Minnesota Electric Transmission Planning

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.

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

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.

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.

The third column contains a reference to a MISO Transmission Expansion Plan (MTEP) Report and an Appendix in the report. The MTEP Report is prepared annually by the Midcontinent Independent System Operator (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 MTEP17, 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.

The fourth column of the table provides a Project Number assigned by the Midcontinent Independent Transmission System Operator (MISO) for each project. This Project Number is important for finding a particular project in the appropriate MISO Transmission Expansion Plan (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), Hutchinson Utilities Commission (HUC), L&O Power Cooperative (L&O), Marshall Municipal Utilities (MMU), and Willmar Municipal Utilities (WMU), 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 assumed many of the planning functions for Minnkota Power Cooperative once the Mid-Continent Area Power Pool (MAPP) was dissolved in late 2015, resulting in the termination of MAPPCOR, the nonprofit organization that did the planning work for the MAPP utilities, including Minnkota. Minnkota does do some of its own planning though, as shown in table 6.3.1 where no MTEP Project Number is shown for some Minnkota projects.

The MPUC rules (Minn. Rules part 7848.1300, item M) state that the biennial report shall contain an approximate timeframe for filing a certificate of need application for any projects identified that are large enough to require a certificate of need. This column provides a simple "Yes" or "No" indication of whether a CON is required. If a certificate of need 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.

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.

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

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 Minnesota Public Utilities 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.

Because nearly all of the projects identified in this Report are being undertaken by utilities that are members of the Midcontinent Independent Transmission System Operator (MISO), this subsection is provided to assist the reader in finding information about the MISO planning process and the annual MISO Transmission Expansion Plan (MTEP) Report that is prepared each year. Much of the information provided in this subsection was also available in the 2013 and 2015 Biennial Reports.

The MTEP process is ongoing at all times at MISO. Generally utilities submit a list of their newly proposed projects in September. MISO staff evaluates these projects over the next several months, and prepares a draft of the annual MTEP Report around July of the following year. After review by utilities and other interested parties, the MISO board of directors usually approves the report in December. The process continues with another report finalized the following December. The MTEP17 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:

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.

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 2017-TC-N5 is used for illustrative purposes):

MPUC Tracking Number 2017-TC-N5 is the Wilson Substation Project in Bloomington, MN. The project can be found in Appendix A of the MTEP17 Report (the MTEP17 Report will be finalized in late 2017) by following these steps:

Similar steps can be followed for all other projects identified in Chapter 6, including those few that are not Appendix A projects (recommended by MISO for approval). If the MTEP Report you are seeking is an older one, probably earlier than 2011, you may have to click on Study Repositories to find these other reports at Step 2.

Appendices A, B and C 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.

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.

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 D1 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 D1 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 Wilson Substation, Tracking Number 2017-TC-N5, which is an approved Appendix A project, this additional information can be found by going to Appendix D1 through the following steps.

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.

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.

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 MTEP17.

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

Project Description: The Winger-Thief River Falls 230 kV Line Project consists of a Winger substation expansion, a Thief River Falls substation expansion, a new 47 mile 230 kV transmission line between Winger and Thief River Falls and a new 230/115 kV transformer at Thief River Falls.

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:

The options above have been considered and compared with a new Winger-Thief River Falls 230 kV line (and the associated Thief River Substation), and it was determined that the benefits of such a project are more robust and cost effective than the other options that were considered.

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 2024. 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 is expected to be completed by early 2018 to determine a more definitive mitigation plan and schedule. Upon completion of this study, Certificate of Need and other filing processes can begin.

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.

Project Description: Voltage problems in the Frazee area are planned to be addressed by the addition of a new Schuster Lake 115/41.6 kV Substation near Frazee in Otter Tail County to support the 41.6 kV system in this area.

