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Studies and Reports > 2021 Biennial Report > Transmission Projects Report 2019


Transmission Projects Report 2019
Chapter 6: Needs
   

6.0 Needs

6.1 Introduction

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

6.1.1 Needed Projects

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

MPUC Tracking Number

MISO Project Name

MTEP Year/App

MTEP Project Number

CON?

Non-Wire Alt.

Utility

The following describes what information is found in each of the columns.

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 that 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 2007, on the other hand, was first identified in the 2007 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/App
The third column contains a reference to a MTEP Report and an Appendix in the report. The MTEP Report is prepared annually by the 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 MTEP21, 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 the 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 because even though Minnkota is not a MISO member. MISO performs some of Minnkota’s transmission planning work.   

Certificate Of Need
The MPUC rules (Minn. Rules part 7848.1300, item M) state that 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. 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 that could 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.  

Utility
This column simply identifies the utility or utilities that are involved in the project.

6.1.2 Description of Each Project by Tracking Number

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 planning was being conducted by and through MISO.

In 2014, as part of its approval of the 2013 Biennial Report, the Commission determined that 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.”  Minn. Stat. §216B.2425, subd. 2(c)(3). 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 that are 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 as well, 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.

6.1.3 Completed Projects

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

MPUC Tracking Number

Description

MTEP Year/App

MTEP Project Number

Utility

Date Completed

Most of the columns contain the same information that is 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 was required from the Commission, or both, 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 that was 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.

6.2   The MISO Planning Process

6.2.1 The MISO Transmission Expansion Plan Report

Because nearly all of 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 that is prepared each year. Much of the information provided in this subsection was also available in the 2013, 2015, 2017 and 2019 Biennial Reports. 

The latest MTEP Reports are available on the MISO webpage at:

http://www.misoenergy.org (Click on “Planning” on the top of the page)

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 usually approves the report in December. The process continues with another report finalized the following December. The MTEP21 Report should be approved by the MISO Board of Directors in December of this year.

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

Appendix A – Projects recommended for approval,
Appendix B – Projects with documented need and effectiveness, and

Generally, when 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 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.

  • The MTEP Report is prepared annually so it provides more timely information. The Biennial Report is prepared every other year.
  • The MISO planning process is comprehensive. MISO considers all regional transmission issues, not just Minnesota transmission issues. 
  • MISO conducts an independent analysis of all projects to confirm the benefits stated by the project sponsor. This adds further verification of the benefits of projects.
  • MISO holds various planning meetings during the year at which stakeholders can have input into the planning process so there are more frequent opportunities for input (see next paragraph.)
  • All completed projects are listed on the MISO webpage.
  • Not duplicating the MTEP Report will save ratepayers money. It is costly to require the utilities to redo all the information that is found in the MTEP Report.

    6.2.2  Finding a Project in a MTEP Report

For each zone, a table is included that describes 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

MISO Project Name

MTEP Year/App

MTEP Project Number

CON?

Non-Wire Alt.

Utility

2019-NE-N17

Running Cap Bank Retirement

2019/A

16145

No

No

XEL

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

Step 1. Go to the MISO homepage at: https://www.misoenergy.org

Step 2. Click on “Planning” at the top of the page. Click the arrow by “MTEP” tab.  Then click on the “Previous MTEP Reports” link on the left side of the page.

Step 3. Click on the link for the MTEP19 Report. 

Step 4. Click on the “MTEP19 Appendix A or B.”

Step 5. Select the “Projects” tab at the bottom of the spreadsheet that was just downloaded. Hold down the “Ctrl” key and press the “F” key to bring up the “Find” dialog box. Enter the MTEP Project Number, which in this case is 16145, in the dialog box and select “Find Next.” Information about the project can then be read from the row the MTEP Project was found during this search.

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, probably earlier than 2011, 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, which is “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 that 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 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 Cap 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 2. Select MTEP19 Appendix B West.

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 that 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, from the Appendices ABC page, click on the down arrow located in the column C 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).

 Utility

MISO Geographic Code

American Transmission Company, LLC

ATC LLC

Dairyland Power Cooperative

DPC

Great River Energy

GRE

ITC Midwest LLC

ITCM

Minnesota Power

MP

Missouri River Energy Services

MRES

Otter Tail Power Company

OTP

Southern Minnesota Municipal Power Agency

SMP

Xcel Energy

XEL

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.

 

6.3   Northwest Zone

6.3.1 Needed Projects

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.

MPUC Tracking Number

MISO Project Name

MTEP Year/App

MTEP Project Number

CON?

Non-Wire Alt.

Utility

2007-NW-N3

NW MN Reliability Upgrades

2014/B

4232

No

No

OTP/MPC

2015-NW-N7

Richwood-Oakland 69 kV  (Load Transfers)

Non-MISO

 

No

No

MPC

2019-NW-N1

Hoot Lake 115 kV Capacitor Bank Addition

2019/A

15725

No

No

OTP

2019-NW-N2

Norcross Area Upgrades

2019/A

17225

No

No

OTP

2019-NW-N3

Erie-Frazee

2019/A

15344

No

Yes

GRE/OTP

2019-NW-N5

Erie/Audubon Alternate Service

Non-MISO

17144

No

No

MPC

2021-NW-N1

Hoot Lake 115/41.6 kV Transformer Replacement

2020/A

19685

No

No

OTP

2021-NW-N2

Henning 230 kV Breaker Addition

Future

TBD

No

No

GRE

2021-NW-N3

Inman 230 kV Breaker Addition

Future

TBD

No

No

GRE

2021-NW-N4

Cormorant to Pelican Rapids Install Storm Structures

2022/A

21825

No

No

GRE


NW MN Reliability Upgrades

MPUC Tracking Number:  2007-NW-N3

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 230/115 kV tap of Drayton-Prairie 230 kV (Lake Ardoch) and associated Oslo 115 kV substation in 2024, and depending on future load growth, a potential second Winger-Plummer 115 kV line and associated substation expansions sometime after 2028. 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.

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.

Alternatives:  

Transmission Alternatives

Several different transmission alternatives were developed as part of OTP’s High Voltage Study to assess the ability of the transmission system to serve the Northwest Minnesota load. These included:

      • A new Thief River Falls 230 kV substation, an expanded Winger 230 kV substation, and a new Winger-Thief River Falls 230 kV line
      • a new Lake Ardoch Substation (230 kV), a new substation at Thief River Falls (230 kV), and a new Lake Ardoch-Thief River Falls 230 kV line,
      • a new Drayton-Kennedy-Donaldson 115 kV line,
      • a new Lake Ardoch Substation (230 kV and 115 kV), a new substation at Oslo (115 kV), and a new Lake Ardoch-Oslo 115 kV line, or
      • a new Drayton-Kennedy-Donaldson 115 kV line, a new Winger-Plummer Pipe 115 kV line, and a second Winger 230/115 kV transformer.

The options above have been considered and compared with the aforementioned suite of 115 kV projects and it was determined that the benefits of such a project are more robust and cost effective than the other options that were considered. 

Non-Wires Alternatives

One part of the NW MN Reliability Upgrades project is the addition of Automatic Undervoltage Load Shedding (UVLS) at several locations, which is a non-wires alternative. This UVLS mitigates some of the most severe but unlikely contingencies in the NW MN area and is not expected to operate frequently.

Additional non-wires alternatives beyond UVLS would not have sufficient availability or would be prohibitively expensive.

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 study efforts mentioned above determined that an upgrade to mitigate post-contingent service issues to the Northwest Minnesota area transmission is required by the winter of 2023. This date is a revised date from the initial draft of the “High Voltage Study” report, and the revised date came from the “Winger-Thief River Falls Timing Analysis.” A refreshed study effort was completed in early 2019 to determine a more definitive mitigation plan and schedule.  With the new planned set of projects, 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. The associated UVLS has been implemented.

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.

Richwood-Oakland 69 kV Line
(Load Transfers)

MPUC Tracking Number: 2015-NW-N7

Utility:  Minnkota Power Cooperative (MPC)

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. 

Alternatives:  

Transmission Alternatives

There are several transmission alternatives being considered as part of these load transfers. In a previous Biennial Report, the preferred alternative was a 115 kV line and a substation conversion was the preferred project. However, that project was dismissed in favor of a looped 69 kV line.

The alternatives involve further investigation of a Mahnomen/Ulrich 115 kV load tap (the project that was originally proposed). Alternatives may also include parts of described project (solely Richwood-White Earth or White Earth-Oakland. Investigations are ongoing, and these alternatives will be compared with the proposed transmission line options.

Non-Wires Alternatives

Non-transmission solutions such as battery backup are being investigated. The transmission plan may be changed if these investigations provide equally cost effective projects that are robust.

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.

Hoot Lake 115 kV Capacitor Bank Addition

MPUC Tracking Number: 2019-NW-N1

Utility: Otter Tail Power Company (OTP)

Project Description: A new 115 kV capacitor bank is proposed at the Fergus Falls Hoot Lake substation. A total of 50 MVAR in two 25 MVAR stages is proposed along with the necessary substation modifications.

Need Driver: The planned retirement of the Hoot Lake coal plant in 2021 leaves the transmission system in the Fergus Falls area with a lack of reactive support. This capacitor bank is being proposed to mitigate a variety of low voltage concerns on the area 41.6 kV system following the retirement of the plant.

Alternatives:

Transmission Alternatives

These capacitor banks are a relatively low-cost improvement. Transmission alternatives include a new 345 kV tie at Fergus Falls or reconductoring select 115 kV and 41.6 kV transmission lines in the area to improve voltage performance.

Non-Wires Alternatives

Non-wires alternatives such as energy storage systems would be more expensive and have inferior availability compared to these capacitor banks.

Analysis: These capacitors were recommended in the Otter Tail Power Company Ten Year Development Study. The study found a need for reactive support for the area 41.6 kV system for several different outages following the retirement of Hoot Lake. In addition to several distribution capacitor installations, the 115 kV Hoot Lake capacitor mitigates any low voltage concerns associated with the plant’s retirement.

Schedule:  The Hoot Lake capacitors are expected to go into service by late October 2021 such that they will be available before the winter peak season following the plant’s retirement.

General Impacts: This project enables the retirement of aging fossil fuel generation. It is located entirely at the existing Hoot Lake substation. There is no new transmission included in this project. No notable sites or locations are near the site of this project. This project is still in its early stages of planning, but all of this information is relatively inconsequential to the nearby environment.

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, minimal impact is expected as a result of the substation modifications.

Norcross Area Upgrades

MPUC Tracking Number: 2019-NW-N2

Utility: Otter Tail Power Company (OTP)

Project Description: This project consists of a new 115/41.6 kV substation near Norcross, MN, as well as a new 7-mile 115 kV line from the existing Grant County substation to the new Norcross substation.

Need Driver: The existing 41.6 kV system in the Norcross area is not able to reliably support load growth. This project provides an additional 115 kV source to this 41.6 kV system to accommodate new planned loads.

Alternatives:

Transmission Alternatives

A tie into the WAPA Moorhead – Morris 230 kV line was considered, but this was a higher cost option for little to no reliability benefit over the final project.

Non-Wires Alternatives

41.6 kV STATCOMs were considered as an alternative, but this proved to be infeasible due to a low short-circuit ratio on the area 41.6 kV system.

Analysis: The Wendell Interconnection and Nashua Elevator Load Serving Study examined various projects that could mitigate the reliability concerns in the Norcross area. The recommended project as described above was found to be the most reliable and lowest-cost alternative. The STATCOM solution proved to be infeasible due to a low short-circuit ratio on the area 41.6 kV system. The WAPA 230 kV tie compared unfavorably to the preferred project due to some unmitigated N-1 concerns as well as additional ongoing SPP transmission service costs.

Schedule:  In order to meet the schedule of new loads planned in the area, this project is planned for completion by early 2022.

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.  There will 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 110 acres, only approximately 10 acres will actually be impacted. 

The economic and social impacts will likely be minimal 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 importance of an improved system.


Erie – Frazee

MPUC Tracking Number:  2019-NW-N3

MPUC Docket Number:  ET-2/TL-20-423

Utility:  Great River Energy (GRE) and Otter Tail Power Company (OTP)

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.

Need Driver:  Driven by load growth and proposed retirement of Hoot Lake generation.

Alternatives: 

Transmission Alternatives

The following alternatives were considered in the study. These alternatives were not preferred for the reasons related to not providing significant reliability improvement, high cost, or low incremental load serving capability when compared with the project (preferred plan).

    1. Audubon 230/115 kV upgrade
    2. Audubon 230/115 kV upgrade with 115 kV line to future Lake Eunice Tap
    3. 230/115 kV substation along Audubon – Hubbard 230 kV line with 115 kV line to a breaker point on existing 115 kV system

      a. Todd Lake 230/115 kV sub with 115 kV line to Frazee

    4. b. Mountain Road 230/115 kV sub with 115 kV line to DLPU

    5. Fergus Falls to Edgetown – Pelican Rapids 115 kV double circuit line

 

Non-Wires Alternatives

Following two NWA were identified to address the Frazee area reliability issues. For detailed analysis, refer to the NWA report done by GRE.

 

NWA – 1

    • 40 MVAr STATCOM at Frazee
    • 10 MW solar PV with 20 MWh ES at Pelican Turkey
    • 40 MW solar PV with 80 MWh ES at Frazee

 

NWA – 2 (with capacitor banks)

    • 20 MW solar PV with 40 MWh ES at Pelican Turkey
    • 20 MW solar PV with 40 MWh ES at Frazee

 

Analysis:  The Erie – Frazee project was determined to be the most reliable and least cost project.

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 is expected to issue the route permit for this project in late October 2021.


Erie/Audubon Alternate Service

MPUC Tracking Number: 2019-NW-N5

Utility:  Minnkota Power Cooperative (MPC)

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.

Alternatives:  

Transmission Alternatives

Initial project alternatives included a second transformer at Ulrich, an Audubon-Christensen 69 kV line, or Ulrich 69 kV capacitors. All of these failed to provide fully redundant service to Audubon and Erie. Several options exist to provide similar service; however, they are not as cost effective. These include:

    • Normal 41.6 kV service from Erie Jct. 230 kV with backup service from Ulrich (or Audubon)
    • Normal 41.6 kV service from Audubon, alternate 41.6 kV service from new load tap.
    • Normal or alternate 25 kV underground service from Erie Jct. 230 kV

Non-Wires Alternatives

Battery backup for use as a non-wire alternative was explored but was found to far less cost effective.

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.

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.

