysis: Adding an alternate 115 kV source into the Lawndale Substation property will provide better diversity and overall reliability to the area as opposed to doubling the load and number of customers on a transmission line that does not have an alternate source in the case of damage.

General Impacts: The project will require approximately 2 miles of new 115 kV transmission line from Lawndale #2 substation to an interconnection with the GRE Bass Lake – Cedar Island 115 kV line. The project is located in existing GRE 69 kV right of way corridor. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 24 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: Complete Rush City 230 kV ring bus. Build independent terminals for the Rock Creek – Rush City and Red Rock – Rush City 230 kV lines.

Need Driver: This project is needed to mitigate age and condition-related concerns and address overload issues associated with NERC TPL-001-4 P6 events.

Transmission Alternatives
This project requires completing the existing substation ring bus. No alternatives were considered.

Non-Wires Alternatives
This a reliability improvement at the substation and no alternatives were considered.

General Impacts: This project is located on GRE owned property. Construction is expected to be completed in 18 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Need Driver: The 345 kV transmission lines terminate with a switch at Bunker Lake substation. This project is needed to terminate the 345 kV lines in to a new 345 kV ring bus, improving system reliability.

Transmission Alternatives
This project is the only option considered to address the reliability concerns.

Non-Wires Alternatives
This a reliability improvement at the substation and no alternatives were considered.

Project Description: Add a breaker at Medina substation on the Crow River – Medina 115 kV line. Add a breaker at the Medina substation on the 115/69 kV transformer. Replace breaker 55WB2.

Need Driver: The Crow River to Medina 115 kV line terminates with a switch at the Medina substation. A fault on the line would trip the entire substation. A fault on the Medina 115/69 kV transformer also trips the entire substation. The breaker installations are needed to limit equipment outage as a result of a fault. Breaker 55WB2 is Siemens BZO hydraulic breaker. There's limited parts availability. There have been past maintenance issues with this breaker, and it's the last oil breaker left at Medina.

Alternatives:
Transmission Alternatives
The need required installation of a breaker to protect the substation from tripping due to a fault. The project was the only alternative considered to address the problem.
Non-Wires Alternatives
This a reliability improvement at the substation and no alternatives were considered.

Analysis: Replacement of the 115 kV switch with a breaker improves the reliability and resiliency of service at the Medina substation. These replacement projects are done within the substation fence and have minimal impact on landowners in the area.

Project Description: The project will change the 115 kV bus topology from the current bus tie breaker topology to a ring bus topology, with alternating line and transformer connections in the ring. Consider space for a six-position ring bus topology with future expansion to a 1.5 bus topology. Breaker 12WB2 replacement is also in scope.

Alternatives:
Transmission Alternatives
This project reconfigures and updates existing topology to address reliability concerns at the Parkwood substation. No additional alternative was considered.
Non-Wires Alternatives
This a reliability improvement at the substation and no alternatives were considered.

Project Description: Install storm structures in the Bunker Lake - Elk River 230 kV line.

Need Driver: GRE is continuing to look at making the system more resilient. GRE has H-frame construction on multiple lines that have shown to be prone to line cascading (domino effect) resulting in long duration outages. One way is to limit the damage of cascading is to install stop structures, such as a storm structure. GRE is proposing to install storm structures that will limit damage from cascading to 5 to 10 mile sections rather than without storm structures, whereby significantly longer mileage of damage could occur.

General Impacts: The project will be constructed on the existing 230 kV transmission line from Bunker Lake substation to the Elk River substation. The project is located in predominantly agricultural lands. Construction is expected to be completed in 2 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction.

Project Description: Rebuild approx. 30 miles of 161 kV line and upgrade South Bend TR6 to a 448 MVA transformer.

Alternatives:
Transmission Alternatives
None.
Non-Wires Alternatives
This a reliability improvement to an existing line and transformer and no alternatives were considered.

General Impacts: The project will be constructed on the existing 161 kV transmission line from Blue Lake substation to the South Bend substation and upgrading the existing South Bend TR6. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right of way will be restored at the end of the project.

Project Description: Install second 345/115 kV transformer at Elm Creek sub and route SherCo-Coon Creek #1 345 kV Line Into Elm Creek Sub

Need Driver: Additional load serving capability in the area. Removes need to shed load under contingency. Eliminates need for line rebuilds in the area, which would otherwise be required.

General Impacts: Transmission addition of additional transformer and retermination of existing line are on existing footprint. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right of way will be restored at the end of the project.

Project Description: Address painted poles concerns between Riverside Sub and Main Street Sub. Approximately 4-mile of triple circuit structure(35-structures) to be either replaced, painted or a combination of replace/paint.

Need Driver: The existing structures were installed in the 1980s and are experiencing paint peeling and steel deterioration.

General Impacts: Replacement and/or painting of existing structures. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right of way will be restored at the end of the project.

Project Description: Upgrade TR1 and TR2 to 115/13.8 kV 70 MVA transformers at Hyland Lake Substation. Install high-side line breaker. Install new feeder bay.

Need Driver: Hyland Lake TR1 and TR2 have distribution load at risk under contingency.

General Impacts: Upgrade of existing transformers and addition of additional reliability protection. Additional feeder bay to support providing reliable customer service. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Install three 345kV circuit breakers at the Coon Creek (CNC) substation to provide a better isolation between the Main Bus 1 & 2 to the line 1 & 2.

Need Driver: Three breakers needed to isolate the SHC-CNC “Line 1” and “Line 3” from the 345kV Main Bus 1 and 2, which will prevent loss of large portions of substation during existing breaker trip.

General Impacts: Additional breakers in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Install two breakers at Rogers Lake to separate Airport – Rogers Lake 115 kV line and Rogers Lake TR2

Need Driver: Eliminate single breaker failure and eliminate distribution exposure by terminating the line and TR2 into individual positions in the breaker and a half scheme at RLK.

Project Description: Replace ammeter on Blue Lake 345 kV breaker 8M33 to increase rating on the Blue Lake - Scott County 345 kV line.

Need Driver: Blue Lake - Scott County 345 kV line is ratings limited by a single ammeter on the Blue Lake 345 kV breaker 8M33.

General Impacts: Ammeter replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: City of Shakopee T-L Interconnection Request. In-and-out off NSP’s Scott County - Dean Lake 115 kV transmission line. Joint substation, NSP will own the high side.

Need Driver: Needed to accommodate the rapidly developing load growth along the western edge of the City of Shakopee’s territory.

Alternatives:
Transmission Alternatives
None.
Non-Wires Alternatives
Load interconnection request, no alternatives considered.

General Impacts: The project will install a new substation along existing 115 kV line. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Install new 115 kV bus tie and associated disconnect switches and bus work and re-terminate 0818/5529 at Rogers Lake Sub.

Need Driver: Needed to accommodate third distribution transformer due to capacity, location, and load.

General Impacts: Additional bus tie and switches in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Replace switches 5M330B, 5M331B, 5M329A, 5M330A, 5M329B, 5M331A, aux current transformers on 5M304 and 5M305, and two sections of busbar.