Need Driver: This area is served by two 115/41.6 kV sources from Frazee and Rush Lake. The loss of the Frazee 115/41.6 kV transformer or Frazee to Perham 41.6 kV line causes low voltage issues at multiple substations in the area including LREC’s Dent and Dora distribution substations.

There are eight GRE-LREC distribution substations and four OTP distribution substations served in the area between Frazee and Rush Lake. The loss the Frazee 115/41.6 kV transformer causes low voltage problems at the Dora and Dent distribution substation.

Alternatives: Leaving the transmission system in the Frazee to Rush Lake area as it is now presents severe undervoltage problems at LREC’s distribution substation. The transmission line overload problems will continue to be critical in the area. Two other alternatives were considered to address the voltage and loading issues in the area. One of the alternatives recommends adding a second transformer at Frazee and rebuilding the 9 mile, 2/0 A Tap line to Dent Sub with 477 ACSR conductor. The other alternative converts 41.6 kV loads to 115 kV system in the near term and establishes a 115/41.6 kV source at the North Perham Junction in the long term. These alternatives were not found being the least cost plan to address the needs of the area for a long term.

Analysis: The Shuster Lake Substation, at system intact, will serve the Dent and Perham loads which are now served from the Frazee and Rush Lake sources, respectively. The project is the least cost plan that will address the low voltage problems in the 41.6 kV system during critical contingencies in the system, the loss of the Frazee 115/41.6 kV system and loss of the Frazee to Perham 41.6 kV line. It also ensures a better load serving reliability in the area as it will provide contingency back up to the Frazee and Rush Lake sources in the area while increasing capacity in the system to serve future load growth in the transmission system.

Schedule: The Schuster Lake Project is currently planned for a fall 2019 completion.

General Impacts: Installation of a new transformer at an existing substation is not expected to have any significant effects.

Clearbrook 115 kV-Bagley West 230 kV

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

Project Description: The name of this project has been changed slightly from the 2015 Report, when it was called Clearbrook West, simply to more accurately reflect the location of the project. This project is related, however, to the new 115 kV ring bus to be installed at the existing Bagley Junction switch. (Tracking Number 2015-NW-N3). The option selected from the Coordinated Clearbrook Looped Service Study (performed primarily by OTP) was to develop a substation near Bagley (about 4.5 miles southwest) that taps the Winger to Wilton 230 kV line, as well as a 22 mile line from the newly developed substation to the Clearbrook 115 kV Substation.

Need Driver: The Clearbrook 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 two 230 kV sources at Wilton and Winger. Loss of any one source forces the load to be served from a single source. Additionally, loss of any transmission between Bagley and Clearbrook threatens a substantial amount of existing and future load service. The proposed transmission facilities include a 22 mile transmission line and a new substation.

Alternatives: Several different transmission alternatives were developed as part of a Clearbrook Looped Service Study to assess the ability of the transmission system to serve the anticipated load increase for the Clearbrook area. These included:

The options above have been considered and compared with a new 230 kV / 115 kV tap line, and it was determined that the benefits of such a project heavily out-weight the added investment (determined in coordinated efforts that followed the initial report).

Analysis: The option selected from the Coordinated Clearbrook Looped Service Study was to develop a substation near Bagley (about 4.5 miles southwest) that taps the Winger to Wilton 230 kV line, as well as a 26 mile line from the newly developed substation to the Clearbrook 115 kV Substation. The newly developed substation, referred to as Bagley West, has a 230/115 kV transformer, breakers for the high and low side of the transformer, switches, relaying, and all other associated bus work. The Bagley West 230/115 kV transformer was identified as an equivalent replacement for the previously repurposed Wilton transformer #1 (OTP), with the recognition that the Wilton 230/115 kV transformer would have needed to be replaced.

Looped service for the Clearbrook area loads was evaluated in the “Coordinated Clearbrook Looped Service Study.” Of the options analyzed, the Clearbrook West 115 kV to Bagley West 230 kV option provided the best option to meet our transmission planning requirements. The study demonstrated a final upgrade requirement of looped service, to be completed by 2026.