Hoot Lake 115/41.6 kV Transformer Replacement

MPUC Tracking Number: 2021-NW-N1

Utility: Otter Tail Power Company (OTP)

Project Description: The existing 115/41.6 kV transformer the Fergus Falls Hoot Lake substation is planned to be replaced with a higher-capacity 115/41.6/34.5 kV transformer equipped with a Load Tap Changer (LTC) on the 41.6 kV winding.

Need Driver: There are three primary need drivers for this project:

The first driver is the age & condition of the existing transformer. The transformer is early 1960s vintage and is showing signs that it is nearing end-of-life. The transformer has two secondary bushings showing signs of degradation and other issues that will lead to imminent failure. Repair work for these issues is not economical for a transformer of this age.

The second driver is system performance concerns. OTP has identified some low voltage concerns on the 41.6 kV transmission system around Hoot Lake. Low voltages can develop in the Pelican Rapids area and in the Silver Lake area for single-element outages during winter peak conditions. The existing transformer is not equipped with an LTC that could improve voltage performance during these outages, but the replacement transformer provides the opportunity to add an LTC to address these concerns. Additionally, the transformer is nearing its thermal capacity for some single-element outages, so the replacement will be sized appropriately to add some thermal margin.

The final need driver is that OTP plans to replace some of the generation capacity of the retiring Hoot Lake coal plants with a 49.9 MW solar farm (MISO generator replacement project R1001). A 34.5 kV tertiary winding on the replacement transformer is the most cost-effective solution to accommodate the interconnection of this solar farm. The Hoot Lake coal plants retired in late May 2021, and the solar farm is expected to be in service in 2022.

Alternatives:

Transmission Alternatives

Several alternatives were identified to address the same concerns as the Hoot Lake transformer replacement project. The first alternative was to add a second 115/41.6 kV transformer in parallel with the existing unit. The second alternative was to move the town of Pelican Rapids load to the 115 kV system and add a capacitor near Silver Lake on the 41.6 kV system. The final alternative was to add a 115/41.6 kV substation at Rothsay and a capacitor near Silver Lake on the 41.6 kV system. All these projects had substantially higher costs than the replacement transformer project, and none of them addressed the age & condition issues of the existing transformer.

Non-Wires Alternatives

Any non-wires alternatives would not have addressed the age & condition issues of the existing transformer, and none would have accommodated the interconnection of the Hoot Lake solar farm.

Analysis: The need for voltage support around Hoot Lake was identified in the Otter Tail Power Company Ten Year Development Study. The replacement 115/41.6/34.5 transformer with a 41.6 kV LTC effectively mitigates these voltage concerns.

Schedule:  The Hoot Lake 115/41.6/34.5 kV replacement transformer is expected to go in service around mid-2022.

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. Additionally, this project enables the interconnection of new solar generation.

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, minimal impact is expected as a result of the substation modifications.


Henning 230 kV Breaker Addition

MPUC Tracking Number:  2021-NW-N2

Utility:  Great River Energy (GRE)

Project Description:  Add two 230 kV breakers at the Henning substation.

Need Driver:  Prevent Henning – Inman 230 kV and Henning – Silver Lake 230 kV line faults from tripping off entire substation.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

Schedule:  The project is planned to be in service by Summer 2029. 

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.


Inman 230 kV Breaker Addition

MPUC Tracking Number:  2021-NW-N3

Utility:  Great River Energy (GRE)

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

Need Driver:  Prevent Inman – Wing River 230 kV line faults from tripping off the 230/115 kV transformer.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

Schedule:  The project is planned to be in service by Summer 2035. 

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.


Cormorant – Pelican Rapids Storm Structures

MPUC Tracking Number:  2021-NW-N4

Utility:  Great River Energy (GRE)

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.

Alternatives: 

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement to an existing line to prevent cascading structure failure and no alternatives were considered.

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

Schedule:  The project is planned to be in service by June 2024. 

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.


6.3.2  Completed Projects

The table below identifies projects that have been completed since our 2019 report.  

MPUC Tracking Number

Description

MPUC Docket

Utility

Date Completed

2015-NW-N1

Clearbrook 115 kV-Bagley West 230 kV

None

MPC/OTP

Cancelled

2015-NW-N5

Ulrich 115/69 kV Transformer Replacement

9652

MPC

11/1/2019

2019-NW-N4

Lake Eunice

Not Required

GRE

2021

   

6.4    Northeast Zone

6.4.1  Needed Projects

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.

MPUC Tracking Number

MISO Project Name

MTEP Year/App

MTEP Project Number

CON?

Non-Wire Alt.

Utility

2007-NE-N1

Duluth Area 230 kV

2014/B

2548

Yes

Yes

MP

2013-NE-N16

Square Butte—Arrowhead HVDC Valve Hall Replacement

2013/B

4295

No

No

MP

2013-NE-N17

Square Butte—Arrowhead HVDC Upgrade

2014/B

3856

No

No

MP

2015-NE-N12

Iron Range-Arrowhead 345 kV Project

2014/B

3832

Yes

No

MP

2015-NE-N14

83 Line Upgrade

2016/A

9622

No

Yes

MP

2017-NE-N2

Laskin-Tac Harbor Voltage Conversion

2016/A

10383

No

No

MP

2017-NE-N3

Little Falls Substation Modernization

2020/A

18110

No

No

MP

2017-NE-N6

Forbes Tie Breaker Addition

2019/A

10285

No

No

MP

2017-NE-N21

Laskin-Tac Harbor Transmission Line Upgrades

2018/A

13504

No

Yes

MP

2017-NE-N23

Mesaba Junction 115 kV Project

2018/A

13485

No

Yes

MP

2019-NE-N2

Forbes 37 Line Upgrade

2019/A

15591

No

Yes

MP

2019-NE-N4

25 Line Upgrade

2020/A

2022/A

15593

21605

No

Yes

MP

2019-NE-N5

29 Line Upgrade

2019/B

15594

No

Yes

MP

2019-NE-N6

Long Prairie Substation Modernization

2019/A

15596

No

No

MP

2019-NE-N8

Badoura Transformer Replacement

2020/A

15598

No

No

MP

2019-NE-N10

Babbitt Area 115 kV Project

2018/B

2018/B

16069

16070

No

Yes

MP

2019-NE-N12

Duluth Loop Reliability Project

2022/A

2022/A

17868

20077

Yes

Yes

MP

2019-NE-N13

National Breaker Replacements

2020/A

17870

No

No

MP

2019-NE-N14

Laskin Breaker Replacements

2020/A

17871

No

No

MP

2019-NE-N15

Portage Lake 115/69 kV Project

2020/A

17664

No

No

GRE

2021-NE-N1

Square Butte – Arrowhead HVDC Line Hardening

2022/A

18058

No

No

MP

2021-NE-N2

8 Line Relocation

2020/A

18060

No

No

MP

2021-NE-N3

Hibbing Substation Modernization

2020/A

18064

No

No

MP

2021-NE-N4

Verndale Substation Modernization

2020/A

18065

No

No

MP

2021-NE-N5

Badoura 115 kV Substation Modernization

2021/A

18066

No

No

MP

2021-NE-N6

15th Ave West Transformer Addition

2020/A

18109

No

Yes

MP

2021-NE-N7

98 Line Asset Renewal

2021/A

18945

No

No

MP

2021-NE-N8

LSPI Cap Bank Asset Renewal

2021/B

20030

No

No

MP

2021-NE-N9

Canosia Road Substation 34 kV Expansion

2021/A

20032

No

No

MP

2021-NE-N10

95 Line Asset Renewal

2021/B

20071

No

No

 MP

2021-NE-N11

Two Islands 115 kV Project

2022/A

20074

No

No

MP/

GRE

2021-NE-N12

Forbes 230 kV Modernization

2021/A

20075

No

No

MP

2021-NE-N13

Cloquet Substation Modernization

2021/B

20087

No

No

MP

2021-NE-N14

Mesaba Junction 137 Line Extension

2022/A

21686

No

Yes

MP

2021-NE-N15

137 Line Rebuild

2022/B

21762

No

No

MP

2021-NE-N16

North Shore Transformer Addition

2022/A

21763

No

No

MP

2021-NE-N17

West Cohasset Substation

2022/A

21606

No

No

MP

2021-NE-N18

Boise Breaker Addition

2022/B

21607

No

No

MP

2021-NE-N19

56 Line Upgrade

2022/B

21764

No

Yes

MP

2021-NE-N20

105 & 106 Line Upgrade

2022/A

21608

No

Yes

MP

2021-NE-N21

Iron Range Synchronous Condenser

2022/B

21765

No

Yes

MP

2021-NE-N22

126 Line Asset Renewal

2022/A

21766

No

No

MP

2021-NE-N23

13 Line Rebuild

2022/B

21767

No

No

MP

2021-NE-N24

Fond du Lac - Wrenshall

Future

TBD

No

No

GRE

2021-NE-N25

Shamineau Lake

2022/A

21830

No

No

GRE

2021-NE-N26

Wing River 230 kV Ring Bus

2021/A

20143

No

No

GRE

2021-NE-N27

Riverton - Wing River Storm Structures

2022/A

21824

No

No

GRE


Duluth 230 kV Project
 

MPUC Tracking Number:  2007-NE-N1

Utility:  Minnesota Power (MP)

Project Description:  Add a second 230/115 kV transformer at the Hilltop Substation, expand Hilltop Substation to a 4-position 230 kV ring bus, 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.

Alternatives: 

Transmission Alternatives

Build a new 230/115 kV substation in the Duluth area.

Non-Wires Alternatives

Install new dispatchable generation in the Duluth area. Non-wire alternatives must be dispatchable to respond when called upon and of sufficient duration to prevent or mitigate overloading. Minnesota Power will continue to consider non-wire alternatives alongside the Duluth 230 kV Project as the need and timing for the project develop.

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.


Square Butte – Arrowhead HVDC Valve Hall Replacement

MPUC Tracking Number:  2013-NE-N16

Utility:  Minnesota Power (MP)

Project Description:  Replace the Center (Square Butte) and Arrowhead HVDC converter stations and associated assets with modern equipment on Square Butte – Arrowhead HVDC line.

Need Driver:  The Center (Square Butte) and Arrowhead HVDC converter stations were designed by General Electric (GE) for a 30 year operating lifetime and as of 2021 they have been operating reliably for over 40 years. The main components of the HVDC converter stations include power electronics (thyristor valves) and their associated cooling system, converter transformers, smoothing reactors, harmonic filters and reactive resources to complete the conversion between alternating current (AC) and direct current (DC). The original vendor, GE, left the HVDC business in the 1980s and in recent years it has been increasingly difficult to procure spare parts for the converter stations as the technology is becoming obsolete and the original designers are well into retirement. Minnesota Power has researched reverse engineering solutions to this technology issue, but has had limited results and thus spare and replacement parts for the converter stations remain limited. Modernizing the converter stations by replacing the thyristors, cooling system, converter transformers, smoothing reactors, harmonic filters, reactive resources, and control system will greatly reduce the likelihood of an extended outage due to component failures in the HVDC converter stations.

Alternatives: 

Transmission Alternatives

There are two alternatives. “Do Nothing” (risk of extended outage due to equipment failure) or implement the Square Butte – Arrowhead HVDC Upgrade (Tracking Number 2013-NE-N17).

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Center and Arrowhead HVDC converter stations.

Analysis:  Replacement of the existing thyristor valves with modern equipment is the minimum necessary project to maintain the reliability of Minnesota Power’s HVDC line and reduce the risk of extended outages due to equipment failure. 

Schedule:  At this time, Minnesota Power is focused on developing the Square Butte – Arrowhead HVDC Upgrade (Tracking Number 2013-NE-N17). At the request of Minnesota Power, MISO performed Transmission Service Request (TSR) System Impact Studies on varying levels of increased HVDC capacity in 2019-2020 and provided Facilities Studies to the TSR customers documenting the associated costs. While the timing of the HVDC Modernization and Capacity Upgrade projects has been fluid in recent years due to Minnesota Power’s ongoing assessment of the risks, value proposition, and long-term opportunities associated with the projects, Minnesota Power presently anticipates proceeding with an HVDC converter station modernization and upgrade project to be complete and placed in service by the end of 2027.

General Impacts:  The modernization of the HVDC equipment is a prudent and necessary activity to 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 anticipated to take place within the footprint of the existing converter terminal buildings and substations, it is anticipated that no new landowners would be impacted by the project.   


Square Butte – Arrowhead HVDC Upgrade

MPUC Tracking Number:  2013-NE-N17

Utility:  Minnesota Power (MP)

Project Description:  Replace the Center (Square Butte) and Arrowhead HVDC converter stations and associated assets with modern equipment on Square Butte – Arrowhead HVDC line and upgrade existing line and terminal equipment to 750 MW or higher capacity.

Need Driver:  The Center (Square Butte) and Arrowhead HVDC converter stations were designed by General Electric (GE) for a 30 year operating lifetime and as of 2021 they have been operating reliably for over 40 years. The main components of the HVDC converter stations include power electronics (thyristor valves) and their associated cooling system, converter transformers, smoothing reactors, harmonic filters and reactive resources to complete the conversion between alternating current (AC) and direct current (DC). The original vendor, GE, left the HVDC business in the 1980s and in recent years it has been increasingly difficult to procure spare parts for the converter stations as the technology is becoming obsolete and the original designers are well into retirement. Minnesota Power has researched reverse engineering solutions to this technology issue, but has had limited results and thus spare and replacement parts for the converter stations remain limited. Modernizing the converter stations by replacing the thyristors, cooling system, converter transformers, smoothing reactors, harmonic filters, reactive resources, and control system will greatly reduce the likelihood of an extended outage due to component failures in the HVDC converter stations.

The modernization of the existing Center and Arrowhead HVDC converter stations presents a once-in-a-generation opportunity to consider enhancements to the long-term value of the HVDC system. At a time when there is increasing focus on long-term regional transmission needs and renewable energy integration, it is especially worthwhile to evaluate the costs and benefits of increasing the capacity and usefulness of the Square Butte – Arrowhead HVDC corridor. 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 concurrently with modernization of the converter stations. Upgrades would also be needed along the 465-mile HVDC transmission line to achieve increased capacity above 550 MW. Depending on the long-term value outlook, a lower total capacity such as 750 MW may ultimately prove to be the most cost-effective and efficient solution for Minnesota Power’s customers. Modern HVDC technology at the converter stations would also enhance HVDC dispatch capability and allow energy to flow in both west to east and east to west directions, adding new flexibility and optionality for the regional transmission system. More significant changes to the capacity, operating voltage, and converter technology of the HVDC system could also provide enhanced long-term value for Minnesota Power and the region, but would come at considerably higher cost. Minnesota Power is in the process of carefully considering the long-term value of the HVDC corridor both internally and with MISO in order to determine the best path forward for its customers and the region.