Need Driver: FRM13 projects needed to address line derates caused by new split-path methodology.

General Impacts: Switch, busbar, and current transformer replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Replace bushing current transformers on breaker K2, switches K2B1, 946B, K2B2, 946A, and meters on 946 and K2.

Need Driver: FRM13 projects needed to address line derates caused by new split-path methodology.

General Impacts: Switch, current transformer, and meter replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Need Driver: The ELR transformer program is to proactively replace aging transformers that have past their operational service life and are showing increase signs of degradation.

General Impacts: Transformer replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Rebuild 3.4 miles of 115 kV line between North Star Steel and Battle Creek substations. Portions of this line are double circuited with 0892, this project will separate the two circuits.

Need Driver: Needed to increase reliability and performance of the line due to deterioration from age and wet environment.

Alternatives:
Transmission Alternatives
Line may be used as is, but this runs the risk of reliability and overloading issues. No alternatives were considered.
Non-Wires Alternatives
This is replacing an existing asset.

Analysis: Verifying the secondary limit on the Farmington – Lake Marion 69 kV line, and limit may need to be replaced. No other immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Project Description: Rebuild 15 miles line 0718 69 kV from Arlington - Winthrop.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Project Description: Replace 115 kV switch at Edina, which is limiting the rating of the Edina - St. Louis Park 115 kV line.

Need Driver: Remediates overloads on the Edina - St. Louis Park 115 kV line.

General Impacts: Switch replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Replace 5N130 actuator secondary current limitation to increase TR9 rating to its transformer limits.

General Impacts: Actuator replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: New GRE interconnection (MTEP ID 21829). Xcel Energy will own high side of new sub with an in-and-out configuration on the Elm Creek - Champlin Tap 115 kV line.

Alternatives:
Transmission Alternatives
None.
Non-Wires Alternatives
Interconnection request connecting to existing line. No alternatives considered.

Project Description: Rebuild 6.9 miles of line 0859 115 kV from Chemolite substation to structure 16.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Project Description: Replace primary and secondary 115 kV bus 1 differential relays for TR05 and TR06.

General Impacts: Relay replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

General Impacts: Busbar replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Rebuild 2 miles of line 0771 from Young America - Carver County 69 kV substations and add OPGW.

Need Driver: Needed to increase reliability and performance of the line due to deterioration from age and wet environment.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Need Driver: Pumping plant is required to maintain electrical supply to the substation.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Equipment upgrades will have minimal impacts to existing system performance and footprint.

Need Driver: The ELR transformer program is to proactively replace aging transformers that have past their operational service life and are showing increase signs of degradation.

Project Description: Replace Monticello 345/230 kV TR06 and 345/115 kV TR10.

Need Driver: The ELR transformer program is to proactively replace aging transformers that have past their operational service life and are showing increase signs of degradation.

Project Description: Rebuild 3.4 miles of 115 kV line between Red Rock and Battle Creek substations. Portions of this line are double circuited with 0893, this project will separate the two circuits.

Need Driver: Needed to increase reliability and performance of the line due to deterioration from age and wet environment.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Line 0736 Arden Hills - Lawrence Creek Rebuild

Project Description: Rebuild 33 miles of line 0736 69 kV from Arden Hills - Lawrence Creek and add OPGW.

Need Driver: Needed for age and condition rebuild. Increasing the capacity of this circuit and potentially converting it to 115 kV in the future will reduce overloading of underground transmission cable at White Bear Lake.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Line 0721 STR 71 to 476 Rebuild

Project Description: Rebuild 22 miles line 0721 69 kV from Structure 71 - Structure 476.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Project Description: Rebuild 7 miles of line 0822 115 kV from Empire to Str 107 and add OPGW.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Need Driver: FRM13 projects needed to address line derates caused by new split-path methodology.

Need Driver: The ELR transformer program is to proactively replace aging transformers that have past their operational service life and are showing increase signs of degradation.

Need Driver: FRM13 projects needed to address line derates caused by new split-path methodology.

General Impacts: Meter replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Replace bushing current transformer on breaker 5S11 as well as switches 8S26B1, 8S25B, 8S25A, 8S26B1.

Need Driver: FRM13 projects needed to address line derates caused by new split-path methodology.

General Impacts: Switch and current transformer replacement in existing substation to support transmission reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: New 115/12.47 kV substation for Dakota Electric Association (DEA) in the Elko New Market area.

Need Driver: A new 115/12.47 kV distribution substation is required by DEA with provisions for future second 115/12/47 kV transformer. The need is based on a new industrial park load which is expected to increase load demand beyond what they can currently serve from existing substations.

The new industrial load is expected to be energized for 2024. This load is initially expected to be 7 MW but could expand with additional load growth.

The new substation is proposed in the Elko New Market area of Minnesota. The location will be east of Interstate 35 in the area highlighted in the system map. The only transmission line available for interconnection is Xcel Energy’s 0832 115 kV line, approximately 2 miles south of Chub Lake substation.

Alternatives:
Transmission Alternatives
New 115 kV line from Chub Lake. This was not considered a viable alternative as there is an existing 115 kV line adjacent to the site with capacity.
Non-Wires Alternatives
Non-wires alternatives cannot adequately accommodate load growth forecasts, assuming a cost of $500/kWh.

Analysis: This project was needed from a capacity standpoint. The existing distribution infrastructure did not have the capacity to serve a new industrial load in this area.

General Impacts: The project will require approximately 0.10 miles of new 115 kV transmission line from the Xcel 0832 115 kV line to Eidswold substation. The project is located in predominantly agricultural lands. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 12 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: Wright-Hennepin Cooperative Electric Association (WHCEA) plans to double end the Arbor Lakes substation. GRE will need to provide a tap, switch, and metering/telecom. Sys. Ops has confirmed 2000A manual, three-way, full load break switch is required. GRE engineering requires a steel pole on a foundation for the switch. Added steel pole grading structure north of the existing switch.

Need Driver: WHCEA needs to support growing load that can’t be served by existing distribution substations in the area.

Alternatives:
Transmission Alternatives
The existing substation was planned to accommodate a second transformer when needed. No additional alternative was considered.
Non-Wires Alternatives
Non-wires alternatives cannot adequately accommodate load growth forecasts.

Analysis: The Arbor Lake substation was planned to accommodate a second transformer when the need for capacity occurs. The extensive load growth that is seen and coming around the Arbor Lake I distribution substation requires a new distribution substation. It was found that adding a second transformer at the Arbor Lake substation is the least cost plan to address the capacity need and serve the area reliably. This project has no impact on landowners in the area as it will all be done within the property of GRE and its member owner.

Schedule: The Arbor Lakes II project is planned to be in-service by fall 2024.