Schedule: The study efforts mentioned above determined that an upgrade to mitigate post-contingent service issues on the Clearbrook area transmission must be completed by the winter of 2026. The project was listed as having an in-service date of 2018 in the previous report. This date has now been pushed out significantly because of the cancellation of proposed loads in the area. A schedule will be developed as definite mitigation plans are determined.

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 814 acres, only 69 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.

Project Description: The Donaldson 115 kV Breaker Project consists of adding a new 115 kV breaker at Donaldson on the Donaldson to Drayton 115 kV line to improve reliability of area loads.

Need Driver: The addition of a new breaker at the Donaldson 115 kV Substation on the Donaldson-Drayton 115 kV line will improve reliability in the area. This breaker will reduce fault exposure to Donaldson loads over 17 miles of transmission, improve operations, maintenance, and relaying flexibility at Donaldson.

Alternatives: Due to the low cost and benefits provided by the addition of the Donaldson breaker no other alternatives were considered.

Analysis: The addition of the breaker at Donaldson reduces fault exposure, improves operations and maintenance, and provides relaying flexibility at Donaldson. This breaker improves reliability to sensitive loads in the Donaldson area.

Schedule: The addition of the Donaldson 115 kV breaker is currently scheduled for December 2018. The July 2016 timeline listed in the previous report was pushed out to this 2018 date due to a lack of internal resources at OTP.

General Impacts: The addition of the Donaldson 115 kV breaker will reduce fault exposure to Donaldson while improving operations, maintenance and relaying flexibility at the Donaldson Substation. This project is the most cost-effective and environmentally responsible project to address the reliability concerns in the area.

Bagley North 115 kV Ring Bus

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

Project Description: The name of this project has been changed from the 2015 Report, when it was called the Clearbrook-Clearbrook West 115 kV line (Load Interconnect), in order to more accurately describe it and to distinguish it from Tracking Number 2015-NW-N1 (Clearbrook 115 kV-Bagley West 230 kV). A new 115 kV ring bus is planned at the existing Bagley Junction switch. This will reduce fault exposure for area loads and improve operations and maintenance flexibility in the area.

Need Driver: The Clearbrook area is a developing hub of crude oil pipelines, and those pipelines require pumping stations. The Clearbrook pumping station has a large amount of exposure due to a lack of breakers in the area. Adding this breaker station not only reduces exposure for the pumping station, but reduces exposure for other area loads as well as improving operations and maintenance flexibility.

Alternatives: Several different transmission alternatives were developed as part of a Clearbrook Looped Service Study developed primarily by Otter Tail Power to assess the ability of the transmission system to serve the anticipated load increase for the Clearbrook area. These included:

The options above have been considered and compared with a new 230 kV / 115 kV tap line and Bagley 115 kV Ring Bus option, and it was determined that the benefits of such a project heavily out-weigh the added investment (determined in coordinated efforts that followed the initial report). This breaker station was considered as part of that study.

General Impacts: The addition of the Bagley 115 kV breaker station will reduce fault exposure to Clearbrook by 50% while improving operations and maintenance flexibility along the Winger-Solway 115 kV transmission line. This project is the most cost-effective and environmentally responsible project to address the reliability concerns in the area.

The economic and social impacts from this project will likely be minimal. 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.

Moranville 230/69 kV Transformer Replacement

Project Description: To keep up with the customer’s growing demand, a new 230/69 kV transformer, along with the corresponding breakers, is planned for installation at the Moranville Substation.

Need Driver: Moranville area load is approaching the thermal limitations of the existing transformer. The existing transformer is also approaching its appropriate retirement age, and it has shown signs of slight deterioration.