Alternatives: 

Transmission Alternatives

Square Butte – Arrowhead HVDC Valve Hall Replacement (Tracking Number 2013-NE-N16).

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Center and Arrowhead HVDC converter stations.

Analysis:  Replacement of the existing thyristor valves with modern equipment is the minimum necessary project to maintain the reliability of Minnesota Power’s HVDC line and reduce the risk of extended outages due to equipment failure. Given the nature of the HVDC modernization project and the long life of the assets (30+ years anticipated), additional modifications to the HVDC system enabling higher transfer capability on the line will provide the most optimal value-added long-term solution for Minnesota Power at a reasonable incremental cost.

Schedule:  At the request of Minnesota Power, MISO performed Transmission Service Request (“TSR”) System Impact Studies on varying levels of increased HVDC capacity in 2019-2020 and provided Facilities Studies to the TSR customers documenting the associated costs. While the timing of the HVDC Modernization and Capacity Upgrade projects has been fluid in recent years due to Minnesota Power’s ongoing assessment of the risks, value proposition, and long-term opportunities associated with the projects, Minnesota Power presently anticipates proceeding with an HVDC converter station modernization and upgrade project to be complete and placed in service by the end of 2027.

General Impacts:  The modernization of the HVDC equipment is a prudent and necessary activity to 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. The additional capacity facilitated by the Square Butte – Arrowhead HVDC Upgrade Project has the potential to 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 footprint of the existing converter terminal buildings and substations and on the existing transmission line right-of-way, it is anticipated that no new landowners would be impacted by the project.  


Iron Range-Arrowhead 345 kV Line

MPUC Tracking Number:  2015-NE-N12

Utility:  Minnesota Power (MP)

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. This project was formerly coupled together with the Great Northern Transmission Line (Tracking Number 2013-NE-N13) but the two projects were subsequently decoupled due to the lack of sufficient transmission service requests to justify the 345 kV connection to Arrowhead.

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, it will be advanced at that time based on its own merits.

Alternatives:

Transmission Alternatives

No other alternatives are currently being considered.

Non-Wires Alternatives

None.

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.


83 Line Upgrade

MPUC Tracking Number:  2015-NE-N14

Utility:  Minnesota Power (MP)

Project Description:  Replace limiting 230 kV terminal equipment at the Boswell and Blackberry substations to restore transmission line capacity.

Need Driver:  The Boswell-Blackberry 230 kV lines (MP “83 Line” and “95 Line”) were derated after a NERC-mandated equipment audit identified undersized terminal equipment at the Boswell and Blackberry substations. The 83 Line Upgrade Project restores the capacity of 83 Line, a critical outlet for Boswell generation, to its original capacity.

Alternatives: 

Transmission Alternatives

Build a third Boswell-Blackberry 230 kV Line.

Non-Wires Alternatives

Install new dispatchable energy resource in the area. Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at an effective location to prevent or mitigate overloading.

Analysis:  There is no more economical or less impactful solution than replacing the limiting equipment to restore the capability of the existing line.

Schedule: This issue was first identified when 83 Line and 95 Line were derated; however, single contingency overloads on 83 Line following the derate have not been identified in any studies to date. Minnesota Power is monitoring MTEP reliability assessment results, as well as the results of Minnesota Power internal studies, to determine if and when a project is needed to restore 83 Line to its original capacity. 

General Impacts: 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 address any issues caused by derating 83 Line.


Laskin-Tac Harbor Voltage Conversion

MPUC Tracking Number:  2017-NE-N2

Utility:  Minnesota Power (MP)

Project Description: The Laskin-Tac Harbor Voltage Conversion involves converting the legacy 138 kV system between the Laskin and Taconite Harbor substations to 115 kV operation. The work includes removing 138/115 kV transformers, replacing 138 kV equipment with 115 kV equipment, and replacing other aging equipment at the existing Laskin, Skibo, Hoyt Lakes and Tac Harbor substations. A previously-planned expansion of the existing Hoyt Lakes Substation has been eliminated from the scope of the project due to space limitations at the existing substation as well as constructability and maintainability concerns. Instead, a new switching station was constructed on a nearby site as part of the Mesaba Junction 115 kV Project (Tracking Number 2017-NE-N23).

Need Driver: Age and condition, removal of single points of failure, standardization of equipment, redundancy and voltage support concerns without local coal-fired generators online in the North Shore Loop.

Alternatives:

Transmission Alternatives

Continue to operate at 138 kV.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition of the 138 kV system assets or standardization of equipment.

Analysis: The Laskin-Tac Harbor 138 kV system was originally established by a mining company in the mid-1900s to connect its generating assets at Taconite Harbor to its plant operations in Hoyt Lakes. Over the years, improvements were made to provide redundancy to the area by connecting the 138 kV system to Minnesota Power’s 115 kV system. Today, Minnesota Power owns the transmission in the Laskin-Tac Harbor 138 kV system and it provides a transmission connection that is critical for the reliability of service to all Minnesota Power and Great River Energy customers in the North Shore Loop.

The transition away from local baseload coal-fired generators in the North Shore Loop has served to increase the importance of the Laskin-Tac Harbor connection for the reliable delivery of power into the North Shore Loop from external sources, in addition to causing a need for additional voltage support in the area. The Laskin-Tac Harbor Voltage Conversion Project leads to the elimination of single points of failure with long replacement lead times (138/115 kV transformers), providing a more redundant and reliable transmission connection for the North Shore Loop. These reliability objectives are accomplished by the project in addition to the inherent benefits of replacing aging equipment, eliminating a non-standard voltage class from the Minnesota Power transmission system, and avoiding the cost of additional 138/115 kV transformers for redundancy, replacement, or the establishment of new transmission connections.

Beyond the benefits described above, the Voltage Conversion Project positions the northern end of the North Shore Loop for the establishment of other local redundancy and voltage support projects, including the Mesaba Junction 115 kV Project (Tracking Number 2017-NE-N23) and the Babbitt Area 115 kV Project (Tracking Number 2019-NE-N10). Continued operation of the Laskin-Tac Harbor system at 138 kV would significantly increase the cost and complexity of making these transmission improvements in the area.

Schedule:  The project will be coordinated with the construction of the Mesaba Junction 115 kV Project and is expected to be in service by the end of 2022. Outage coordination as well as lead times on engineering and materials have led to delays in implementation of the project.

General Impacts: The Laskin-Tac Harbor Voltage Conversion Project will eliminate a non-standard voltage class from the Minnesota Power system, mitigating single points of failure, replacing aging equipment, and avoiding the future cost of adding or replacing other equipment unique to the 138 kV system. It is the most efficient and least environmentally impactful solution for meeting the near-term and long-term needs of the North Shore Loop, making good use of the existing 138 kV facilities by converting them to 115 kV. The Voltage Conversion Project is also a critical component of maintaining a reliable system in the face of significant changes in the North Shore Loop. Replacing voltage support previously provided by baseload coal units in the area and improving the redundancy 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.


Little Falls Substation Modernization

MPUC Tracking Number:  2017-NE-N3

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

Establish a replacement 115/34 kV distribution station in the Little Falls area. Add another 115 kV capacitor bank in the area or reconfigure the Little Falls 115 kV bus to include a bus tie breaker.

Non-Wires Alternatives

Install new distribution-connected generation on Little Falls, Blanchard, or Pepin Lake 34.5 kV systems. Non-wire alternatives must be available when needed and have an output characteristic sufficient to reduce the effective peak load in the area. However, non-wire alternatives cannot address concerns related to age and condition at the Little Falls Substation.

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.


Forbes Tie Breaker Addition

MPUC Tracking Number:  2017-NE-N6

Utility:  Minnesota Power (MP)

Project Description: Reconfigure Forbes 115 kV bus to install a redundant bus tie breaker. One 115 kV transmission line entrance will be relocated to the end of the bus to make room for the redundant tie breaker. Replace end-of-life circuit breakers and associated equipment.

Need Driver: Internal fault or failure of breaker to operate causes overloading on area transmission lines and low post-contingent voltages. Installation of a redundant bus tie breaker will eliminate the contingency causing these issues. Age and condition of existing Forbes 38-44 MW breaker, 37L breaker, and 38L breaker along with equipment such as switches and relay panels. 

Alternatives:

Transmission Alternatives

Install breaker failure relay on existing Forbes 38-44MW 115 kV bus tie breaker, thermal upgrade overloaded transmission lines, and install additional voltage support in the area.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition of the breakers and associated equipment.

Analysis: This issue has been identified in MTEP assessments and Minnesota Power studies going back to MTEP15. Subsequent Minnesota Power studies have indicated that changes in the North Shore Loop which increase reliance on the Forbes 230/115 kV source for delivery of power once provided locally by baseload generators cause the Forbes tie breaker failure contingency to become more severe than initially anticipated in MTEP15. Therefore, Minnesota Power concluded that the addition of a redundant bus tie breaker is the most comprehensive long-term solution for the area, while also being cost-effective and limiting impact to the Forbes Substation and the immediately adjacent transmission line entrances.

Schedule: In coordination with the construction of other projects related to changes in the North Shore Loop, the Forbes Tie Breaker Addition is presently planned to be constructed over the 2021 and 2022 summer and fall seasons.

General Impacts: Minnesota Power’s approach to this issue is intended to ensure that the most appropriate solution (in terms of cost, human, and environmental impacts) is implemented at the most appropriate time to address the issue first identified in the MTEP15 assessment and any related issues that may be efficiently addressed with the same project. Per the scope discussed above, the impacts will be mostly contained within the existing Forbes Substation yard and no expansion area will be necessary. The only impacts outside the substation yard will be due to the relocation of a transmission line entrance to make room for the redundant tie breaker.


Mesaba Junction 115 kV Project

(formerly known as “Hoyt Lakes 115 kV Project”)

MPUC Tracking Number:  2017-NE-N23

Utility:  Minnesota Power (MP)

Project Description:  The new Mesaba Junction Switching Station will be constructed and interconnected to the existing transmission lines in the area connecting to the Taconite Harbor, Hoyt Lakes, and Laskin substations. In addition to the transmission line connections, the new switching station will include two switched capacitor banks to provide voltage support. Approximately 5.4 miles of new 115 kV line will be constructed along the existing Laskin – Hoyt Lakes transmission line corridor to extend the existing Forbes – Laskin 115 kV Line (“38 Line”) into Mesaba Junction. The existing connection to the Laskin Substation will be eliminated.

Need Driver:  Redundancy, reliability, voltage support, and transmission capacity concerns following conversion, idling, or retirement of North Shore Loop coal-fired generators.

Alternatives:

Transmission Alternatives

Build a second Laskin-Hoyt Lakes transmission line and reconfigure (or rebuild) Laskin Substation to eliminate single points of failure.

Non-Wires Alternatives

Install new dispatchable energy resource in the area. Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at an effective location to prevent or mitigate overloading.

Analysis:  The Mesaba Junction 115 kV Project meets four critical needs for the North Shore Loop, as discussed below. 

First, the project supports redundancy by providing a third transmission source into the area, establishing a more robust substation configuration, and enabling a standardized network voltage. The Mesaba Junction 115 kV Project establishes a new 115 kV line parallel to the existing Laskin – Hoyt Lakes 115 kV Line and a new switching station that replaces the simple straight bus configuration of the existing Hoyt Lakes Substation with a more reliable ring bus configuration. The Project will be coordinated with the Laskin-Tac Harbor Voltage Conversion Project (Tracking Number 2017-NE-N2), greatly enhancing the constructability of that project and enabling Minnesota Power to realize all the benefits of a standardized network voltage.

Second, the project enhances reliability by providing a modern, utility-controlled path for power flow into the North Shore Loop. The Mesaba Junction 115 kV Project will place the customer-owned Hoyt Lakes Substation in a dedicated local network, relocating the regionally-important bulk electric system path into a new switching station that is designed, owned, operated and maintained by Minnesota Power. The modern design of the new switching station will also provide safer accessibility and maintainability. The result is improved personnel safety, enhanced system reliability, and reduced compliance risk associated with multiple NERC standards. This key benefit became possible when space constraints at the Hoyt Lakes Substation, as well as constructability and maintainability concerns with the facility, caused the previously-planned expansion of the Hoyt Lakes Substation to become infeasible.

Third and fourth, the project improves voltage support and provides transmission capacity to deliver power into the North Shore Loop. Previously, local baseload generators provided both voltage support on a continuous basis and a local source of power that met and, much of the time, exceeded the need for power in the North Shore Loop. New capacitor banks at the Mesaba Junction Switching Station will replace the voltage support that has been lost due to generator retirements. The extension of the existing Forbes – Laskin 115 kV Line into Mesaba Junction will increase power delivery capability into the North Shore Loop for 230/115 kV sources located west of the North Shore Loop to deliver the power no longer being produced by the retired generators.

Schedule:  The Mesaba Junction Switching Station was constructed in 2020. Extension of the Forbes – Laskin 115 kV Line into Mesaba Junction is currently under construction and planned for completion in the first half of 2022, with first energization of Mesaba Junction from Forbes sometime in early second quarter 2022. Subsequently, the remaining transmission line interconnections to Mesaba Junction will be completed as the Laskin-Tac Harbor Voltage Conversion (Tracking Number 2017-NE-N2) is constructed in 2022. Both projects are planned for completion by the end of 2022. Outage coordination as well as lead times on engineering and materials have led to delays in implementation of the projects.

General Impacts:  The Mesaba Junction 115 kV 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 project will require approximately 5 miles of new 115 kV transmission in a remote area of northern Minnesota that has been heavily impacted by historical mining operations.


Forbes 37 Line Upgrade

MPUC Tracking Number:  2019-NE-N2

Utility:  Minnesota Power (MP)

Project Description: Increase rating of Forbes – 37 Line Tap 115 kV Line.

Need Driver: Post-contingent overloads for loss of various parallel circuits following conversion, idling, or retirement of North Shore Loop coal-fired generators and anticipated load growth in the Hoyt Lakes area.

Alternatives:

Transmission Alternatives

Reconductor existing line, build new parallel line.

Non-Wires Alternatives

Install new dispatchable energy resource in the area. Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at an effective location to prevent or mitigate overloading.