General Impacts: The project will require approximately 0.10 miles of new 115 kV transmission line from the GRE WH-CA 115 kV line to the Arbor Lakes II substation. The project is located in predominantly industrial lands. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 12 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: Rebuild the Pilot Knob Substation to a breaker and a half configuration due to age and condition of the current equipment. Upgrade the DA-PD line from Deerwood to Pilot Knob substation to increase the capacity. Upgrade to be built to 115 kV standards but operated at 69 kV. Retire the underground portion of the DA-PLX at Pilot Knob and replace with overhead. Retire the DA-RE line from Pilot Knob Road to Black Hawk Road. Retire the DA-PKX from Pilot Knob to Cliff Road. Retire SS-2820 and replace with a turning structure. Retire SS-2819.

Need Driver: Pilot Knob substation age and condition require upgrade. DA-RE needs to be retired to allow for the county to upgrade the section of Pilot Knob Road. DA-PKX is no longer needed if the DA-RE is retired.

Alternatives:
Transmission Alternatives
Alternatives considered were rebuilding the line at 69 kV standards. For the following reasons GRE is rebuilding the line to 115 kV standard and operating at 69 kV until all associated 69 kV lines can be upgraded and the transformers at Pilot knob removed to create a 115 kV looped service between Pilot Knob and Burnsville:

Transformer Costs. The 69 kV system requires the 115/69 kV transformer at Pilot Knob Substation. Removing these high-cost transformers will result in cost savings to the consumer and remove the piece of equipment from creating reliability issues, which typically have long outage periods prior to replacing a failed unit.
Non-Wires Alternatives
Non-wires alternatives were not considered due to the replacement need for age and condition.

Analysis: An Analysis of the project was studied against the alternative of the system remaining at 69 kV, as described in the alternatives section.

General Impacts: The project is located on existing property and exiting GRE 69 kV right of way corridor. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 24 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: Construct about 3 to 5 miles 115 kV transmission line from GRE’s 115 kV line near Victoria Tap. The interconnecting lines be constructed as an in-and-out design to accommodate a future double-ended sub.

Need Driver: MVEC is requiring the new Laketown substation because of the additional load planned in Laketown Township. The existing substations in this area will be at capacity and will not be able to serve the additional load in the future.

Alternatives:
Transmission Alternatives
Alternative 115 kV connections were considered but did not sectionalize the system as well as connecting to the MV-VTT line between Augusta and Victoria. This section provided the best reliability and resiliency.
Non-Wires Alternatives
Non-wires alternatives for this project are under review.

Analysis: A distribution analysis was performed. This showed the need for a new substation in the area due to lack of feeder redundancy, load growth in an area with no distribution substation, and future feeder overload and voltage issues on lines already with voltage regulators in use

Schedule: The Laketown Substation project is planned to be in-service by fall 2028.

General Impacts: The project will require approximately 3 to 5 miles of new 115 kV transmission line from the Xcel Energy 5557 115 kV line to Laketown substation. The project is located in predominantly agricultural lands. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 12 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: Design and construct a tap line approximately 6.5 miles and capable for 115 kV. Remove existing tap switch and line on the CapX line.

Need Driver: The Cedar Lake tap needs to be removed from the CapX to allow for the Helena – Hampton Corners 345 kV second circuit.

Alternatives:
Transmission Alternatives
A connection to the 69 kV lines to the west and to the south were considered. However, these Xcel Energy circuits to the west and south of the substation are not recommended for a new Cedar Lake tap due to concerns related age), reliability and limited capacity. Triple circuiting the CapX line was deemed not feasible as it would require new foundations and poles.
Non-Wires Alternatives
Transmission solution required due to existing distribution substation need to be connected to the transmission system.

Analysis: This project was needed due to the second Helena-Hampton 345 kV line project. This was a congestion reduction project submitted by Xcel Energy.

Schedule: The Cedar Lake Tap Line Relocation project is planned to be in-service by fall 2025.

General Impacts: The project will require approximately 6.5 miles of new 115 kV transmission line from the GRE MV-EVX 115 kV line to Cedar Lake substation. The project is located in predominantly agricultural lands. Prior to construction, GRE will acquire the necessary right-of-way and permits for construction of the project. GRE anticipates acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, GRE will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 12 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: DEA plans to update their 115 kV Fisher in/out distribution substation (both east and west) on the same property to replace the aged substation equipment. GRE will need to move the meter and telecom equipment as part of this work. GRE will also be adding a breaker and associated controls to this site.

Need Driver: This project is needed due to aging infrastructure that needs replacements. The installation of a breaker is needed for improved reliability to areas served from Fisher distribution substation. This breaker will effectively prevent the tripping of both Fischer distribution substations in the event of a line fault.

Alternatives:
Transmission Alternatives
This project was needed for age and condition and will not involve new transmission lines or substations; therefore, no other alternatives were considered.
Non-Wires Alternatives
Non-wires alternatives were not considered due to the replacement need for age and condition.

Analysis: Distribution analysis determined the need for new equipment based on the age and condition of existing equipment at the substation. The need for a new breaker was determined based on reliability and outage data. A breaker at this site will improve reliability by reducing the line exposure Fischer distribution substations.

Schedule: The Fischer Distribution Substation Rebuild project is planned to be in-service by fall 2025.

General Impacts: This project is located on GRE-owned property and right-of-way. Construction is expected to be completed in 6 months. During this time, GRE and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: GRE will be adding a second radial circuit tap (double circuit) into Lakeville substation for the addition of a second transformer and switchgear to Lakeville substation. Dakota Electric Association (DEA) is responsible for the high side structures and associated transmission side substation equipment.

Need Driver: Dakota Electric Association needs a second transformer at the Lakeville site due to limited capacity of the existing distribution transformer.

Alternatives:
Transmission Alternatives
As this project is using existing transmission lines to connect to a new transformer, an alternative of building new transmission lines was not considered.
Non-Wires Alternatives
Non-wires alternatives cannot adequately accommodate load growth forecasts.

Analysis: Distribution analysis showed that a second transformer was required due to the limited capacity of the existing transformer and the load growth in the area.

Schedule: The Lakeville Area Projects are planned to be in-service by fall 2025.

Project Description: This project involves the following at Burnsville substation: replace and relocate EEE (all new panels/relays/etc.), soil correction at new EEE site, northwest fence line expansion, replacement of 5M197, and add breakers with new 115 kV ring bus configuration on north end of substation.

Alternatives:
Transmission Alternatives
This is an equipment reliability improvement at the substation and no alternatives were considered.
Non-Wires Alternatives
This project involves equipment improvement at the substation and no alternatives were considered.

Analysis: An analysis determined that existing equipment was out-of-date and at a high risk of failure. Additionally, a future proposed project will bring in a new 115 kV connection into this substation, preparing for this connection now will reduce future outage time at this substation.
Schedule: The Burnsville Substation Upgrade project is planned to be in-service by summer 2028.

The table below identifies those projects by Tracking Number in the Twin Cities Zone that were listed as ongoing projects in the 2021 Biennial Report but have been completed or withdrawn since the 2021 Report was filed with the Public Utilities Commission in October 2021. Information about each of the completed projects is summarized briefly in the table below. More information about these projects and inadequacies can be found in earlier reports. Projects that were listed as being complete in the 2021 Report are not repeated here, but more information about those projects can be found in these earlier reports.