Alternatives: There are two transformers at the Moranville Substation (comprised of two transformer pairs), however, thermal limitations on alternate service lines and the transformers prevent the current configuration from being fully effective during peak conditions following a contingency. An extensive uprate to the surrounding 69 kV system could serve as an alternative to the transformer replacement, but it would be a far more expensive approach to serving this load during a contingency. The transformer replacement is also a more robust and energy efficient option.

Analysis: There are not any negative reliability impacts due to the transformer and breaker replacements. This is primarily a capacity uprate.

Schedule: The study efforts mentioned above determined that the transformer replacement should be completed by the winter of 2017-2018. Delays have occurred due to budgeting and more important projects taking higher priority. The project is soon to be underway, and should be complete sometime fall 2017.

General Impacts: This project is entirely at the Moranville Substation location. There is no new transmission area for this project. No notable sites or locations are near the site of this project. This project is nearing construction, so all of these details are already approved in terms of impacts to the nearby area and environment.

This project will require a short-term project crew. This will bring some business to the area in the form of room and/or board. In terms of local government benefits, little is expected as a result of the substation modifications.

This project is the result of update requirements and capacity needs, and it will probably not have an impact on the community in terms of population or other social characteristics.

Ulrich 115/69 kV Transformer Replacement

Project Description: A new 115/69 kV transformer is being proposed for installation at the Ulrich Substation. Capacitors mentioned in the 2015 Report as part of this project are no longer required due to the Lake Park 230/69 kV Substation (Tracking Number 2017-NW-N1) providing sufficient support during outage of the Ulrich transformer.

Alternatives: There is a single transformer at Ulrich that serves two 69 kV transmission lines. These lines are well loaded under peak conditions, and alternate service is somewhat restricted to these transmission lines due to radial configuration or thermal limitations during peak conditions following a contingency. Ensuing load transfers also create some concerns during system intact conditions. A new 230/69 kV substation is being built nearby (Lake Park, MN) to provide some alternate service, see Tracking Number 2017-NW-N1, but there are still some thermal limitations. An extensive uprate to the surrounding 69 kV system or further load transfers could serve as an alternative to the transformer replacement, but uprates would be a far more expensive approach. Load transfers are being investigated as another project is being studied (near White Earth, MN). The transformer replacement is a robust and energy efficient option, and is preferred for now.

Analysis: There are not any negative reliability impacts due to the transformer replacement. This is primarily a capacity uprate.

Schedule: The study efforts mentioned above determined that the transformer replacement must be completed by the winter of 2019-2020, however, the ultimate schedule and scope of this project will be determined by the outcome of Tracking Number 2009-NW-N2. A schedule will be developed as that timeframe approaches.

General Impacts: This project is entirely at the Ulrich Substation location. There is no new transmission area for 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, little is expected as a result of the substation modifications.

This project is the result of update requirements and capacity needs, and it will probably not have an impact on the community in terms of population or other social characteristics.

Richwood-Oakland 69 and Audubon-Erie Junction 41.6 kV Lines (Load Transfers)

Project Description: Referred to as “Mahnomen/Ulrich Tap-Existing White Earth Substation 115 kV Line (Load Tap/Transfer)” in the 2015 Biennial Report. 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. The proposed project includes 20.0 miles of transmission line work (all new line).

A new 41.6 kV line from Audubon Distribution Substation to Erie Junction (with conversion of Audubon Distribution Substation onto the 41.6 kV system) has also been deemed necessary. The proposed project includes 4.0-7.5 miles of transmission line work (2.5 miles of it will be completely new). 1.5-5.0 miles of the transmission line work will be rebuilt transmission (1.5 miles will be double circuit). This will also require some substation expansion at the Ulrich 115/69/41.6 kV Substation.

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 Erie Substation. The intent is to transfer load off a neighboring system for primary service and continue to use the neighboring system for back-up service.