Analysis: Following a transition away from baseload coal-fired generators in the North Shore Loop, the power formerly generated locally must be delivered from remote sources outside the North Shore Loop. This causes post-contingent overloading on several area transmission lines, including the Forbes – 37 Line Tap 115 kV Line. The upgrade project provides the needed capacity to ensure reliable delivery of power to the East Range and into the North Shore Loop following transition away from the local generation.

Schedule:  Due to wetlands in the area traversed by the transmission line, construction is advantageous during frozen ground conditions. In coordination with the construction of other projects related to changes in the North Shore Loop, the Forbes 37 Line Upgrade is presently planned to be constructed in the 2021-22 winter season.

General Impacts:  The Forbes 37 Line Upgrade is a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. Increasing the rating of this transmission line allows for the reliable delivery of power to the area from remote sources following the transition away from local baseload coal units, enabling the full realization of significant economic and environmental benefits from transitioning away from these units. The project will provide necessary system improvements to the North Shore Loop without requiring the establishment of additional transmission line corridors, which will minimize any potential environmental impacts.


25 Line Upgrade

MPUC Tracking Number:  2019-NE-N4

Utility:  Minnesota Power (MP)

Project Description: Increase rating of Hibbing – Virginia 115 kV Line (“25 Line”). A second phase has been added to the project to address asset renewal needs on 25 Line and adjacent segment of the Hibbing – 44 Line Tap 115 kV Line (“44 Line”). 25 Line and 44 Line will be rebuilt on double circuit structures from the Hibbing Substation to the 44 Line Tap. 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.

Alternatives:

Transmission Alternatives

Reconductor existing line, build new parallel line.

Non-Wires Alternatives

Install new dispatchable energy resource in the area. Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at an effective location to prevent or mitigate overloading. However, non-wire alternatives can only address the capacity needs and would not displace the need for asset renewal components of the project.     

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 2023.

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.


29 Line Upgrade

MPUC Tracking Number:  2019-NE-N5

Utility:  Minnesota Power (MP)

Project Description: Increase rating of Boswell – Grand Rapids 115 kV Line (“29 Line”).

Need Driver: Overloads following multiple-circuit contingency events in the surrounding area.

Alternatives:

Transmission Alternatives

Reconductor, establish new transmission.

Non-Wires Alternatives

Install new dispatchable energy resource in the area. Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at an effective location to prevent or mitigate overloading.

Analysis: Post-contingent overloads on the Boswell – Grand Rapids 115 kV Line were first identified in the MTEP18 2020 and 2023 summer off-peak cases and are being monitored. A thermal upgrade of the existing line to increase its capacity was submitted as a potential Corrective Action Plan based on the information available at the time. The same issue has not been observed consistently in subsequent MTEP assessments. Depending on if and how the issue shows up in subsequent assessments, further analysis will be done to clarify the issue and determine what the most appropriate solution is.

Schedule: This issue was first identified in the MTEP18 2020 and 2023 summer off-peak cases and is related to multiple-circuit contingency events. Minnesota Power is monitoring MTEP reliability assessment results to determine if and when a project is needed. 

General Impacts: 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 address the issue first identified in the MTEP18 assessment.


Long Prairie Substation Modernization

MPUC Tracking Number:  2019-NE-N6

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

Develop area distribution system to shift load off Long Prairie.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Long Prairie Substation.

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.


Badoura Transformer Replacement

MPUC Tracking Number:  2019-NE-N8

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

Increase facility ratings to mitigate post-contingent overloads.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition and non-standard equipment at Badoura.

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.

Schedule: The project is currently targeted for an in-service date of 2025.

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 fenceline.


Babbitt Area 115 kV Project

MPUC Tracking Number:  2019-NE-N10

Utility:  Minnesota Power (MP)

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

Alternatives:

Transmission Alternatives

Purchase and rebuild 6 miles of existing customer-owned 115 kV transmission through an active mining area to connect 137 Line from the Embarrass Substation to the 137 Line Extension from the Mesaba Junction Switching Station; or construct approximately 4 miles of new 115 kV transmission south from the Babbitt Tap to the 137 Line Extension to avoid acquiring the customer-owned segment through the mine.

Non-Wires Alternatives

Non-wire alternatives involve new dispatchable energy resources, like reciprocating engines, combustion turbines, or possibly long-duration energy storage, in both the Hoyt Lakes and Babbitt areas. Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at effective locations to prevent or mitigate overloading.

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 2025-26.

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.


Duluth Loop Reliability Project

MPUC Tracking Number:  2019-NE-N12

Utility:  Minnesota Power (MP)

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).

Alternatives:

Transmission Alternatives

New 115 kV or 230 kV line parallel to Arrowhead – Colbyville 115 kV path(s).

Non-Wires Alternatives

New dispatchable transmission- or distribution-connected generation in the Duluth 115 kV Loop; dynamic reactive support and transmission line capacity upgrades in the Duluth 115 kV Loop and the North Shore Loop. Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at an effective location to prevent or mitigate voltage concerns.

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 is planning to submit 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]. Following permitting and engineering activities, preliminary plans are for project construction to take place in 2023-25.

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.


National Breaker Replacements

MPUC Tracking Number:  2019-NE-N13

Utility:  Minnesota Power (MP)

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

Need Driver: Age and condition.

Alternatives:

Transmission Alternatives

There is no more economical or less impactful solution than replacing the existing circuit breakers.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the National Taconite 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 2021-22.

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.


Laskin Breaker Replacements

MPUC Tracking Number:  2019-NE-N14

Utility:  Minnesota Power (MP)

Project Description: Replace end-of-life circuit breakers and associated equipment at Laskin Substation.

Need Driver: Age and condition.

Alternatives:

Transmission Alternatives

There is no more economical or less impactful solution than replacing the existing circuit breakers.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Laskin Substation.

Analysis: Three 115 kV oil circuit breakers from 1962-69 and a transmission-to-distribution transformer of a similar vintage will be replaced as part of this project.

Schedule:  The project is currently planned for construction in 2024 after Minnesota Power recently reviewed and updated substation asset renewal priorities.

General Impacts:  The Laskin 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 Laskin Substation, which is located at the Laskin Energy Center, making optimal use of the existing site infrastructure to minimize human and environmental impacts.


Portage Lake 115/69 kV Project

MPUC Tracking Number:  2019-NE-N15

Utility:  Great River Energy (GRE)

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:  Long radial line exposure.  Thermal overloading during winter peak.

Alternatives:

Transmission Alternatives

Upgrade Four Corners Transformer

The Four Corners 115/69 kV transformer has a top rating of 28 MVA. An option that was evaluated was to add more transformation capacity at Four Corners. This option is relatively inexpensive, but it does nothing to alleviate the radial MW-mile exposure seen by the 4 substations served from the Palisade Radial 69 kV system.

Gowan 115/69 kV

The Gowan 115/69 kV concept utilizes the 156 Line (Cromwell – Savanna 115 kV) that passes by GRE’s Gowan substation and interconnects to the existing 69 kV lines at Gowan via a 115/69 kV transformer. This project will alleviate the loading concerns on Four Corners transformer but falls short of alleviating the radial MW-mile exposure seen by the 4 substations served from the Palisade Radial 69 kV system.

Non-Wires Alternatives

A non-wires alternative (NWA) such as generation (solar, wind), demand response (load management), or energy storage (battery, plug-in hybrid vehicles) could be used to solve or partially solve the thermal overloads and voltage violations resulting from the loss of the Cromwell – Palisade Tap 69 kV line but it does not address the 32 miles of transmission line that the four Member substations are exposed to.

The system’s peak loading is happening at night during winter months. The area is not wind rich and would have to rely on solar and since the peak is at night, it would have to be solar plus battery technology.

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%.

Schedule:  The project is planned to be in service by November 2023. 

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.


Square Butte – Arrowhead HVDC Line Hardening

MPUC Tracking Number:  2021-NE-N1

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

Due to the nature of the issue, the only other alternative is to “Do Nothing” – which would proliferate the risk of extended outages, difficult restoration, and adverse on-the-ground impacts from HVDC structure failures at high-profile or high-impact locations.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address the structural failure concerns.

Analysis: In coordination with the planned modernization of the converter stations and the capacity upgrade of the Square Butte – Arrowhead HVDC system (2013-NE-N16 and/or 2013-NE-N17), Minnesota Power is also planning a transmission line “hardening” project. While the modernization of the converter stations will result in refurbished HVDC components at Center and Arrowhead 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 Upgrade 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 Upgrade 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 Square Butte – Arrowhead HVDC system 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 as it is packaged with the transmission line capacity upgrade component of the HVDC Upgrade Project (2013-NE-N17). The earliest start date for construction of the project is 2022.

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. 


8 Line Relocation

MPUC Tracking Number:  2021-NE-N2

Utility:  Minnesota Power (MP)

Project Description: Relocate existing Fond du Lac – Thomson 115 kV Line (8 Line) off of a failing slope onto a shared Right-Of-Way with Fond du Lac – Hibbard 115 kV Line (15 Line). The rest of 8 Line will then be rebuild and reconductored due to age and condition, replacing transmission line components and obtaining additional capacity. At the Fond du Lac Substation, aging equipment will be replaced, and a new 115 kV circuit breaker, relay panel, and associated equipment will be added. Limiting jumpers will be replaced at both the Thomson and Fond du Lac substations.

Need Driver: MNDOT requested relocation of Fond du Lac – Thomson 115 kV (8 Line) off of a failing slope near Highway 210. There are also age and condition replacement needs and a long-term capacity need as well.

Alternatives:

Transmission Alternatives

Do nothing with the transmission line and reinforce the failing slope.

Non-Wires Alternatives

Non-wire alternatives cannot displace the need for age and condition-related upgrades to the existing transmission line.

Analysis: A structure on the Fond du Lac – Thomson 115 kV Line is located near a failing slope to the west of the Highway 210 crossing. For reliability reasons, it is necessary to relocate 8 Line away from this slope. In 2017, MNDOT requested that both 8 Line and 15 Line be relocated off of this particular failing slope as the steep grade between the structures atop this failing slope presents a risk to Highway 210 travelers. 15 Line leaving Fond du Lac Substation was relocated away from this failing slope in 2018 and sufficient right-of-way was obtained and cleared at the time to accommodate paralleling 8 Line along the south side of this 15 Line corridor. From the point where the existing 15 Line corridor turns North after crossing Highway 210, 8 Line will turn southwest to obtain an alignment with the existing 8 Line river crossing. The remaining length of 8 Line will be rebuilt and reconductored due to age and condition, similar to other transmission line asset renewal projects that Minnesota Power is developing.

Schedule:  The project is presently planned for construction in 2022.

General Impacts:  The 8 Line Relocation Project will ensure that the existing Fond du Lac – Thomson 115 kV Line continues to provide a safe and reliable transmission path for Minnesota Power’s customers and hydroelectric assets in the Duluth and Cloquet areas. The short segment of relocation will be primarily located adjacent to an existing transmission line, and will improve transmission reliability and public safety by moving away from the failing slope. The rest of the project involves replacement of existing assets on the existing transmission line right-of-way. In both cases, the project will make optimal use of existing transmission line corridors in the area to minimize human and environmental impacts.


Hibbing Substation Modernization

MPUC Tracking Number:  2021-NE-N3

Utility:  Minnesota Power (MP)

Project Description: The Hibbing Substation is located west of Hibbing, Minnesota, south of the Hibbing Taconite mining operations. The Hibbing 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. This work at the Hibbing Substation was combined into one project in order to facilitate efficient coordination of engineering and construction.

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.

Alternatives:

Transmission Alternatives

Develop area distribution system to shift load off the Hibbing Substation to existing or new distribution substations.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Hibbing Substation.

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 2022, with above-grade construction taking place in stages from 2023-2024 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.


Verndale Substation Modernization

MPUC Tracking Number:  2021-NE-N4

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

Install new 115/34 kV transformers at nearby Wing River 230/115 kV Substation and reconfigure distribution system to enable retirement of Verndale Substation.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Verndale Substation.

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 stages from 2024-2025 to manage outage and constructability constraints.

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.


Badoura 115 kV Substation Modernization

MPUC Tracking Number:  2021-NE-N5

Utility:  Minnesota Power (MP)

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.

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.

Alternatives:

Transmission Alternatives

Replace the breakers in current locations and modernize original Badoura 115 kV Substation yard to retain existing box structure.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition of 115 kV equipment at Badoura.

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.

Schedule:  The project is scheduled to build out a new alternate station service source for the 115 kV and 230 kV yards as well as remove existing 34.5 kV equipment in 2022. The line relocations and cap bank bus buildout is scheduled for 2023 for a final in-service date of 2023.

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.


15th Avenue West Transformer Addition

MPUC Tracking Number:  2021-NE-N6

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

Establish a new 115/34 kV substation near downtown Duluth; reinforce existing Duluth 34 kV system by building new feeders to existing sources at Swan Lake Road and LSPI substations.

Non-Wires Alternatives

Install new distribution-connected generation on Duluth 34 kV system. Non-wire alternatives must be available when needed, dispatchable to support reliable load-serving under contingency conditions, and have an output characteristic sufficient to reduce the effective peak load in the area.

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.


98 Line Asset Renewal

MPUC Tracking Number:  2021-NE-N7

Utility:  Minnesota Power (MP)

Project Description: The 98 Line Asset Renewal Project involves asset renewal and structure replacements to increase the clearance of spans for the existing 954 ACSR “Cardinal” conductor on the existing Iron Range – 98 Line Tap 230 kV Line.

Need Driver: Replacing old structures and increasing conductor to ground clearance margins. The project is also being coordinated with additional asset renewal work on 98 Line to address identified age & condition issues.

Alternatives:

Transmission Alternatives

There are no reasonable alternatives that will address the clearance and asset renewal requirements for the existing structures on 98 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.

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:  Construction on the 98 Line Asset Renewal Project was completed in 2021.   

General Impacts:  The 98 Line Asset Renewal Project will ensure that the existing Iron Range – 98 Line Tap 230 kV Line continues to provide a safe and reliable transmission path for Minnesota Power’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 line with little or no additional human or environmental impacts.


LSPI Cap Bank Asset Renewal

MPUC Tracking Number:  2021-NE-N8

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

Remove and replace the entire capacitor bank.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition of the existing capacitor bank.

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.

Schedule:  The project is being targeted for implementation in 2022 or 2023 depending on overall project priorities and availability.

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.