The following table provides a list of transmission needs identified in the Southwest Zone by MISO utilities.

Heron Lake 161 kV Substation Rebuild

MPUC Tracking Number: 2013-SW-N1
Utility: ITC Midwest (ITCM)
Project Description: Heron Lake 161 kV Substation Rebuild.

Need Driver: As part of a joint study with GRE and MRES, ITC Midwest has revised and reduced the scope of the Heron Lake 161 kV project. In the updated configuration, one of the capacitor banks is no longer needed and the 161 kV configuration changes from a breaker-and-a-half to a ring bus.

Alternatives:
Transmission Alternatives
The capacitor banks were re-evaluated during the ad hoc study and it was determined that one of them was no longer be needed with the addition of the ‘Worthington Area Projects.’
Non-Wires Alternatives
This project was first proposed in 2013, and system changes, like the Worthington area projects, have removed the initial need for capacitor banks. Substation age and condition issues remain, and a non-wires alternative would not resolve the need to address the age and condition of Heron Lake substation.

Analysis: Transmission studies revealed that voltage in the area is depressed by the relatively long 69 kV lines in the area and the lack of sources in the area. In addition, outages on either the 69 kV or 161 kV systems drove voltage below ITC Midwest’s planning criteria. The Heron Lake 161 kV substation will be constructed as a three position ring but with a single 161/69 kV transformer.

Schedule: Due to outage constraints and the addition of the Worthington Area Projects, the new expected in-service date would be no later than December 2027.

General Impacts: The addition of the ‘Worthington Area Projects’ allowed ITC Midwest to reduce the scope and cost of the existing Heron Lake Capacitor Bank Addition and subsequent substation expansion. The new plan provides better electrical performance at a reduced cost, while adding the additional benefit of geographic diversity which significantly improves customer reliability.

Project Description: The 12.9 miles-long Summit to Dovray 69 kV line will be reconstructed on the existing right of way.

Need Driver: The line’s age and condition and increased maintenance costs have required that this line be rebuilt. The existing line has galloping issues, and the line operates frequently.

Alternatives:
Transmission Alternatives
A rebuild of the line with T2-4/0 ACSR conductor is planned. The rebuild of the line on existing right of way was the sole alternative considered to solve the age and condition issue.
Non-Wires Alternatives
The Summit to Dovray 69 kV line is being replaced due to age and condition. A non-wires alternative is not considered a viable alternative to address the need to replace the Summit to Dovray 69 kV line.

Analysis: The plan to replace the transmission line with new poles, conductor and shield wire will solve the reliability concern caused by the age and condition of the 69 kV line.

Schedule: Construction of the line is expected to be completed by the end of 2027.

General Impacts: The rebuild will occur on existing right of way. No new landowners will be impacted by construction, although some additional temporary workspace may be required. Unique environmental features will be addressed to minimize environmental impacts that could occur during construction. ITCM will work with the appropriate permitting agencies to receive necessary approvals. ITCM contractors and personnel will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. The rebuild will increase the reliability of electric service in the area.

Project Description: The approximately 14.5 mile-long Dovray to Fulda 69 kV line will be reconstructed on the existing right of way.

Need Driver: The line’s age and condition and increased maintenance costs have required that this line be rebuilt. The existing line has galloping issues, and the line operates frequently.

Alternatives:
Transmission Alternatives
A rebuild of the line with T2-4/0 ACSR conductor is planned. The rebuild of the line on existing right of way was the sole alternative considered to solve the age and condition issue.
Non-Wires Alternatives
The Dovray to Fulda Junction 69 kV line is being replaced due to age and condition. A non-wires alternative is not considered a viable alternative to address the need to replace the Dovray to Fulda Junction 69 kV line.

Analysis: The plan to replace the transmission line with new poles, conductor and shield wire will solve the reliability concern caused by the age and condition of the 69 kV line.

Schedule: Construction of the line is expected to be completed by the end of 2028.

Project Description: The approximately 20.1 miles-long Fulda Junction to Heron Lake 69 kV line will be reconstructed on the existing right of way.

Need Driver: The line’s age and condition and increased maintenance costs have required that this line be rebuilt. The existing line has galloping issues, and the line operates frequently.

Alternatives:
Transmission Alternatives
A rebuild of the line with T2-4/0 ACSR conductor is planned. The rebuild of the line on existing right of way was the sole alternative considered to solve the age and condition issue.
Non-Wires Alternatives
The Fulda Junction to Heron Lake 69 kV line is being replaced due to age and condition. A non-wires alternative is not considered a viable alternative to address the need to replace the Fulda Junction to Heron Lake 69 kV line.

Analysis: The plan to replace the line with new poles, conductor and shield wire will solve the reliability concern caused by the age and condition of the 69 kV line. The line work is expected to be completed by the end of 2028.

Schedule: Construction of the line is expected to be completed by the end of 2028.

Project Description: This project bypasses and retires the Fieldon series capacitor and removes the substation, whose only function is for the series capacitor.

Need Driver: System improvements in the area have removed the need for the Fieldon series capacitor which has had operational issues in the past and has a significant recurring maintenance cost.

Alternatives:
Transmission Alternatives
Leaving the series capacitor in service, with corresponding maintenance burden and cost.
Non-Wires Alternatives
Retirement of an existing asset no longer needed.

Analysis: Retiring this substation produces no adverse effects to the transmission system.

Utility: Great River Energy (GRE), ITC Midwest (ITCM), Missouri River Energy Services (MRES) hereinafter referred to as “the Utilities.”

Project Description: Construct the Forks substation interconnection in the Dickinson – Lakefield Junction 161 kV transmission line. Construct the Rost 161/69 kV substation interconnection in the Heron Lake – Round Lake 69 kV transmission line. Construct approximately 6.5 miles of 161 kV transmission line from the Forks substation to the Rost substation. Construct approximately 9 miles of 69 kV transmission line from the Lorain substation to the Rost substation.

Need Driver: Load growth at the Lorain 69 kV substation has exacerbated prior outage events in the area. Any outage on the 161 kV between Split Rock (Xcel) and Magnolia leaves the system susceptible to low voltages for faults anywhere between Lakefield Junction and Elk 161 kV.

Non-Wires Alternatives
Even though the hybrid solution identified in the NWA study addresses the issues based on the technical analysis, economic analysis reveals that this is not an economically feasible option for the Worthington area. Nonetheless, considering future zero carbon emission goals, the hybrid solution fails to fulfill those requirements as well. Compared to the traditional solution cost, the proposed hybrid solution cost is about 10 times higher than the traditional solution. This study verified that no non-wires alternatives or cost-effective environmentally friendly hybrid alternatives are available today to address the Worthington area's reliability issues in an economical manner. A report is available upon request.