According to these requests, existing sources (via the neighboring system or distribution backfeeding) are insufficient for the customer’s demand during a contingency. As a result, new transmission has been deemed necessary. The proposed transmission facilities include a 24.0-27.5 miles of transmission line work (22.5 miles of it will be completely new), substation conversions (White Earth and Erie dist. substations), and expansion of the Ulrich 115/69/41.6 kV Substation.

Alternatives: There are several transmission alternatives being considered as part of these load transfers. In the 2015 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) and a neighboring system’s project near Audubon 230/115/41.6 kV Substation. Investigations are ongoing, and these alternatives will be compared with the proposed transmission line options. 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 TPL assessments (in terms of forecasting the existing White Earth and Erie area loads). 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. This will occur after final scope and schedule of the Frazee-Perham-Rush Lake Area (Tracking Number 2009-NW-N2) is finalized.

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 sites or locations are near the site of this project. 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 population or other social characteristics. It will likely impact some farmland; however, it should only amount to about 15 acres, as stated in the environmental considerations.

Thief River Falls 115 kV Capacitor Bank Addition

Project Description: An additional capacitor in the existing capacitor bank is being proposed for the Thief River Falls Substation. Due to the steady growth of area loads, some voltage support to the system has been deemed necessary. The proposed capacitor addition includes 14.96 MVAR of capacitors and any necessary modifications to the existing Thief River Falls Substation.

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. To sustain reliability in years leading to new transmission upgrades, a new capacitor bank addition is being proposed for the Thief River Falls Substation in cooperation with Otter Tail Power, as they have agreed to their own capacitor addition at Donaldson Substation. Tracking Number 2017-NW-N4.

Alternatives: In years prior to 2021, automatic undervoltage load shedding has been identified as the most cost effective mitigation for voltage violations following a contingency. However, new compliance standards come into effect after that time, and non-consequential load loss is no longer permitted. That led to the proposed capacitor bank additions at Thief River Falls (14.96 MVAR) and Donaldson (30.00 MVAR). This will sufficiently support the system until the in-service date of the Winger-Thief River Falls 230 kV line (winter of 2023-2024).

Analysis: Reliability improvements from the previously mentioned projects were evaluated in the “High Voltage Study,” which was performed by OTP with support from MPC. The study showed that a fault on and 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 a new 230 kV source at Thief River Falls to be completed by 2024. However, the timeframe between 2021 and 2023 required further mitigations for the loss of automatic undervoltage load shedding (per TPL-001-4). To mitigate the resulting voltage violations, Thief River Falls capacitor bank and Donaldson capacitor additions have been proposed (2019-2020).

Schedule: The study efforts mentioned above determined that an upgrade to mitigate post-contingent service issues to the Northwest Minnesota area transmission must be completed by the winter of 2023-2024. 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.” The date change is due to actual vs. projected load increases and recent changes to interpretations of NERC TPL standards. A schedule will be developed as definite mitigation plans are determined. A study effort will soon be underway to re-evaluate the Northwestern Minnesota load service and project options.

General Impacts: This project is entirely at the Thief River Falls Substation location. There is no new transmission area for 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 is the result of update requirements, and it will probably not have an impact on the community in terms of population or other social characteristics.

Lake Park Substation

Project Description: A new 230/69 kV substation is planned for construction near Lake Park, MN.

Need Driver: The Ulrich area load is approaching the thermal limitations of the existing transformer. In addition to the existing load topology, a couple of loads that are currently served by a neighboring utility will soon be transferred to the Ulrich source. The new substation is required to keep up with the changes in the demand near Hawley, MN and to provide alternate service to a radial transmission system.

Alternatives: There is a single transformer at Ulrich that serves two 69 kV transmission lines. These lines are well loaded under peak conditions, and alternate service is somewhat restricted to these transmission lines due to radial configuration or thermal limitations during peak conditions following a contingency. Ensuing load transfers also create some concerns during system intact conditions. An early alternative (to this new 230/69 kV substation being built at Lake Park) was a new 69 kV transmission line between Audubon and Hal Christensen distribution substations. This transmission line was going to provide some alternate service, but there would have still been some thermal limitations, for system intact and alternate service. An extensive uprate to the surrounding 69 kV system and a second transformer at Ulrich Substation could have been an alternative to this new Lake Park Substation, but the uprates and Ulrich Substation expansion would have been a more expensive approach. The Lake Park substation is a robust and energy efficient option, and will be in-service this winter.