Canosia Road Substation 34 kV Expansion

MPUC Tracking Number:  2021-NE-N9

Utility:  Minnesota Power (MP)

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 intercDriveronnect 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 : 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.

Alternatives:

Transmission Alternatives

Establish a new 115/24 kV or 115/46 kV source from Canosia Rd to tie into existing non-standard voltages in the Cloquet area; build a new 115/34 kV substation at a different location.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition and voltage standardization for the Cloquet-area distribution system.

Analysis: The Canosia Road Substation 34 kV Expansion will be the first step and foundation in a mutli-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 planned for implementation 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.


95 Line Asset Renewal

MPUC Tracking Number:  2021-NE-N10

Utility:  Minnesota Power (MP)

Project Description:  The 95 Line Asset Renewal Project involves replacement of transmission line components on the Boswell – Blackberry 230 kV Line (“95 Line”) due to age and condition.

Need Driver:  The project will address asset renewal needs on 95 Line related to the age and condition of existing structures, conductor, guy attachments, and other hardware.

Alternatives: 

Transmission Alternatives

There are no reasonable alternatives that will address the asset renewal needs for the existing transmission line components on 95 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.

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:  The 95 Line Asset Renewal Project is presently targeted for construction in 2026.

General Impacts:  The 95 Line Asset Renewal Project will ensure that the existing Boswell – Blackberry 230 kV Line continues to provide a safe and reliable transmission path for Minnesota Power’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 line with little or no additional human or environmental impacts.


Two Islands 115 kV Project

MPUC Tracking Number:  2021-NE-N11

Utility:  Minnesota Power (MP), Great River Energy (GRE)

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.

Alternatives:

Transmission Alternatives

Complete overhaul of the Taconite Harbor Substation, including removal and reconstruction of foundations and steel structures and reconfiguration of bus work. This alternative results in unacceptable risk to the North Shore Loop with significant periods of radial feeds greatly reducing reliability in the region. GRE investigated the alternative to continue using Taconite Harbor and avoid building a 115/69 kV delivery point at the new GRE Two Islands Substation. This alternative was not embraced because MP couldn’t commit to the duration that the existing Taconite Harbor Substation would continue to exist. The last remaining generators from the Taconite Harbor Energy Center recently completed Attachment Y studies with MISO to decommission.

Non-Wires Alternatives

Non-wire solutions are not viable as they would not address the aging condition and safety and reliability concerns associated with the existing Taconite Harbor Substation.

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 2023, with civil work beginning in 2022. 

GRE Schedule:  The project is planned to be in service by the end of 2024. 

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.


Forbes 230 kV Modernization

MPUC Tracking Number:  2021-NE-N12

Utility:  Minnesota Power (MP)

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.

Need Driver:  Age and condition.

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 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.

Schedule:  The project is presently planned for construction in 2023-24.

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.


Cloquet Substation Modernization

MPUC Tracking Number:  2021-NE-N13

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

Establish a new 115/14 kV substation east of Cloquet and reconfigure distribution system to enable retirement of Cloquet Substation or expand Canosia Rd 34 kV system and establish new 34/14 kV stepdowns to enable retirement of Cloquet Substation.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Cloquet Substation.

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 2023-24 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.


Mesaba Junction 137 Line Extension

MPUC Tracking Number:  2021-NE-N14

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

Do nothing.

Non-Wires Alternatives

Install new dispatchable energy resource in the area. Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at an effective location to prevent or mitigate overloading. In this case, the non-wire alternatives must also be able to continue to support and follow load when isolated from the transmission system due to outages on the only transmission source to the area (137 Line).

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

  1. Providing redundancy to an industrial load pocket that requires near-constant availability
  2. Enabling asset renewal by allowing the 137 Line Rebuild Project (Project Number 2021-NE-N15) to be constructed
  3. Improving reliability with two properly maintained 115 kV transmission sources to the 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 2022 fall season. Transmission line construction and above grade construction at the substation is presently planned to be constructed in the 2022-23 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.


137 Line Rebuild

MPUC Tracking Number:  2021-NE-N15

Utility:  Minnesota Power (MP)

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.

Need Driver: Age and condition.

Alternatives:

Transmission Alternatives

There are no reasonable alternatives that will address the asset renewal needs for the existing transmission line components on 137 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.

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 2023-25, 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.


North Shore Transformer Addition

MPUC Tracking Number:  2021-NE-N16

Utility:  Minnesota Power (MP)

Project Description: The North Shore Transformer Addition Project involves adding a new 115/14 kV transformer at the existing North Shore Switching Station and reconfiguring the Silver Bay area distribution system to interconnect to the new transformer. An existing 115 kV capacitor bank will be relocated to a different bus position to accommodate interconnection of the new transformer. As a result of the project, the existing Silver Bay Hillside Substation will be retired.

Need Driver: The Silver Bay Hillside Substation serves the City of Silver Bay. The substation was scheduled for replacement as part of Minnesota Power’s Substation Modernization Program, however upon field review of site conditions and constructability review it was determined that installing a new transformer at the nearby North Shore Switching Station would be a more optimal long-term solution for the area. The retirement of the Silver Bay Hillside Substation will enable that site to be converted to a mobile substation interconnection location, enhancing Minnesota Power’s contingency plans for the City of Silver Bay distribution system following completion of the project.

Alternatives:

Transmission Alternatives

Rebuild Silver Bay Hillside Substation; establish a new 115/14 kV distribution substation near the City of Silver Bay and reconfigure distribution system to interconnect to it.

Non-Wires Alternatives

Non-wire alternatives are not viable because they cannot address concerns related to age and condition of the Silver Bay Hillside Substation.

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 for construction in 2022.

General Impacts:  The North Shore Transformer Addition Project will ensure a continuous and reliable power supply to the City of Silver Bay by replacing aging equipment before it fails. At present, it is expected that the impacts will be entirely contained within the existing North Shore Switching Station yard, making optimal use of the existing infrastructure to reduce human and environmental impacts.


West Cohasset Substation

MPUC Tracking Number:  2021-NE-N17

Utility:  Minnesota Power (MP)

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 in order to interconnect a new manufactured wood products plant.

Alternatives:

Transmission Alternatives

Extend 115 kV from Zemple, Boswell, or an existing 115 kV line to a new substation site; interconnect to existing Boswell – Zemple 230 kV Line at a new substation site; upgrade existing distribution substations that are remote from the West Cohasset site and build new 23 kV feeder(s) to support additional load.

Non-Wires Alternatives

Non-wire alternatives must be available when needed and dispatchable to support reliable load-serving under normal and contingency conditions.

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

Schedule:  The project must be in-service by mid-2023 to enable interconnection of the new load.

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. The West Cohasset Substation Project is needed to maintain adequate power delivery capability to the Cohasset-area distribution system upon interconnection of a new manufactured wood products plant. Therefore, the project contributes to the realization of significant social and economic benefits for the Cohasset area while minimizing human and environmental impacts by locating new transmission facilities in areas that are already largely dedicated to utility usage.


Boise Breaker Addition

MPUC Tracking Number:  2021-NE-N18

Utility:  Minnesota Power (MP)

Project Description: The Boise Breaker Addition Project involves the installation of a new 115 kV circuit breaker on the International Falls – Boise 115 kV Line (“134 Line”) at the Boise Substation.

Need Driver: The Boise Breaker Addition Project is needed to improve transmission line and bus protection systems for 134 Line and the Boise Substation, provide clearer delineation between Minnesota Power’s transmission system and the customer-owned electric distribution system at the Boise Substation, and improve reliability of service to the paper mill customer. The project also includes replacement of existing metering CTs due to their age and condition.

Alternatives:

Transmission Alternatives

The only reasonable alternative is to do nothing, and continue with the existing configuration.

Non-Wires Alternatives

Non-wire alternatives cannot address system protection design issues.

Analysis: As currently configured, there is no 115 kV breaker on 134 Line at the Boise Substation. This means that for any faults on 134 Line, circuit breakers on the low side of the customer-owned transformers must open to isolate the fault. In addition to complicating the protection system design by intertwining Minnesota Power’s transmission line protection with customer-owned bus and transformer protection, this configuration also inhibits the customer from continuing to operate reliably during and after fault clearing. The project will improve protection design and reliability for the transmission system and the paper mill customer by creating separation between the transmission line and the substation.

Schedule:  The project is presently intended for construction in 2023, in coordination with the paper mill so as to minimize impacts to its operations.

General Impacts:  The Boise Breaker Addition Project will enhance the reliability of service to the paper mill while simplifying protection system designs for both Minnesota Power and Boise. The project is likely to require a fence expansion of the existing Boise Substation, but since the substation is located entirely on paper mill property the expansion will only impact the paper mill.


56 Line Upgrade

MPUC Tracking Number:  2021-NE-N19

Utility:  Minnesota Power (MP)

Project Description: Thermal upgrade on Ridgeview – Colbyville 115 kV (56 Line)

Need Driver: Post-contingent overloads for loss of Arrowhead – Colbyville 115 kV (57 Line) and a Taconite Harbor transmission line.

Alternatives:

Transmission Alternatives

Reconductor existing line, build new parallel line.

Non-Wires Alternatives

Install new dispatchable energy resource in the area. Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at an effective location to prevent or mitigate overloading.

Analysis: Minnesota Power’s internal studies have indicated that there is potential for overloading on the Ridgeview – Colbyville 115 kV Line (56 Line) under certain contingency conditions. The contingency conditions that cause this overload result in a radial North Shore Loop transmission system configuration in which all load from Colbyville to the east is served through 56 Line. Because of the radial nature of the issue, its likelihood depends greatly on the total amount of load at the Colbyville Substation and eastward in the North Shore Loop. The upgrade project would provide the needed capacity to ensure reliable delivery of power from the Duluth area into the North Shore Loop. Minnesota Power is monitoring the annual MTEP reliability assessment results and continuing to evaluate the issue in internal studies to gain a better understanding of the load level threshold and timing for this project.

Schedule:  The project is presently planned for construction no earlier than 2026.

General Impacts:  The 56 Line Upgrade Project will ensure a continuous and reliable power supply to Minnesota Power and Great River Energy customers in the Duluth and North Shore Loop areas 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. The project is expected to be completed entirely on the existing right-of-way, making optimal use of existing transmission assets while minimizing human and environmental impacts.


105 & 106 Line Upgrade

MPUC Tracking Number:  2021-NE-N20

Utility:  Minnesota Power (MP)

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.

Need Driver: Post-contingent overloads for loss of parallel circuits.

Alternatives:

Transmission Alternatives

Build new parallel line; relocate one or more existing 230 kV line terminations from Blackberry to Iron Range to reduce post-contingent flows on the Iron Range – Blackberry 230 kV Lines.

Non-Wires Alternatives

Non-wire alternatives must be dispatchable to respond when called upon, of sufficient duration, and at an effective location to prevent or mitigate overloading.

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.

Schedule:  The project is presently targeted for implementation in 2023-24.

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.


Iron Range Synchronous Condenser

MPUC Tracking Number:  2021-NE-N21

Utility:  Minnesota Power (MP)

Project Description: The Iron Range Synchronous Condenser Project involves the establishment of a synchronous condenser at the existing Iron Range 230 kV Substation.

Need Driver: The new synchronous condenser is needed to ensure a continuous and reliable source of voltage support and system strength during times when no large dispatchable generators are online in Northern Minnesota.

Alternatives:

Transmission Alternatives

Must-run large dispatchable generators such as the Boswell Energy Center for reliability purposes. Retrofit one or more Boswell units with synchronous condenser capability.

Non-Wires Alternatives

Synchronous condensers are a non-wire alternative. Other non-wire alternatives must be dispatchable to respond when called upon, able to provide sufficient magnitude, consistency, and availability of system support, and located at an effective location to replace the support previously provided by baseload generators.

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.

Given the significance of system strength as a potential impact of changing operations of the Boswell Energy Center units, Minnesota Power is in the process of determining how best to evaluate this issue and ensure a minimum level of system strength is maintained at all times for Northern Minnesota in the event that both Boswell units are offline due to a Boswell unit tripping offline unexpectedly while the other one was operating in economic dispatch or due to both units operating in economic dispatch. There is inherent risk involved in depending entirely on external resources – over which Minnesota Power has no control or influence in the long-term planning of – for essential reliability services such as system strength and voltage support that directly impact the reliability and operations of Minnesota Power’s customers and protection systems. Therefore, some amount of local short circuit capability and voltage support is needed to provide a continuous, predictable, and redundant source to Minnesota Power’s system. Besides large local generators like the Boswell units, establishment of one or more new synchronous condensers on the Minnesota Power system would appear to provide the best option for maintaining a local source of short circuit capability. A synchronous condenser is essentially a generator that is driven by the transmission system rather than by a steam turbine or some other form of mechanical energy. Synchronous condensers require no fuel for continuous operation and produce only reactive power. Synchronous condensers are capable of providing voltage regulation during normal system operations as well as dynamic voltage response and fault current during system disturbances.   

Schedule:  Minnesota Power is presently evaluating options for synchronous condenser development and does not anticipate placing a synchronous condenser in service before 2023.

General Impacts:  The establishment of one or more synchronous condensers on Minnesota Power’s transmission system will provide necessary voltage support and system strength for Minnesota Power’s customers during times when no large dispatchable generators are online in Northern Minnesota. To the extent possible, new synchronous condensers will be located at existing facilities or, in the case of unit conversion, within an existing generation plant. In addition to making optimal use of existing facilities, the establishment of one or more synchronous condensers 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.


126 Line Asset Renewal

MPUC Tracking Number:  2021-NE-N22

Utility:  Minnesota Power (MP)

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.

Alternatives:

Transmission Alternatives

There are no reasonable alternatives that will address the asset renewal needs for the existing transmission line and substation components associated with 126 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 or substation equipment.

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.

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.


13 Line Rebuild

MPUC Tracking Number:  2021-NE-N23

Utility:  Minnesota Power (MP)

Project Description: The 13 Line Rebuild Project involves replacement of transmission line structures and conductor on the Cromwell – 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.

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.

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. In developing the scope for the 13 Line Rebuild Project, Minnesota Power also took into consideration reasonable enhancements that could be incorporated to improve operational performance and relaying for 13 Line.

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 2023.

General Impacts:  The 13 Line Rebuild Project will ensure that the existing Cromwell – 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.


Fond du Lac - Wrenshall

MPUC Tracking Number:  2021-NE-N24

Utility:  Great River Energy (GRE)

Project Description:  Build a new 115 kV transmission line from MP’s Wrenshall to GRE’s Fond du Lac substation and establish 115/69 kV transformation at Fond du Lac.