Analysis: This new project will allow a strong new source to serve the growing Worthington load, address voltage collapse, and allow the existing 69 kV system to remain in a more system normal configuration during critical prior outages.

General Impacts: The project will require approximately 6.5 miles of new 161 kV transmission line from Forks substation to Rost substation. The project is located in predominantly agricultural lands. Prior to construction, the Utilities will acquire the necessary right-of-way and permits for construction of the project. The Utilities anticipate acquiring a 100-foot easement to facilitate construction and operation of the line. The preliminary design follows existing road rights-of-way to minimize impacts to nearby residents and environmental features. Prior to construction, the Utilities will complete a desktop review of environmental features that may be present in the right of way and will work with the appropriate permitting agencies, as required, to minimize impacts during construction. Construction is expected to be completed in 60 months. During this time, the Utilities and/or their contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. As compared to available alternatives, the project minimizes the length of transmission line through sensitive areas.

Project Description: The 9.2 miles-long Trosky to Pipestone 69 kV line will be reconstructed on the existing right of way.

Need Driver: The line’s age and condition and increased maintenance costs have required that this line be rebuilt. A portion of the line was rebuilt after a 2019 ice storm and this project will rebuild the remaining portions.

Alternatives:
Transmission Alternatives
The rebuild of the line on existing right of way was the sole alternative considered to solve the age and condition issue.
Non-Wires Alternatives
The referenced 69 kV line is being replaced due to age and condition. A non-wires alternative is not considered a viable alternative to address the need to replace the referenced 69 kV line.

Analysis: The plan to replace the transmission line with new poles and shield wire will solve the reliability concern caused by the age and condition of the 69 kV line. The existing 477 ACSR conductor is planned to be transferred.

Schedule: The line is expected to be constructed and in service by December 2023.

General Impacts: The rebuild will occur on existing right of way. No new landowners will be impacted by construction, although some additional temporary workspace may be required. Unique environmental features will be addressed to minimize environmental impacts that could occur during construction. L&O will work with the appropriate permitting agencies to receive necessary approvals. L&O contractors and personnel will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. The rebuild will increase the reliability of electric service in the area.

Project Description: To provide for interconnection of two 80 MW (160 MW total) solar-powered generating facility, MISO projects J1164 and J1325, the 161 kV bus at Magnolia will be reconfigured to form a ring bus at the location of the existing Magnolia substation.

Need Driver: MISO projects J1164 and J1325 was studied under the MISO business practices, and the expansion of the Magnolia 161 kV bus to connect projects J1164 and J1325 is required to provide interconnection service to the project under the MISO tariff.

Alternatives:
Transmission Alternatives
The interconnections were evaluated under the MISO’s DPP 2018 and 2019 system impact studies. No alternatives for the interconnections were identified.
Non-Wires Alternatives
Projects J1164 and J1325 will be interconnected under MISO Tariff requirements. A non-wires is not viable as this project is aiding in the interconnection of two 80 MW (160 MW total) solar-powered generating facilities.

Analysis: The interconnection of projects J1164 and J1325 were evaluated as part of the MISO DPP 2018 and 2019 system impact studies. The expansion of facilities at Magnolia are required to provide a point of interconnection for project J1164 and J1325.

The Magnolia substation is over 60 years old and the substation was not originally designed or constructed to accommodate additional bus positions on the 161 kV bus. The existing 161 kV substation bus will be rebuilt from a straight bus configuration to a ring bus configuration.

General Impacts: The upgrades will occur within the existing Magnolia 161 kV Substation. Termination of the J1164 and J1325 generator tie-line will be coordinated with the interconnection customer and necessary authorities. No new landowners will be impacted by construction, although some additional temporary workspace may be required. Unique environmental features will be addressed to minimize environmental impacts that could occur during construction. ITCM will work with the appropriate permitting agencies to receive necessary approvals. ITCM contractors and personnel will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Install approximately 60 mile second 345 kV circuit between the Brookings County and Lyon County substations. Install approximately 39 mile second 345 kV circuit between the Hampton Corner and Helena substations. Perform substation upgrades associated with installation of line.

Need Driver: Adds second circuit that eliminates current system conditions that impede deliverability of existing resources to demand centers in primarily off-peak periods of high renewable production which results in a reduction of available generation capacity at times of higher than average maintenance and construction outages.

Alternatives:
Transmission Alternatives
None.
Non-Wires Alternatives
This new line installation uses existing double circuit structures on existing right of way. No alternatives were considered.

Analysis: This is a cost-effective system resiliency solution that reduces system congestion.

General Impacts: The project will be constructed on the existing 345kV double circuit structures, using existing right of way. The second circuit will reduce congestion on the transmission system allowing for economical dispatch of renewable energy resources. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. Existing right of way will be restored upon completion of project.

Need Driver: The ELR transformer program is to proactively replace aging transformers that have passed their operational service life and are showing increase signs of degradation.

Project Description: This project will replace the aging OPGW on the Brookings - Lyon County and Hampton - Helena 345 kV lines. This project will be performed in tandem with the installation of the Brookings - Lyon County and Hampton - Helena 2nd circuit installation project.

Need Driver: The existing OPGW on the Brookings - Lyon County and Hampton - Helena 345 kV lines are showing signs of degradation and have experienced failures. Replacement is needed to ensure reliable communications and controls on those circuits.

Alternatives:
Transmission Alternatives
None.
Non-Wires Alternatives
This project replaces existing end of life communications equipment. No alternatives were considered.

General Impacts: The project will be replacing existing equipment at end of life. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. Existing right of way will be restored upon completion of project.

Project Description: This project will Move J460 Steep Bank Lake interconnection to new 345 kV second circuit being built between Brookings County - Lyon County (MTEP ID 23452).

Need Driver: Transferring Steep Bank Lake to the new Brookings County - Lyon County 345 kV line will avoid crossing lines going into the substation and provide additional operational flexibility.

General Impacts: The project will be swapping existing substation to new line on existing right of way eliminating line crossings which could impact reliability. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated. Existing right of way will be restored upon completion of project.

Project Description: New 4-line terminal breaker station connecting to Minnesota Valley – Troy 69 kV transmission line (0724), Crook’s substation, and the SMBSC plant.

Need Driver: Improve reliability of service to Southern Minnesota Beet Sugar Corporation (SMBSC), a business adversely impacted by power disruptions.

Alternatives:
Transmission Alternatives
New 230/69 kV substation north of the plant site to supply the two distribution substations supporting SMBS. No indicated load increase; the 69 kV line is capable of providing a well enough source of service to the existing customers. Not enough justification for an additional source in the area
Non-Wires Alternatives
None.

Analysis: Adding a breaker station to the existing 69 kV system will reduce outages and improve reliability for SMBSC. No other immediate overloads or voltage concerns.

Project Description: Rebuild 1.5 miles of line 0719 69 kV from Winthrop - Structure 45.