Analysis: There are not any negative long-term reliability impacts due to the new substation. The only reliability issue is the short-term construction outage on radial transmission. Otherwise, it will provide more sources of power and higher capacity to Hawley, MN and the surrounding area.

Schedule: The alternate service issues and ensuing load transfers mentioned above determined that the substation was critical. The project is underway, and will be complete by winter 2017-2018.

General Impacts: This project is entirely at the new Lake Park Substation location (Section 30, Township139N, Range 43W, Becker County). There is no new transmission area required for this project. No notable sites or locations are near the site of this project. This project is nearing construction, so all of these details are already approved by the Rural Utility Service (RUS)—no impacts to the nearby area and environment.

This project is the result of alternate service and capacity needs, and it will probably not have an impact on the community in terms of population or other social characteristics.

Itasca-MPL Laporte 115 kV Line (and Northwoods Circuit Breaker Addition)

Project Description: The project consists of a new 9.4 mile-long 115 kV HVTL and 115/4.16 kV substation.

Need Driver: The Clearbrook and Itasca areas are developing hubs of crude oil pipelines, and those pipelines require pumping stations. A new pumping station is developing south of Itasca, and the existing transmission/distribution system is insufficient for the customer’s expected demand. As a result, a new load interconnection on the 115 kV system has been deemed necessary. The proposed interconnection facilities include a 9-mile transmission line and a new substation. As a result of the system impact study, a breaker addition at the existing Northwoods Substation (located roughly 25 miles north of the MPL Laporte site) is a required interconnection facility also.

Alternatives: There was really only one feasible option for this load interconnection, due to the absence of both transmission and distribution that would sufficiently serve a load of this size. The next most feasible option would have been an 18-mile line (twice the length of this project’s line) to Minnkota’s Nary 115 kV Substation.

Analysis: Due to the development of a new pump station load near Itasca, a new load service needed to be established. Since the forecast provided by the customer was beyond the availability of existing member distribution cooperative facilities, and there are no existing Minnkota transmission facilities near the site, the load service was specified for 115 kV. This required a new transmission line from a nearby 115 kV substation at Itasca (about 9 miles of line to the north), as well as a newly developed substation for service to the MPL Laporte pump station load. Since the 115 kV line and load are to be interconnected with a neighboring transmission system, a system impact study was done, and protection upgrades were necessary due to the extension of this radial 115 kV system. The miles of exposure on this radial 115 kV system was already around 18 miles (putting strain on the typical protection specifications used on a 115 kV loop). The additional 9 miles of radial exposure (total of 27 miles) would have made it difficult to coordinate proper breaker operation for faults that occur on the far outreaches of that radial system. To mitigate the issue, a breaker addition at the existing Northwoods Substation (about 25 miles north of the MPL Laporte pump station load site) was selected for facilitating the interconnection.

Schedule: The customer’s latest in-service date determined that the load interconnection must be completed by the winter of 2017-2018. The project is underway and will be completed by that time. A route permit was issued for the line by the Public Utilities Commission on June 21, 2017. MPUC Docket No. ET-6/Tl-16-327.

General Impacts: This project is primarily rural in location. The route will have to navigate around some lakes within the area. Assuming a one hundred foot right-of-way, the project area will be nearly 110 acres, but the affected farmland should only be about 6 acres, assuming some general estimates on electrical poles and farmland equipment navigation. The project follows around Itasca State Park, some nearby roads, and some farmsteads. It also has one crossing at La Salle Creek. This project is nearing approval and construction, so all of these details are already approved—no impacts to the nearby area and environment.