Need Driver:  GRE’s 69/46 kV Fond du Lac substation provides a back up to East Central Electric’s (ECE) Amnicon, Bardon, and Summit delivery points when the main source from Stinson is lost.  MP has eluded to removing the 23 Line that provides a 46 kV source to the Fond du Lac substation due to its ROW traverses Jay Cooke State Park which is very hilly and hard to access for maintenance and outage restoration.

Alternatives:

Transmission Alternatives

Rebuild 46 kV 23 Line (Bear Creek – Thomson H.E) that traverses Jay Cooke State Park with very rugged terrain.

Non-Wires Alternatives

This project is still being studied. Non-transmission alternatives will be studied and considered prior to project initiation.

Analysis: Building the Wrenshall – Fond du Lac 115 kV project will allow for MP to remove their 23 Line from the Jay Cooke State Park and provide a more robust solution going forward.

Schedule:  The project is planned to be in service by Nov 2029.

General Impacts:  The project will require approximately 5.1 miles of new 115 kV transmission line from the Wrenshall substation to the Fond du Lac 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 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.


Shamineau Lake

MPUC Tracking Number:  2021-NE-N25

Utility:  Great River Energy (GRE)

Project Description:  Crow Wing Power (CWP) has requested a new distribution substation, to be named Shamineau Lake, that will be served by GRE’s “CW-MFT,” 115-kV line radially served from the 155 line (Dog Lake – Scearcyville). The interconnection to the “CW-MFT” line will be made via 3-way, load break, 2000-amp, transmission switch.

Need Driver:  The addition of regulators and capacitor banks was considered as a solution to allow for CWP to keep serving load from the Ward delivery point but it’s not a robust solution.  The regulators on the feeders from Ward have been working overtime to keep up with the 34.5kV voltage fluctuations.

Alternatives:

Transmission Alternatives

There is no other high voltage transmission line within 10 miles of the Shamineau Lake area load pocket making it extremely expensive and not practical to bring a line from another source.

Non-Wires Alternatives

Distribution driven project for capacity need.

Analysis: CWP has been utilizing a circuit from Todd-Wadena from the Ward substation to serve their Shamineau Lake load pocket which is 6 miles out of CWP’s service territory making it hard to maintain proper end-of-the-line voltage after load has grown over the years. CWP has deployed as much voltage regulation as possible and have now requested a new distribution substation closer to the load pocket to provide better voltage to their customers.

Schedule:  The project is planned to be in service by October 2022. 

General Impacts:  The project will require approximately 0.1 miles of new 115 kV transmission line from “CW-MFT” 115 kV line to Shamineau 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.


Wing River 230 kV Ring Bus

MPUC Tracking Number:  2021-NE-N26

Utility:  Great River Energy (GRE)

Project Description:  Reconstruct the Wing River 230 kV bus to ring bus configuration.

Need Driver:  Age and condition necessitates reconstruction of the Wing River 230 kV bus.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

Schedule:  The project is planned to be in service by April 2022. 

General Impacts:  This project is located on GRE owned property. 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.


Riverton – Wing River Storm Structures

MPUC Tracking Number:  2021-NE-N27

Utility:  Great River Energy (GRE)

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

None.

Non-Wires Alternatives

This a reliability improvement to an existing line to prevent cascading structure failure and no alternatives were considered.

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

Schedule:  The project is planned to be in service by November 2023. 

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.


6.4.2 Completed Projects

The table below identifies those projects by Tracking Number in the Northeast Zone that were listed as ongoing projects in the 2019 Biennial Report but have been completed or withdrawn since the 2019 Report was filed with the Minnesota Public Utilities Commission in October 2019. 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 2019 Report are not repeated here, but more information about those projects can be found in these earlier reports.


MPUC Tracking Number

Description

MPUC Docket

Utility

Date Completed

2007-NE-N6

Onigum Area

Not Required

GRE

Moved to study

2011-NE-N2

15 Line Upgrade

Not Required

MP

2019

2011-NE-N12

Wrenshall Substation

Not Required

MP

Cancelled

2013-NE-N13

Great Northern Transmission Line

CN-12-1163
TL-14-21

MP

2020

2013-NE-N22

Elisha 115/34.5 kV Project

Not Required

GRE

2021

2015-NE-N2

868 Line Upgrade

Not Required

MP

2021

2015-NE-N5

16 Line Relocation

TL-14-977

MP

2020

2015-NE-N16

Two Inlets Pumping Station (X1A)

Not Required

GRE

2021

2015-NE-N17

Backus Pumping Station
(X2A)

Not Required

GRE

2021

2015-NE-N18

Swatara Pumping Station (X3A)

Not Required

GRE

2021

2015-NE-N19

Hingley Pumping Station (X4A)

Not Required

GRE

2021

2017-NE-N4

Nashwauk 14 Line Upgrade

Not Required

MP

2019

2017-NE-N5

53 Line Upgrade

Not Required

MP

2019

2017-NE-N15

North Shore STATCOM

Not Required

MP

2019

2017-NE-N16

51 Line Upgrade

Not Required

MP

Cancelled

2017-NE-N22

Blackberry Breaker Replacements

Not Required

MP

2020

2017-NE-N25

Boswell 230 kV Fast-Switched Capacitor

Not Required

MP

Cancelled

2019-NE-N1

11 Line Upgrade

Not Required

MP

2020

2019-NE-N3

Hibbing 14 Line Upgrade

Not Required

MP

2021

2019-NE-N7

Savanna Transformer

Not Required

MP

2021

2019-NE-N9

Midway Substation Retirement

Not Required

MP

2019

2019-NE-N11

38 Line Upgrade

Not Required

MP

2020

2019-NE-N16

Forbes SVC Retirement

Not Required

XEL

2020

2019-NE-N17

Running Cap Bank Retirement

Not Required

XEL

2020

   

6.5    West Central Zone

6.5.1  Needed Projects

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.

MPUC Tracking Number

MISO Project Name

MTEP Year/
App

MTEP Project Number

CON?

Non-Wire Alt.

Utility

2009-WC-N6

Elk River-Becker Area

2012/C

2691

No

Yes

GRE

2015-WC-N3

Ortonville 115/41.6 kV Transformer

2015/B

4236

No

No

OTP

2019-WC-N1

Litchfield 69kV LT Tap Line

NA

NA

No

No

SMP

2019-WC-N3

Morris-Johnson Jct.-Ortonville J493/J526 Upgrade

2019/A

17006

No

No

MRES/
GRE/OTP

2019-WC-N4

Westwood 1 115 kV Conversion

2020/A

17971

No

No

GRE

2021-WC-N1

Black Oak – Sauk Centre 69 kV Rebuild

2021/A

19889

No

No

XEL

2021-WC-N2

Minnesota Valley TR12 ELR

2021/A

19886

No

No

XEL

2021-WC-N3

Watkins – Kimball Line Rebuild

2021/A

19890

No

No

XEL

2021-WC-N4

Howard Lake to Big Swan, Delano to Howard Lake, Cokato to Winstead Rebuild

2021/A

19913

No

No

XEL

2021-WC-N5

Panther – Big Swan Rebuild

2021/A

20135

No

No

XEL

2021-WC-N6

Appleton – Benson 115 kV Line

2021/A

20148

Yes

No

GRE/
OTP/MRES

2021-WC-N7

Granite Falls - Willmar (WB) Line Upgrade

2022/A

20707

No

No

GRE

2021-WC-N8

Big Swan Breaker Addition

2022/A

20165

No

No

GRE

2021-WC-N9

Kerkhoven 115 kV Breaker Additions

Future

TBD

No

No

GRE

2021-WC-N10

Walden 115 kV Breaker Addition

Future

TBD

No

No

GRE

2021-WC-N11

Benson – Morris Storm Structures

2022/A

21823

No

No

GRE


Elk River-Becker Area

MPUC Tracking Number:  2009-WC-N6

Utilities:  Great River Energy (GRE)

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.


Ortonville 115/41.6 kV Transformer

MPUC Tracking Number: 2015-WC-N3

Utility:  Otter Tail Power Company (OTP)

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.

Alternatives:  With the most recent load forecasts, this project is not presently planned for construction. Alternatives may be considered if or when loads drive the need for this project.

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.


Litchfield 69 kV LT Tap Line

MPUC Tracking Number:  2019-WC-N1

Utility:  Southern Minnesota Municipal Power Agency (SMP)

Project Description:  Rebuild SMMPA’s existing 69 kV LT tap line from the GRE DS Line to the Litchfield Substation to 115 kV standard with 795 ACSR conductor for continued operation at 69 kV.

Need Driver:  This project is motivated by the GRE rebuild of the DS line to a 115 kV standard. See project 2017-WC-N5 for more information.

Alternatives:

Transmission Alternatives

The line rebuild will provide increased load serving capability to Litchfield as well as increased reliability in the area.

Non-Wires Alternatives

None.

Analysis:  If GRE proceeds with their decision to rebuild this area to a 115 kV standard, SMMPA will have no choice but to upgrade this line to the same standard. Therefore, there are no non-wires alternatives to consider for SMMPA.

Schedule:  The schedule is currently unknown. See project 2017-WC-N5. 

General Impact:  The line will be rebuilt on existing right-of-way and will have little impact on landowners.


Morris-Johnson Jct.-Ortonville J493/J526 Upgrade

MPUC Tracking Number:  2019-WC-N3

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

Project Description:  This project consists of upgrades to the GRE/MRES/OTP owned Ortonville to Morris 115 kV transmission line to accommodate the interconnection of wind generators, J493/J526. These facilities consist of:

1. Ortonville to Johnson Jct. 115 kV line
2. Ortonville Substation
3. Morris to Johnson Jct. 115 kV line

Need Driver:  Network Upgrades to the Transmission Owner’s transmission line required for the interconnection of the Interconnection Customers’ Project J493/J526.

Alternatives: 

Transmission Alternatives

Building additional 345 kV lines at a higher cost.

Non-Wires Alternatives

This is an uprate of an existing line, required for generation outlet for MISO interconnection projects J493 and J526. Any non-wires alternatives would not provide sufficient outlet capability for these interconnection projects.

Analysis: The Morris – Johnson Jct. – Ortonville 115 kV line upgrade is needed to accommodate the wind generation outlet of the MISO J493 & J526 projects.

Schedule:  The project is planned to be in service by spring 2022. 

General Impacts:  The project will be constructed on an existing 100-foot right-of-way that is largely located on agricultural lands. No new landowners will be impacted by construction, although some additional temporary workspace may be required. GRE/MRES/OTP have 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 24 months. During this time, GRE/MRES/OTP 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.


Westwood 1 115 kV Conversion

MPUC Tracking Number:  2019-WC-N4

Utility:  Great River Energy (GRE)

Project Description:  Convert the Westwood 1 substation to 115 kV service.

Need Driver:  Improve service reliability to Westwood 1, LeSauk and Five Points distribution substations. Abide by existing agreement with MP to limit the number of substations between breaker stations at a maximum of three. 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.

Alternatives: 

Transmission Alternatives

The alternative to abiding by existing agreement with MP is to install a 115 kV breaker station at St. Stephen. While it is costly, it would not provide the redundancy that the project provides to Westwood 1, LeSauk and Five Points substations.

Non-Wires Alternatives

GRE is replacing existing wires to transition two substations from radial service to a looped service.  An NWA was not considered for this alternative as the corridor is existing and the desire for better reliability to the loads impacted.

Analysis:  Westwood 1 conversion will also utilize the 115 kV transmission line that Westwood 2 is connected to this could result in losing both Westwood 1 and Westwood 2 substations at the same time. Therefore, the project described in the description is the best value plan for the system.

Schedule:  The project is planned to be in service by fall 2023. 

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.


Black Oak – Sauk Center 69 kV Rebuild

MPUC Tracking Number:  2021-WC-N1

Utility:  Xcel Energy (XEL)

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.

Alternatives: 

Transmission Alternatives

The alternative option for this project is to perform maintenance and refurb on the line without upgrading the conductor. However, this option would still result in thermal overloads caused by N-1 contingencies.

Non-Wires Alternatives

None as this is an age and condition project of an existing line.

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

Schedule:  The project is planned to be in service by June 1, 2024. 

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.


Minnesota Valley TR12 ELR

MPUC Tracking Number:  2021-WC-N2

Utility:  Xcel Energy (XEL)

Project Description:  Like for like replacement of Minnesota Valley TR12. Transformer is 68 years old and is experiencing performance issues.

Need Driver:  Transformer is 68 years old and has indications of some overheating issues, moisture, bad joints, and active thermal degradation.

Alternatives: 

Transmission Alternatives

Keep old transformer. Not replacing would result in more frequent and long term outages.

Non-Wires Alternatives

None as this is replacing an existing transformer.

Analysis:  Like for like transformer replacement will have minimal impacts to existing system performance.

Schedule:  The project is planned to be in service by December 15, 2021. 

General Impacts:  Like for like transformer replacement will have minimal impacts to existing system performance and footprint.


Watkins - Kimball Line Rebuild

MPUC Tracking Number:  2021-WC-N3

Utility:  Xcel Energy (XEL)

Project Description:  Rebuild and upgrade approximately 6.56 miles of existing line. Replace EOL switches and MODs.

Need Driver:  83 year old poles. Age and condition do not support repairs. Load growth requires upgrade of small conductor. Potential for increased outage frequency and duration. Failure could provide risk to public.

Alternatives: 

Transmission Alternatives

Do nothing. Not replacing would result in more frequent and long term outages.

Non-Wires Alternatives

None, this is an age and condition replacement of an existing line.

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

Schedule:  The project is planned to be in service by December 15, 2022. 

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.


Howard Lake to Big Swan, Delano to Howard Lake, Cokato to Winstead Rebuild

MPUC Tracking Number:  2021-WC-N4

Utility:  Xcel Energy (XEL)

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.

Alternatives: 

Transmission Alternatives

Do nothing. Not replacing would result in more frequent and long term outages.

Non-Wires Alternatives

None, this is an age and condition replacement of existing lines.

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

Schedule:  The project is planned to be in service by June 15, 2024. 

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.


Panther – Big Swan Rebuild

MPUC Tracking Number:  2021-WC-N5

Utility:  Xcel Energy (XEL)

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.

Alternatives: 

Transmission Alternatives

Partial rebuild of identified line segments or progressive end of life replacements as failures occur. These options would cause increased time, cost, and line outages as well as not address the system performance reliability.

Non-Wires Alternatives

None.

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.