Need Driver: Asset at end of life and at risk of imminent failures. Increased outage frequency and duration. Failure could provide risk to public safety.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Minnesota Valley TR11 ELR

Need Driver: Asset at end of life and at risk of imminent failures. Increased outage frequency and duration. Failure could provide risk to public safety.

Alternatives:
Transmission Alternatives
Transformer may be used as is, but this runs the risk of reliability and overloading issues. No alternatives were considered.
Non-Wires Alternatives
This is replacing an existing asset.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

Fairmont, MN Area Transmission Expansion

MPUC Tracking Number: 2023-SW-N10

Utility: Southern Minnesota Municipal Power Agency

Project Description: Building of a new 69/12.5 kV distribution substation “West Industrial Park” (WIP) west of Fairmont, construction of a new 69 kV SMMPA breaker station and construction of two 69 kV transmission lines, one from WIP to the SMMPA’s Fairmont Energy Station (FES) substation and one from WIP which will tap Great River Energy’s 69 kV line between Rutland substation and the Fairmont 10th Street Substation.

Need Driver: This project was motivated by Fairmont Public Utilities (FPU) to address their need for a new distribution substation.

Alternatives:
Transmission Alternatives
A radial 69 kV transmission line was considered, but ultimately there was too much line exposure to Fairmont load.
Non-Wires Alternatives
Because Fairmont needs to be able to serve load from a new location non-wires alternatives were not considered.

Analysis: These additions will add a reliable 69 kV transmission loop through town. This increases the load serving capability in town as well as minimizes the possibility of transmission outages to area load.

General Impacts: The new FPU substation is likely to be built on existing city owned land. The new SMMPA substation will be built on existing SMMPA owned land. Most of the line routing will be done on existing distribution right of way. Where needed right of way will be expanded or added to, environmental impacts will be minimized on the project. Relevant permits and approvals will be received prior to construction. Contractors and personnel will contribute positively to the local economy.

MPUC Tracking Number: 2023-SW-N11

Utility: Southern Minnesota Municipal Power Agency

Project Description: Current breakers were installed in 1985, and they have become unreliable and difficult to maintain with their age. Along with these breakers, the associated switches and relays will also be replaced with newer and more reliable equipment. The new equipment includes new PTs, arresters, and new solid-state relay panels.

Need Driver: Old breakers have become difficult to maintain with reoccurring problems and parts shortages, effectively driving maintenance costs up. Other equipment upgrades are being made to switch from electromechanical to the more reliable solid-state equipment.

Schedule: New equipment expected to be in service in 2025.

General Impacts: The 10th St. substation is on existing city owned land. Relevant permits and approvals will be received prior to construction. Contractors and personnel will contribute positively to the local economy.

Project Description: Expansion of the 345 kV Gen tie bus at the Lakefield substation to accommodate the Three Waters Wind (340 MW) Wind Farm. Installation of new 345 kV breakers on the existing generator and installation of the GRE controlled EEE, 1500’ of 345 kV Transmission to the interconnect 161 kV/345 kV step up substation.

Need Driver: Additional 345 kV interconnection required to connect the Three Waters wind farm.

Alternatives:
Transmission Alternatives
This project is necessary to facilitate the connection of a new wind farm. This is an existing generation site and was deemed the best interconnection point, therefore alternatives were not considered.
Non-Wires Alternatives
Non-wires alternatives are not considered for new generation interconnections as the POI is determined by the interconnection customer.

Analysis: The interconnection of the Three Waters Wind Farm at Lakefield was evaluated as part of the MISO DPP system impact studies.

Schedule: The Lakefield Area Projects are planned to be in-service by November 2026.

The table below identifies those projects by Tracking Number in the Southwest Zone that were listed as ongoing projects in the 2021 Biennial Report but have been completed or withdrawn since the 2021 Report was filed with the Minnesota Public Utilities Commission in October 2021. Information about each of the completed projects is summarized briefly in the table below. More information about these projects and inadequacies can be found in earlier reports. Projects that were listed as being complete in the 2021 Report are not repeated here, but more information about those projects can be found in these earlier reports.

The following table provides a list of transmission needs identified in the Southeast Zone by MISO utilities. There were no projects identified in this zone by non-MISO utilities.

Project Description: The approximately 35 miles-long Adams to Stewartville 69 kV line will be reconstructed on the existing right of way.

Need Driver: The Adams to Stewartville 69 kV line was built over 50 years ago, and increased maintenance costs will require the line to be reconstructed due to its age and condition.

Alternatives:
Transmission Alternatives
A rebuild on existing ROW was the sole alternative considered to solve the age and condition issue.
Non-Wires Alternatives
Non-wire alternatives are not viable because they cannot address concerns related to age and condition on the Adams to Stewartville 69 kV circuit.

Analysis: The plan to replace the over 50-years-old transmission line with new poles, conductor and shield wire will solve the reliability concern caused be the age and condition of the 69 kV line.

General Impacts: The line is near the end of its useful life. No new landowners will be impacted by construction, although some additional temporary workspace may be required. Unique environmental features will be addressed to minimize environmental impacts that could occur during construction. ITCM will work with the appropriate permitting agencies to receive necessary approvals. ITCM contractors and personnel will contribute positively to the local economy. No significant traffic impacts are anticipated. The right-of-way will be restored following construction. The rebuild of the line will increase the reliability of electric service in the area.

Project Description: To provide for interconnection of the 50 MW solar-powered generating facility, MISO project J523, the 161 kV bus at Adams will be reconfigured to form a breaker-and-1/2 terminal at the location of the existing Adams 161 kV bus-tie breaker. Also, as part of the work for the J523 generation, the 161 kV terminal to the 345/161 kV transformer will be re-terminated at a new terminal in the newly created breaker-and-1/2 row that will serve as the point of interconnection for project J523.

Need Driver: MISO project J523 was studied under the MISO business practices, and the expansion of the Adams 161 kV bus to connect project J523 is required to provide interconnection service to the project under the MISO tariff.

Alternatives:
Transmission Alternatives
The interconnection was evaluated under the MISO’s DPP February 2016 system impact study. No alternatives for the interconnection were identified.
Non-Wires Alternatives
Project J523 will be interconnected under MISO Tariff requirements. A non-wires is not viable as this project is aiding in the interconnection of a 50 MW solar-powered generating facility.

Analysis: The interconnection of project J523 was evaluated as part of the MISO February 2016 system impact study. The expansion of facilities at Adams are required to provide a point of interconnection for project J523.

The Adams substation is approximately 55 years old, and the substation was originally designed to accommodate conversion to a breaker-and-1/2 bus configuration. In conjunction with the interconnection of project J523, a separate maintenance project will be developed to convert the remaining 161 kV substation bus from a straight bus configuration to a breaker-and-1/2 configuration.

General Impacts: The upgrades will occur within the existing Adams 161 kV Substation. Termination of the J523 generator tie-line will be coordinated with the interconnection customer and necessary authorities. No new landowners will be impacted by construction, although some additional temporary workspace may be required. Unique environmental features will be addressed to minimize environmental impacts that could occur during construction. ITCM will work with the appropriate permitting agencies to receive necessary approvals. ITCM contractors and personnel will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: The project calls for the Huntley to Freeborn 161 kV line to be tapped approximately 6.1 miles west of Freeborn. A new 161/69 kV substation would be constructed to accommodate a 100 MVA, 161/69 kV transformer with load-tap changer.