This project will require a temporary project crew. This will bring some business to the area in the form of room and board. In terms of local government benefits, permit costs have been enforced on this project, and that was determined by the scope of this project. Also, some landowners have received income as a result of this project, and the income will be taxable.

This project is the result of a new pump station development, but it will probably not have a substantial or lasting impact on the community in terms of population or other social characteristics. It will likely impact some farmland; however, it should only amount to about 6 acres, as stated in the environmental considerations.

Thief River Falls-Plummer Pipe 115 kV Line Uprate

Project Description: A capacity uprate is being proposed for the existing Thief River Falls-Plummer Pipe 115 kV line.

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. A specific contingency forces a heavy share of this load to be served from only one 115 kV line. Additionally, other contingencies involving the loss of two transmission facilities between Drayton and Grand Forks can also cause the same capacity issue. Due to the nature of the contingencies, non-consequential load loss is permissible.

Alternatives: The uprate is a relatively low-cost improvement, and is only questionable on the basis that such an improvement could be deferred with a temporary use of non-consequential load loss, and a later project in Winger-Thief River Falls 230 kV line.

Analysis: Due to steady growth of area loads and new contingencies added to regular MTEP (transmission planning) analyses, some additional capacity to the system has been deemed necessary. The proposed uprate includes some analysis, design, and probably the raising of 3 or 4 structures (or potentially, structure replacements). Since there is new transmission being proposed in the area (Winger-Thief River Falls 230 kV), this uprate could be deferred by non-consequential load loss. A final determination hasn’t been reached, but this is the preferred option.

Schedule: The need for in-service is tentatively summer of 2019. A study effort will soon be underway to re-evaluate the Northwestern Minnesota load service and related project options.

General Impacts: This project is primarily rural in location and slight in scope. Since it is an uprate to an existing 115 kV line, no environmental impacts are anticipated.

This project may require a temporary project crew. If so, that may bring some business to the area in the form of room and board. In terms of local government benefits, little is expected as a result of the transmission uprate.

This project is the result of capacity needs, and it will probably not have an impact on the community in terms of population or other social characteristics.

Donaldson 115 kV Capacitor Bank Addition

Project Description: A new capacitor bank is being proposed for the Donaldson Substation. Growth of industrial loads in the area has caused a need for more voltage support. A total of 30 MVAR of capacitors in two 15 MVAR stages is proposed, along with any necessary modifications to the existing Donaldson Substation.

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. To sustain reliability in years leading to new transmission upgrades, a new capacitor bank addition is being proposed for the Donaldson Substation (in cooperation with Minnkota Power Cooperative, as they have agreed to their own capacitor addition at the Thief River Falls Substation).

Analysis: Reliability improvements from the previously mentioned projects were evaluated in the “High Voltage Study,” which was performed by OTP with support from MPC. The study showed that a fault on and 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 a new 230 kV source at Thief River Falls to be completed by 2024. However, the timeframe between 2021 and 2023 required further mitigation for the loss of automatic undervoltage load shedding (per TPL-001-4). To mitigate the resulting voltage violations, Thief River Falls capacitor bank and Donaldson capacitor additions have been proposed (2018-2020).

Schedule: The study efforts mentioned above determined that an upgrade to mitigate post-contingent service issues to the Northwest Minnesota area transmission must be completed by the winter of 2023-2024 (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 schedule will be developed as definite mitigation plans are determined. A study effort is underway to re-evaluate the Northwestern Minnesota load service and project options.

General Impacts: This project is entirely at the Donaldson Substation location. There is no new transmission area for 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.

This project is the result of updated requirements, and it’s unlikely it will have a noticeable impact on the community in terms of population or other social characteristics.