Schedule:  The project is planned to be in service by December 31, 2026. 

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.


Appleton – Benson 115 kV Line

MPUC Tracking Number:  2021-WC-N6

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

Project Description:  Construct approximately 27 miles of 115 kV transmission line from the MRES Appleton substation to GRE Benson substation. Convert 2 GRE and 3 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:  Improve local area load serving and future load growth. Address low voltage issues during N-2 contingencies that lead to voltage collapse.

Alternatives:

Transmission Alternatives

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

Non-Wires Alternatives

Both technical and economic analysis proves that the NTA solution is not viable for the Benson area. In addition to that, the technical solution shows that NTA 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 lowest cost solution.

Schedule:  The project is planned to be in service by May 2025. 

General Impacts:  The project will require approximately 27 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.


Granite Falls - Willmar (WB) Line Upgrade

MPUC Tracking Number:  2021-WC-N7

Utility:  Great River Energy (GRE)

Project Description:  Increase the line rating by replacing 10 poles.

Need Driver:  In MISO’s TPL-001-4 study for MTEP20, thermal violations on the Granite Fall-Willmar 230 kV line were identified for a NERC category P6 contingency (loss of transmission element, followed by system adjustments, followed by loss of another transmission element) in the 2025SH90 and 2025SLL90 models (shoulder and light load models with wind dispatched at 90% of nameplate). GRE’s identified Corrective Action Plan for the violation is a re-temp of the WB line to 212 deg. F.

Alternatives:

Transmission Alternatives

While system re-dispatch is allowed for NERC category P6 contingencies, the amount of generator re-dispatch required to mitigate this overload (over 2 GW) is not a realistic Corrective Action Plan.

Non-Wires Alternatives

This a minor upgrade to an existing line and no alternatives were considered.

Analysis:  Not doing the project risks non-compliance with NERC standard TPL-001-4.

Schedule:  The project is planned to be in service by January 2025. 

General Impacts:  The project will be constructed on the existing 230 kV transmission line from Granite Falls substation to Willmar 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.


Big Swan 115 kV Breaker Addition

MPUC Tracking Number:  2021-WC-N8

Utility:  Great River Energy (GRE)

Project Description:  Add a 115 kV line breaker at the Big Swan substation

Need Driver:  Prevent line faults from tripping off entire substation.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

Schedule:  The project is planned to be in service by November 2022. 

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.


Kerkhoven 115 kV Breaker Addition

MPUC Tracking Number:  2021-WC-N9

Utility:  Great River Energy (GRE)

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

Need Driver:  Prevent line faults from tripping off entire substation.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

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

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.


Walden 115 kV Breaker Addition

MPUC Tracking Number:  2021-WC-N10

Utility:  Great River Energy (GRE)

Project Description:  Add 2 115 kV line breakers at the Walden substation.

Need Driver:  Prevent line faults from tripping off entire substation.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

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

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.


Benson – Morris Storm Structures

MPUC Tracking Number:  2021-WC-N11

Utility:  Great River Energy (GRE)

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.

Alternatives: 

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement to an existing line to prevent cascading structure failure and no alternatives were considered.

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

Schedule: The project is planned to be in service by November 2023. 

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.


6.5.2  Completed Projects

The table below identifies those projects by Tracking Number in the West Central Zone that were listed as ongoing projects in the 2019 Biennial Report but have been completed or withdrawn since the 2019 Report was filed with the Minnesota Public Utilities Commission in October 2019. 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 2019 Report are not repeated here, but more information about those projects can be found in these earlier reports.

MPUC Tracking Number

Description

MPUC Docket

Utility

Date Completed

2017-WC-N5

DS Line Rebuild Project

None

GRE

Original Project Withdrawn

2019-WC-N2

Howard Lake-Maple Lake 115 kV Rebuild

None

GRE

Original Project Withdrawn

   

6.6    Twin Cities Zone

6.6.1  Needed Projects

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

2017-TC-N1

Airport-Rogers Lake 115 kV Rebuild

2016/B>A

10074

No

No

XEL

2021-TC-N1

High Bridge-Rogers Lake Bifurcation to Double Circuit

2021/A

19914

No

No

XEL

2021-TC-N2

Elm Creek TR4

2021/A

19892

No

No

XEL

2021-TC-N3

Barnes Grove Interconnection

2021/A

19905

No

No

XEL

2021-TC-N4

South Dayton Substation

2022/A

21829

No

No

GRE

2021-TC-N5

Lawndale – Bass Lake 115 kV Line

2015/A

7912

No

No

GRE

2021-TC-N6

Rush City 230 kV Ring Bus

Future

TBD

No

No

GRE

2021-TC-N7

Bunker Lake 345 kV Ring Bus

Future

TBD

No

No

GRE

2021-TC-N8

Medina Breaker Addition

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

Airport-Rogers Lake 115 kV Rebuild

MPUC Tracking Number: 2017-TC-N1

Utility:  Xcel Energy (XEL)

Project Description:  Rebuild the exi sting Airport to Rogers Lake 115 kV line due to age and condition.

Need Driver:  The existing Airport to Rogers Lake 115 kV line structures have reached end of life and need to be replaced. The line will be rebuilt using the same right of way.

Alternatives: 

Transmission Alternatives

An alternative to rebuilding the existing 115 kV line would be to construct a new 115 kV line in the area to replace the existing line. However, this line needs to connect to substations in a congested metro area and connects directly to the Minneapolis-St. Paul International Airport. It was determined that rebuilding the line in place was the best alternative.

Non-Wires Alternatives

None, this is an age and condition replacement of existing line.

Analysis:  Nearly 70% of the existing structures are overloaded and in failure mode.

Schedule:  The project is planned to be in-service by December 2021.

General Impacts:  This project will be constructed on ~3.2 miles of existing right of way that is located in the Twin Cities metro area. No new landowners will be impacted by this project. Xcel Energy performed a preliminary review of the route shows that the existing line crossed the Mississippi River, close to multiple lakes, two cemeteries, three highways, and an interstate crossing. The company will work with all appropriate agencies during the permitting phase of the project. 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.  


High Bridge-Rogers Lake Bifurcation to Double Circuit

MPUC Tracking Number: 2021-TC-N1

Utility:  Xcel Energy (XEL)

Project Description:  Convert the bifurcated 115 kV line from High Bridge to Rogers Lake to a double circuit 115 kV line to alleviate curtailment on the High Bridge Generating Plant. Construct new breaker positions at High Bridge and Rogers Lake to accommodate the second 115 kV circuit.

Need Driver:  Relieve congestion issues historically seen at the High Bridge 115 kV substation.

Alternatives: 

Transmission Alternatives

Do nothing, continue having congestion at High Bridge due to N-1 contingencies.

Non-Wires Alternatives

None.

Analysis:  This project splits a bifurcated line into two separate lines and will remove the need to curtail generation at High Bridge due to an N-1 outage.

Schedule:  The project is planned to be in service by May 1, 2023.

General Impacts:  This project will remove the bifurcation ties at both ends of the High Bridge – Rogers Lake 115 kV line and add breaker positions at both substations.


Elm Creek TR4

MPUC Tracking Number: 2021-TC-N2

Utility:  Xcel Energy (XEL)

Project Description:  Install Elm Creek TR4 at 115 kV/34.5 kV with one new 34.5 kV feeders exiting the substation to remediate N-1 overloads and allow proposed new customer load.

Need Driver:  Extended outage duration under Transformer N-1 contingency to mitigate overloads. New customer load interconnecting to substation.

Alternatives: 

Transmission Alternatives

Offload surrounding 34.5 kV feeders to reduce N-1 risk or build a new substation to increase area capacity.

Non-Wires Alternatives

None.

Analysis:  Due to increasing load on the surrounding 34.5 kV feeders, the Elm Creek TR2 34.5 kV transformer can no longer find sufficient load relief through feeder load transfers. For this reason, the N-1 risk on Elm Creek TR2 has dramatically increased (the entire load of the transformer) marking it as a high consequence risk. The best mitigation for addressing this risk is the installation a new 34.5 kV transformer and feeders which will immediately solve the high transformer risk, as well as alleviate pressure from the surrounding 34.5 kV feeders.

Schedule:  The project is planned to be in service by December 15, 2021.

General Impacts:  Transformer addition will have minimal impacts to existing system performance and footprint.


Barnes Grove Interconnection

MPUC Tracking Number: 2021-TC-N3

Utility:  Xcel Energy (XEL)

Project Description:  Install 3-way switch on 69 kV line between Inver Grove - Keagan Lake Tap to accommodate GRE’s new Barnes Grove interconnection (MTEP 2589).

Need Driver:  GRE interconnecting new Barnes Grove substation to serve new customer load.

Alternatives: 

Transmission Alternatives

No alternatives were considered; GRE’s Coop has been planning on building a 69 kV substation on this property for 10+ years. The site has been graded since 2009.

Non-Wires Alternatives

Distribution driven project for capacity need.

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.

Schedule:  The project’s in-service date was March 31, 2021.

General Impacts:  New interconnection will have minimal impacts to existing system performance and footprint.


South Dayton

MPUC Tracking Number:  2021-TC-N4

Utility:  Great River Energy (GRE)

Project Description:  Construct the new Connexus Energy (CE) South Dayton 115 kV in-and-out distribution substation in the Xcel 5522 line.

Need Driver:  Accommodate local area load growth.

Alternatives:

Transmission Alternatives

Add second transformer at the CE Hennepin substation.

Non-Wires Alternatives

Distribution driven project for capacity need.

Analysis:  The new CE South Dayton substation is closer to load growth areas than the CE Hennepin substation.

Schedule:  The project is planned to be in service by May 2023. 

General Impacts:  The project will require approximately 0.10 miles of new 115 kV transmission line from the Xcel 5522 115 kV line to South Dayton 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.


Lawndale – Bass Lake 115 kV Line

MPUC Tracking Number:  2021-TC-N5

Utility:  Great River Energy (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:  Accommodate existing and future local area load growth.

Alternatives:

Transmission Alternatives

Build Lawndale #2 as 69 kV service.

Non-Wires Alternatives

This project is still being studied.  Non-transmission alternatives will be studied and considered prior to project initiation.

Analysis:  Adding an alternate 115kV 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.

Schedule:  The project is planned to be in service by November 2024. 

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.


Rush City 230 kV Ring Bus

MPUC Tracking Number:  2021-TC-N6

Utility:  Great River Energy (GRE)

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:  Overloads during NERC TPL-001-4 P6 events. Age and condition.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

Schedule:  The project is planned to be in service by January 2024. 

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.


Bunker Lake 345 kV Ring Bus

MPUC Tracking Number:  2021-TC-N7

Utility:  Great River Energy (GRE)

Project Description:  Build Bunker Lake 345 kV ring bus.

Need Driver:  Deficient line switching for 345 kV lines.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

Schedule:  The project is planned to be in service by Summer 2030. 

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.


Medina Breaker Addition

MPUC Tracking Number:  2021-TC-N8

Utility:  Great River Energy (GRE)

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.

Need Driver:  A fault on the Crow River – Medina 115 kV line trips the entire substation. A fault on the Medina 115/69 kV transformer trips the entire substation.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

Schedule:  The project is planned to be in service by Summer 2033. 

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.


Parkwood 115 kV Ring Bus Expansion

MPUC Tracking Number:  2021-TC-N9

Utility:  Great River Energy (GRE)

Project Description:  Rebuild the 115 kV bus at Parkwood substation as a ring bus.

Need Driver:  Overloads during NERC TPL-001-4 P6 events. A 115 kV fault trips the entire substation.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement at the substation and no alternatives were considered.

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

Schedule:  The project is planned to be in service by June 2024. 

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.


Bunker Lake - Elk River Storm Structures

MPUC Tracking Number:  2021-TC-N10

Utility:  Great River Energy (GRE)

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.

Alternatives:

Transmission Alternatives

None.

Non-Wires Alternatives

This a reliability improvement to an existing line to prevent cascading structure failure and no alternatives were considered.

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

Schedule:  The project is planned to be in service by June 2024. 

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.


6.6.2     Completed Projects

The table below identifies those projects by Tracking Number in the Twin Cities Zone that were listed as ongoing projects in the 2019 Biennial Report but have been completed or withdrawn since the 2019 Report was filed with the Public Utilities Commission in October 2019. 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 2019 Report are not repeated here, but more information about those projects can be found in these earlier reports.

MPUC Tracking Number

Description

MPUC Docket

Utility

Date Completed

2017-TC-N4

Black Dog-Wilson 115 kV Upgrade

 

XEL

04/30/2021

2017-TC-N5

Wilson Substation

 

XEL

12/21/2020

2017-TC-N6

Plymouth Area Power Upgrade

12-113

XEL

10/30/2018

2017-TC-N7

Lebanon Hills 115 kV

Not Required

GRE

2020

2019-TC-N2

South Afton Substation

 

XEL

05/29/2021

2019-TC-N1

Red Rock Transformer Replacement

 

XEL

Cancelled

2019-TC-N3

East Metro Area Upgrades

 

XEL

Cancelled

2021-TC-N3

Barnes Grove Interconnection

 

XEL

03/31/2021

   

6.7   Southwest Zone

6.7.1  Needed Projects

The following table provides a list of transmission needs identified in the Southwest 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-Wire Alt.

Utility

2013-SW-N1

Heron Lake 161 kV Substation Rebuild

2012/A

3528

No

Yes

ITCM

2015-SW-N3

Buffalo Ridge Cutover

2015/A

8017

No

No

XEL

2017-SW-N1

Summit to Dovray 69 kV Rebuild

2016/A

9907

No

No

ITCM

2017-SW-N2

Dovray to Fulda 69 kV Rebuild

2016/A

9908

No

No

ITCM

2017-SW-N3

Fulda to Heron Lake 69 kV Rebuild

2016/A

9910

No

No

ITCM

2021-SW-N1

Fieldon Retirement

2021/A

19165

No

No

XEL

2021-SW-N2

Worthington Area Projects

2022/A

GRE:22030/ ITCM:21929/ MRES:20608

No

No

GRE/ITCM/MRES

2021-SW-N3

Luverne to Trosky 69 kV Rebuild

N/A

N/A

No

No

L&O


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 & MRES, ITC Midwest has revised and reduced the scope of the Heron Lake 161 kV project. In the updated configuration, the capacitor banks are no longer needed and the 161 kV configuration changes from a breaker-and-a-half to a ring bus.

Alternatives: 

Transmission Alternatives

The capacitor bank were re-evaluated during the ad hoc study and it was determined to 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 four 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.
 