Need Driver: The 69 kV system around Albert Lea, MN experiences low voltage and thermal loading issues under multiple NERC P2 contingencies. This area is primarily fed from the Huntley and Hayward substations and the line between them is approximately 50 miles long. This 69 kV system is operated radially, and the existing 161 kV sources are stretched on high impedance conductor over great distances.

Alternatives:
Transmission Alternatives
Rebuilding Huntley 69 kV to a ring-bus configuration and re-terminating Corn Plus substation’s load to a consolidated substation near Winnebago Local in conjunction with rebuilding the Hayward 161 kV Substation to a breaker-and-½ configuration were also considered.
Non-Wires Alternatives
Non-wire alternatives are not viable because they cannot meet the duration requirements to alleviate the voltage concerns.

Analysis: The new substation at Thisius will help support future load growth on the 69 kV system and provide a much needed source between the Huntley and Hayward substations. The location of the Thisius 69 kV station can also accommodate future 161 kV expansion necessary to address future area needs.

Schedule: It is expected that the project would be placed in service by early June 2023.
General Impacts: Line routing and facilities siting will be coordinated with necessary local, state and federal authorities. ITC contractors and personnel will work with landowners to address their concerns during construction. Impacts to landowners will be minimized. Temporary workspace may be required. Unique environmental features will be addressed to minimize environmental impacts that could occur during construction. ITC will work with the appropriate permitting agencies. No significant traffic impacts are anticipated. ITC contractors and personnel will contribute positively to the local economy. The new facilities will increase the reliability of the electric system in the area.

Project Description: This project involves the rebuilding of an approximately 1.6-mile portion of the 69 kV between Farmington substation (FRM) and Northfield substation (NOF). The intent of the rebuild is to increase reliability and performance of the line, reduce the likelihood of a forced outage occurring and increase the capacity for project future load growth.

Need Driver: Asset at end of life and at risk of imminent failures. Increased outage frequency and duration. Failure could provide risk to public safety.

Analysis: Verifying the secondary limit on the Farmington – Lake Marion 69 kV line, and limit may need to be replaced. No other immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Project Description: Due to age and condition, ITC Midwest is replacing both 161/69 kV transformers at the Hayward substation near Hayward, MN, with a single larger unit.

Need Driver: Both transformers are nearing end of their life and are needing to be replaced.

Alternatives:
Transmission Alternatives
Replacing both existing units with a pair of larger/standard transformers. However, with the addition of ‘2019-SE-N5 Thisius 161/69 kV Substation’ there was no longer a need to have two transformers in this substation.
Non-Wires Alternatives
Non wires alternative was not considered. Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Hayward Substation.

Analysis: No other immediate overloads or voltage concerns were observed with the replacement of the two existing Hayward 161/69 kV transformers with a single unit.

General Impacts: The project is being completed within the existing Hayward substation property lines and minimal impacts to neighboring landowners is expected.

Project Description: This project involves the rebuilding of an approximately 19.7 miles of existing 69 kV on line 0761 from Zumbrota to the current 69 kV Standards.

Need Driver: Asset at end of life and at risk of imminent failures. Increased outage frequency and duration. Failure could provide risk to public safety.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Project Description: Rebuild 6.7 miles of 69 kV line 0749 from Waseca - ITC Tap and add OPGW.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Project Description: Rebuild 22 miles of line 0714 69 kV from Medelia - Watonwan.

Analysis: Age and condition rebuild. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Project Description: Rebuild 16 miles of line 0708 69 kV from Eagle Lake - Waterville and add OPGW.

Alternatives:
Transmission Alternatives
Line may be used as is, but this runs the risk of reliability issues. No alternatives were considered.
Non-Wires Alternatives
This is replacing an existing asset.

Analysis: Rebuilding to address galloping concerns. No immediate overloads or voltage concerns.

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Project Description: Build new Gaiter Lake substation in Waseca to pick up load off of Clarks Grove, Meridan, and Waseca substations. Retire Clarks Grove and Meridan substations.

Need Driver: Needed due to age and condition of Clarks Grove and Merdian substations, as well as capacity needs.

Alternatives:
Transmission Alternatives
Rebuild of existing substations would not increase load serving capability, leaving load at risk and would involve full rebuild of two substations opposed to construction of one new substation.
Non-Wires Alternatives
None.

Analysis: Transferring load from existing substations to new substation in same area. No immediate overloads or voltage concerns.

General Impacts: The project will install a new substation along existing 69 kV line and retirement of two existing substations. During construction the company or contractors will be working in the area and will contribute positively to the local economy. No significant traffic impacts are anticipated.

Project Description: Rebuild 2.2 miles of DPC’s Maple Leaf to Airport 69 kV line between the Rock Dell and Pleasant Valley distribution substations on existing and new right-of-way.

Need Driver: DPC purchased this line from People’s Energy Cooperative in July of 2022. This line was identified for rebuild due to age and condition.

Alternatives:
Transmission Alternatives
A rebuild solely on existing right-of-way was considered. However, a portion of the existing right-of way runs through a lower lying area that is also in the Rock Dell Wildlife Management Area. For this reason, a mix of existing and new right-of way is also being considered.
Non-Wires Alternatives
None.

Analysis: The 2.2-mile section 69 kV transmission line rebuild will address the reliability concerns due to age and condition. The potentially relocated section of this rebuild will also improve accessibility for maintenance.

Schedule: Construction of the line is expected to be completed by early-2026.

General Impacts: The line is near the end of its useful life. Dairyland construction crews will rebuild this line in early-2026, requiring approximately three weeks to construct. The portion of the rebuild on existing right-of-way will have minimal impacts, while the portion being considered for new right-of-way will improve accessibility.

Project Description: Rebuild 8.9 miles of DPC’s Maple Leaf to Rochester 69 kV line between the Genoa and Ringe distribution substations on existing and new right-of-way.

Need Driver: DPC purchased this line from People’s Energy Cooperative in July of 2022. This line was identified for rebuild due to age and condition.

Alternatives:
Transmission Alternatives
A rebuild solely on existing right-of-way was considered. Relocating portions of the line has added reliability benefits.
Non-Wires Alternatives
None.

Analysis: The 8.9-mile section 69 kV transmission line rebuild will address the reliability concerns due to age and condition. The relocated section of this rebuild will also improve line exposure and reliability.

Schedule: Construction of the line is expected to be completed by late 2026.

General Impacts: The line is near the end of its useful life. Dairyland construction crews will rebuild this line in 2026, requiring approximately eleven weeks to construct.