Summit to Dovray 69 kV Rebuild

MPUC Tracking Number:  2017-SE-N1

Utility:  ITC Midwest (ITCM)
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 2024.

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.


Dovray to Fulda Junction 69 kV Rebuild

MPUC Tracking Number:  2017-SE-N2

Utility:  ITC Midwest (ITCM)
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 2025.

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.


Fulda Junction to Heron Lake 69 kV Rebuild

MPUC Tracking Number:  2017-SE-N3

Utility:  ITC Midwest (ITCM)

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 2019.

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

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.


Fieldon Retirement

MPUC Tracking Number:  2021-SW-N1

Utility:  Xcel Energy (XEL)

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.
Schedule:  This project is expected to be completed in July 2022.

General Impacts:  Retirement of the Fieldon substation.


Worthington Area Projects

MPUC Tracking Number:  2021-SW-N2

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

Project Description:  Construct the Lakefield Corners 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 Lakefield Corners 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. 

Alternatives:

Transmission Alternatives

      1. Nobles County to Worthington 115 kV Loop
      2. Build a 69 kV line from Lakefield Junction to West Lakefield and from West Lakefield to Worthington (Lorain).
      3. Rost 161/69 kV substation with Rost Located at intersection of ITCM’s 161 kV and GRE’s FE-RJ 69 kV line, along with 69 kV line from Worthington to GRE’s FE-RH line.

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 verifid 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.

Schedule:  The project is planned to be in service by November 2027. 

General Impacts:  The project will require approximately 6.5 miles of new 161 kV transmission line from Lakefield Corners 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.


Luverne to Trosky 69 kV Rebuild

MPUC Tracking Number:  2021-SW-N3
 
Utility:  L&O Power Cooperative (L&O)

Project Description:  The 16.6 miles-long Luverne to Trosky 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:  Initial rebuild of the line is expected to commence in 2022.
 
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.


6.7.2 Completed Projects

The table below identifies those projects by Tracking Number in the Southwest Zone that were listed as ongoing projects in the 2019 Biennial Report but have been completed or withdrawn since the 2019 Report was filed with the Minnesota Public Utilities Commission in October 2019. 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 2019 Report are not repeated here, but more information about those projects can be found in these earlier reports.

MPUC Tracking Number

Description

MPUC Docket

Utility

Date Completed

2015-SW-N3

Buffalo Ridge Cutover

 

XEL

Cancelled

2019-SW-N1

Lismore 115 kV Interconnection

Not Required

GRE

2021

2019-SW-N2

Rutland Substation 161kV Ring Bus Addition

NA

SMP

12/1/2019

   

6.8  Southeast Zone

6.8.1  Needed Projects

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.

MPUC Tracking Number

MISO Project Name

MTEP Year/App

MTEP Project Number

CON?

Non-Wire Alt.

Utility

2015-SE-N6

Waseca Junction to Montgomery 69 kV rebuild

2013/A

4101

No

No

ITCM

2015-SE-N7

Ellendale to Owatonna 69 kV Rebuild

2013/A

4108

No

No

ITCM

2017-SE-N1

Huntley to Wilmarth 345 kV MEP Project

2016/A

11883

Yes

Yes

XEL/ITCM

2017-SE-N3

Rochester-Wabaco 161 kV Rebuild

2018/A

16184

No

No

DPC

2019-SE-N2

Adams to Stewartville 69 kV Rebuild

2012/A

3630

No

No

ITCM

2019-SE-N3

J523 Generator Interconnection to Adams 161 kV

2020/A

TBD

No

No

ITCM

2019-SE-N4

Adams 161 kV Maintenance

2020/A

13879

No

No

ITCM

2019-SE-N5

Thisius 161/69kV Substation

2020/A

17968

No

Yes

ITCM

2021-SE-N1

Replace Green Isle Substation

2021/A

19891

No

No

XEL

2021-SE-N2

Northfield to Farmington Line Rebuild

2021/A

19888

No

No

XEL

2021-SE-N3

Hayward 161/69 kV Transformer Replacement

2022/Target A

21935

No

No

ITCM


Waseca Junction to Montgomery 69 kV Rebuild

MPUC Tracking Number:  2015-SE-N6

Utility:  ITC Midwest (ITCM)
Project Description:  The 29.6 mile-long Waseca Junction to Montgomery 69 kV line will be reconstructed on the existing right of way. 

Need Driver:  This 69 kV line was built in 1946 and increased maintenance costs have required that this line be rebuilt due to 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 Waseca Junction to Montgomery 69kV circuit

Analysis:  The plan to replace the approximately 70-year-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.  
Schedule:  Construction of the line is expected to be completed by the end of 2021.

General Impacts: The line is near the end of its useful life. The line will be reconstructed on the 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 line rebuild will increase the reliability of the electric system in the area.


Ellendale to West Owatonna 69 kV Rebuild

MPUC Tracking Number:  2015-SE-N7

Utility:  ITC Midwest (ITCM)

Project Description:  The 13.2 miles-long Ellendale to West Owatonna 69 kV line will be reconstructed on the existing right of way. 

Need Driver:  This 69 kV line is a known, real-time system constraint. The line is also nearing the end of its useful life. 

Alternatives:  
Transmission Alternatives
Replacement of the 69 kV transmission line with new poles, conductor and shield wire addresses a capacity constraint and provides for needed upgrade of the 50-year-old 69 kV line. 

Additional analysis is ongoing. The Ellendale to West Owatonna 69 kV has also been a source of system congestion due to area wind energy, and evaluation of a possible voltage conversion from 69 kV to 161 kV along a corridor from the Hayward or Freeborn 161 kV substations to Owatonna and other alternatives are also being evaluated in effort to better address possible future generation outlet and load-serving needs.
Non-Wires Alternatives
Non-wire alternatives are not viable because they cannot address concerns related to age and condition on the Ellendale to West Owatonna 69kV circuit.

Analysis:  Rebuilding the line to a greater capacity on existing right-of-way was the sole alternative considered to alleviate the system capacity constraint. 

Schedule:  The rebuild of the line is expected to be completed in 2022.

General Impacts:  Replacement of the line will provide for additional system capacity and reduce maintenance cost on the existing, aging infrastructure. It is expected that the line will be reconstructed 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 of the line will increase the reliability of the electric system in the area.


Huntley to Wilmarth 345 kV MEP Project

MPUC Tracking Number:  2017-SE-N1

Utilities:  Xcel Energy (XEL) & ITC Midwest (ITCM)

Project Description:  Construct new 345 kV circuit from the Wilmarth Substation to the Huntley Substation.

Need Driver:  This is a market efficiency project to relieve congestion on the Huntley to Blue Earth 161 kV line.

Alternatives: 
Transmission Alternatives
Several solutions such as rebuilding the South Bend to Blue Earth to Huntley 161 kV, a new Freeborn to West Owatonna 161 kV circuit, and a new Wilmarth to North Rochester 345 kV circuit were also studies to relieve the congestion observed.
Non-Wires Alternatives
None.

Analysis:  The Huntley to Wilmarth 345 kV project was found to alleviate the observed congestion at the Minnesota/Iowa border. The proposed project met the MISO present value cost to benefit ratio required for Market Efficiency projects. 

Schedule:  Planned in service date is end of 2021. A certificate of need and route permit were granted for this project in 2019.

General Impacts:  This project utilizes the existing Wilmarth and Huntley substations. Some additional new right-of-way was acquired to construct the new 345 kV circuit on the approved route, but approximately 40% of the line is being constructed as a double circuit with the existing Wilmarth-Lakefield Jct. 345 kV line. An Environmental Impact Statement was prepared for the project and is available on eDockets in MPUC Docket Nos. E002,ET-6675/CN-17-184 and TL-17-185. Unique environmental features were addressed to minimize environmental impacts that could occur during construction. Xcel worked with the appropriate permitting agencies to receive necessary approvals. Xcel contractors and personnel are contributing positively to the local economies. No significant traffic impacts are anticipated. 


Rochester-Wabaco 161 kV Rebuild

MPUC Tracking Number:  2017-SE-N3

Utility:  Dairyland Power Cooperative (DPC)

Project Description:  Rebuild 13.2 miles of 161 kV line between DPC’s Rochester and Wabaco transmission substations.  This project will increase the line’s capacity with upgraded conductor, switches and substation jumpers.

Need Driver:  This 161 kV line was identified as a limiting transmission congestion point as part of the MTEP18 assessment. The line shows a significant amount of congestion when other west-to-east lines at the interface of Minnesota and Wisconsin are out of service.

Alternatives: 
Transmission Alternatives
The ability for the existing structures to handle a larger conductor was reviewed. The existing structures would not be able to carry a larger conductor to achieve a higher capacity on this line. The MTEP18 transmission study reviewed three other solutions involving larger 345 kV lines, which did not pass the present value analysis due to very high costs.
Non-Wires Alternatives
None.

Analysis:  The project to replace the line with new poles, conductor and substation jumpers at the endpoints of the Rochester and Wabaco substations will alleviate the congestion issues as determined by MISO. Dairyland Power Cooperative has reached an agreement with a third party to fund the Rochester-Wabaco 161 kV Rebuild Project.

Schedule:  Construction is scheduled to occur October 2021 to March 2022.
General Impacts:  Dairyland construction crews will rebuild this line in 2021 into 2022 requiring approximately twenty-four weeks to construct. The upgraded line will reduce congestion on the transmission system.


Adams to Stewartville 69 kV Rebuild

MPUC Tracking Number:  2019-SE-N2

Utility:  ITC Midwest (ITCM)
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 69kV 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.

Schedule:  Initial rebuild of the line is expected to commence in 2023.

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.


J523 Generator Interconnection to Adams 161 kV

MPUC Tracking Number:  2019-SE-N3

Utility: ITC Midwest (ITCM)

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 reterminated 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.

Schedule:  The project will be placed in service in September of 2022.

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. 


Adams 161 kV Maintenance

MPUC Tracking Number:  2019-SE-N4

Utility: ITC Midwest (ITCM)

Project Description:  The Adams 161 kV currently has two generating facilities, 5-161 kV lines, a 161/69 kV transformer and a 345/161 kV transformer connected to the 161 kV bus in a straight bus configuration. The greater than 55 years old substation was initially designed with capability for the 161 kV bus to be converted to a breaker-and-1/2 configuration, and in conjunction with the interconnection of project J523, additional circuit breakers will be installed, and the 161 kV bus will be converted to a breaker-and-1/2 configuration. 

Need Driver:  The breaker-and-1/2 configuration will provide greater operational flexibility by avoiding generating facility outages and line outages otherwise required for maintenance, and it will increase system reliability by avoiding loss of multiple system elements in the event of a fault. The Adams 161 kV bus reconfiguration will also eliminate the overload of the Adams to Rose Wind 69 kV line for a breaker failure contingency of bus L2 at Adams 161 kV.

Alternatives: 
Transmission Alternatives
Rebuilding the Adams 161 kV substation near the existing facility would require significant line relocation and new equipment, and it was considered a too costly alternative.
Non-Wires Alternatives
Non-wire alternatives are not viable because they cannot address concerns related to age and condition at the Adams substation.

Analysis:  Reconfiguring the substation to a breaker-and-1/2 configuration in conjunction with the interconnection of project J523 will provide operational flexibility if performing system maintenance while also providing for increased system reliability. The operational flexibility also removes the need to reduce area generation in the event of a bus fault or breaker failure event at Adams 161 kV.
 
Schedule:  The project work will be coordinated with the work to interconnect project J523, which has a September 2022 in service date. It is expected that the Adams 161 kV maintenance work will be completed in the second quarter of 2022, prior to the in service date for J523.

General Impacts: Coordination with generating facilities’ owners, Xcel Energy and Dairyland Power Cooperative will be required for outages facilities construction. The upgrades will occur within the existing Adams 161 kV Substation. 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. 


Thisius 161/69 kV Substation

MPUC Tracking Number:  2019-SE-N5

Utility:  ITC Midwest (ITCM)

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 161/69kV 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.


Replace Green Isle Substation

MPUC Tracking Number:  2021-SE-N1

Utility:  Xcel Energy (XEL)

Project Description:  Replace existing Green Isle substation with a new 69/13.8 kV substation on a new site.

Need Driver:  The existing transformer TR1 has contingency risk following planned addition of industrial load. The existing substation is 4 kV and needs to be converted to conform with standards, and the existing site is not sized to fit the new design.

Alternatives: 
Transmission Alternatives
Increasing the transformer size would not conform with standard distribution voltage and substation yard constraints are a concern.
Non-Wires Alternatives
None, this is replacing an existing asset.

Analysis:  The existing transformer TR1 has contingency risk following planned addition of industrial load.

Schedule:  The work will take approximately one year to complete and use Xcel Energy employees. The required in-service date is subject to the timing of the industrial load growth.

General Impacts:  This project will require land for a new distribution substation.


Northfield to Farmington Line Rebuild

MPUC Tracking Number: 2021-SE-N2

Utility:  Xcel Energy (XEL)

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.

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.

Schedule:  The project is planned to be in service by December 15, 2022.

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


Hayward 161/69 kV Transformer Replacement

MPUC Tracking Number:  2021-SE-N3

Utility: ITC Midwest (ITCM)

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:  This project is pending submittal to MISO’s MTEP study but is expected to be included in the MTEP22 Study.

Schedule:  The in-service date for this project is by year end 2025.

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


6.8.2  Completed Projects

The table below identifies those projects by Tracking Number in the Southeast Zone that were listed as ongoing projects in the 2019 Biennial Report but have been completed or withdrawn since the 2019 Report was filed with the Minnesota Public Utilities Commission in October 2019. 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 2019 Report are not repeated here, but more information about those projects can be found in these earlier reports.

MPUC Tracking Number

Description

MPUC Docket

Utility

Date Completed

2011-SE-N5

Arlington-Green Isle 69 kV

 

XEL

11/21/2020

2015-SE-N4

Line 0714 Rebuild

 

XEL

12/15/2017

2017-SE-N6

J407 Generator Interconnection

N/A

ITCM

8/2020

2019-SE-N1

Cannon River Park Tap Line

Not Required

GRE

2021

2019-SE-N8

Blooming Prairie N86 69 kV Line Rebuild

NA

SMP

11/30/2020

2019-SE-N9

Preston N-22 69 kV Line Rebuild

NA

SMP

05/01/2020

2019-SE-N10

West Owatonna 161 kV Ring Bus Addition and Load Interconnection

NA

SMP

12/1/2019