J898 Interconnection at Beaver Creek 161 kV
MPUC Tracking Number: 2023-SE-N8

Project Description: Replace the 161 kV Beaver Creek Tap three-way switches with a 3-breaker substation approximately 6 miles south of the Beaver Creek Tap to allow for the interconnection of 100 MW of wind-powered generation with the potential for additional capacity in the future. A 6-mile portion of 161 kV transmission line on new right-of-way will be constructed to connect the new transmission substation back to the existing Harmony to Beaver Creek 161 kV transmission line. A 4-mile stretch of existing 161 kV transmission line between Harmony and the Beaver Creek Tap will be retired.

Need Driver: The new 3-breaker substation and 6-mile portion of 161 kV transmission line are required as part of the MISO Tariff for the interconnection of 100 MW of wind-powered generation for project J898.

Alternatives:
Transmission Alternatives
The interconnection for J898 was evaluated under MISO’s DPP August 2017 West system impact study. An alternative of upgrading the 69 kV transmission to the south of SMMPA’s Rice substation was considered.
Non-Wires Alternatives
None.

Analysis: The interconnection of project J898 was evaluated under MISO’s DPP August 2017 West and 2020 West system impact study. Potential overloads of the underlying 69 kV system under contingent conditions were identified. The proposed project was determined to be the most reliable and cheapest mitigation for these overloads.

Schedule: The in-service date for the substation portion of the project is late-2026, while the new 161 kV transmission line portion of the project is mid-2027.

General Impacts: The 161 kV transmission line portion of this project will be built on new right-of-way, with approximately 4 miles of existing transmission line to be retired. The resulting configuration will replace the existing 3-terminal 161 kV transmission line between Harmony, Adams and Rice with three 2-terminal transmission lines, providing additional reliability benefits.

Project Description: Construct a new 5-breaker 161/69 kV transmission substation, named Kellogg on DPC’s Wabaco to Alma 161 kV transmission line. Construct 9 miles of 161 kV transmission line on new right-of-way, connecting between Wabaco and Kellogg from existing transmission into the Kellogg substation. Install a 112 MVA 161/69 kV transformer at Kellogg and reterminate DPC’s Utica to Alma 69 kV transmission line into the Kellogg substation. Retire the remaining 2.5-mile Mississippi River crossing portion of the 69 kV transmission line between Alma and the Weaver distribution substation.

Need Driver: These projects are required by MISO’s Long Range Transmission Plan (LRTP) and are included in the identified Tranche 1 projects to address needs associated with the changing resource mix across the MISO Midwest subregion. The new DPC facilities are required to replace the 69 kV Mississippi River crossing between Alma and the Weaver distribution substation with the North Rochester to Tremval 345 kV transmission line.

Alternatives:
Transmission Alternatives
The MISO LRTP planning efforts considered several alternatives to the recommended Tranche 1 projects.
Non-Wires Alternatives
None.

Analysis: The Kellogg substation, new 161 kV transmission line and 69 kV retermination frees up the Mississippi River crossing for the new North Rochester to Tremval 345 kV transmission line, without sacrificing local reliability.

General Impacts: The new Kellogg substation and 69 kV retermination will have minimal need for new right-of-way, but will allow for new 345 kV Mississippi River crossing on existing right-of-way. The 9 miles of new 161 kV transmission will be constructed on new right-of-way. The LRTP Tranche 1 projects are renewable-enabling, allowing for reliable, green energy in the future.

MPUC Tracking Number: 2023-SE-N10

Utility: Southern Minnesota Municipal Power Agency

Need Driver: Old breakers have become difficult to maintain with reoccurring problems and parts shortages, effectively driving maintenance costs up. Other equipment upgrades are being made to switch from electromechanical to the more reliable solid-state equipment.

General Impacts: This project is located on SMMPA owned property. No significant traffic impacts are anticipated. Relevant permits and approvals will be received prior to construction. Contractors and personnel will contribute positively to the local economy.

Project Description: Expansion of the 161 kV bus at the Pleasant Valley substation to accommodate the Phase 1 Wind (170 MW) and Phase 2 Wind (150 MW) Wind Farms. Expansion of the control house to accommodate the additional equipment.

Need Driver: Additional 161 kV transmission bays required to connect the Dodge County and Timberwolf Wind wind farms.

Alternatives:
Transmission Alternatives
Alternate design to install dead end and breakers in the existing opening between existing breakers 19QB6 and 19QB7. This would eliminate the need to expand the current yard. This would require extensive bus outages and limitations on generation at Pleasant Valley to allow for safe installation and maintenance of equipment. This alternative was decided against by the field service team and engineering due to the outage constraints for both maintenance and construction.
Non-Wires Alternatives
Non-wires alternatives are not considered for new generation interconnections as the POI is determined by the interconnection customer.

Analysis: The interconnection of the Dodge County and Timberwolf Wind wind farms was evaluated as part of the MISO DPP system impact studies.

Schedule: The Pleasant Valley Area Projects are planned to be in-service by spring 2024.

Need Driver: The line to Byron has caused market congestion in the past and is projected to continue to cause market congestion into the future.

Alternatives:
Transmission Alternatives
No transmission alternatives were considered since this project is replacing the most limiting equipment in an existing substation.
Non-Wires AlternativesNo non-wires alternatives were considered since this project is replacing the most limiting equipment in an existing substation.

Analysis: This upgrade will prevent terminal equipment from being the binding rating and allow for the line conductor capacity rating to be fully utilized, reducing the likelihood of the line causing congestion in the market.

The table below identifies those projects by Tracking Number in the Southeast Zone that were listed as ongoing projects in the 2021 Biennial Report but have been completed or withdrawn since the 2021 Report was filed with the Minnesota Public Utilities Commission in October 2021. Information about each of the completed projects is summarized briefly in the table below. More information about these projects and inadequacies can be found in earlier reports. Projects that were listed as being complete in the 2021 Report are not repeated here, but more information about those projects can be found in these earlier reports.

6.0 Needs

6.1 Introduction

6.1.1 Needed Projects

6.1.2 Description of Each Project by Tracking Number

6.1.3 Completed Projects

6.2 The MISO Planning Process

6.2.1 The MISO Transmission Expansion Plan Report

6.3 Northwest Zone

6.3.1 Needed Projects

6.3.2 Completed Projects

6.4 Northeast Zone

6.4.1 Needed Projects

6.4.2 Completed Projects

6.5 West Central Zone

6.5.1 Needed Projects

6.5.2 Completed Projects

6.6 Twin Cities Zone

6.6.1 Needed Projects

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Line 0736 Arden Hills - Lawrence Creek Rebuild

General Impacts: No environmental issues have been identified. Line rebuild will have minimal impacts to existing system performance and footprint.

Line 0721 STR 71 to 476 Rebuild

6.6.2 Completed Projects

6.7 Southwest Zone

6.7.1 Needed Projects

Heron Lake 161 kV Substation Rebuild

Minnesota Valley TR11 ELR

Fairmont, MN Area Transmission Expansion

6.7.2 Completed Projects

6.8 Southeast Zone

6.8.1 Needed Projects

6.8.2 Completed Projects