The table below identifies one project in the Northwest Zone that was listed as an ongoing project in the 2015 Biennial Report but has since been determined to not be necessary. More information about Tracking Number 2015-NW-N6 can be found in the 2015 Report. Should the project once again become necessary, it will be assigned a new Tracking Number.

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

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

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

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

Because Minnesota Power anticipated this future need, a relatively minimal amount of transmission line and substation construction will be required to implement the Duluth 230 kV Project when it becomes needed. Due to the configuration of the existing Duluth area transmission system and anticipated need to provide a second 230 kV source to the Hilltop Substation, no other alternative to this project will provide a cost effective or reasonable solution to this pending inadequacy. Other transmission alternatives would require longer 230 kV line construction and increase both social and economic impacts associated with construction of such a line, and distributed generation is not preferable from either a cost or operational standpoint to the project.

Minnesota Power is continuing to monitor line loading, voltage support and load growth in the Duluth area to better understand when to move ahead with the Duluth 230 kV Project.

Schedule: Slower than anticipated load growth and external system improvements such as the Arrowhead-Stone Lake-Gardner Park 345 kV Line delayed the need for the Duluth 230 kV Project for many years. Recent studies indicate that this project may become needed in the early 2020s. The underlying system drivers behind this potential update in the timing of the project are related to the impact of a number of transitional changes in the nearby North Shore Loop transmission system as well as large load additions and changing transfer assumptions on the Minnesota Power system. The earliest that Minnesota Power currently anticipates initiating public outreach or permitting activities for this project would be in 2019. Further study is required to determine if the Duluth 230 kV Project remains the best technical solution to the issues being identified in the out-year cases and when the project is needed.

General Impacts: When it becomes needed, the Duluth 230 kV Project will make optimal use of existing transmission infrastructure in the area to provide the needed system improvements, supporting load growth, economic development, and the transition away from small coal units on the Minnesota Power system in the most cost-effective and least environmentally impactful manner possible by utilizing existing utility infrastructure to the greatest extent possible.

Project Description: Construct a new, 115 kV line from Great River Energy’s (GRE) existing Birch Lake Substation to Lake Country Power’s (LCP) Onigum Substation. LCP will rebuild their substation adjacent to the existing site to receive 115 kV electric service.

Need Driver: LCP’s Onigum Substation is served by a 34.5 kV system that is sourced by the 115/69/34.5 kV Birch Lake Substation and the 115/34.5 kV Akeley substation. Due to the aging condition and lack of capacity, GRE is planning to rebuild the existing 34.5 kV to 115 kV.

Alternatives: An alternative considered was rebuilding the 34.5 kV system with a like-for-like replacement.

Analysis: The 2008 GRE Long Range Plan indicated that the conversion of the Onigum Substation to 115 kV operation will unload the 34.5 kV service and extend the useful life of this system. MP and GRE will need to monitor the growth of the Walker area electric system to see when further conversion may be required.

Schedule: The timing of the Onigum conversion will be driven by the anticipated load growth in the area or if structural issues arise.

General Impacts: The Onigum 115 kV Conversion Project is the most efficient and least environmentally impactful viable solution for meeting the near term and long term needs in the Onigum area. The Onigum area will be served by a transmission grade source that will have less disruption resulting in greater reliability and also will also have less system losses.

Project Description: Rebuild and reconductor existing Fond du Lac-Hibbard 115 kV Line (MP “15 Line”).

Need Driver: The existing Fond du Lac-Hibbard 115 kV Line needs to be rebuilt with a larger conductor due to its age and condition, lack of shield wire resulting in elevated risk to nearby sensitive industrial loads, and identified pre- and post-contingent overloads on the line.

Alternatives: A previously-preferred alternative (MISO MTEP Project #2549) involved reconfiguring 15 Line with an existing 115 kV line and substation to allow for removal of approximately half of the 11-mile line. Further analysis of constructability, particularly with regard to the location where 15 Line would be reconfigured to interconnect with the existing 115 kV line, as well as further analysis of the long-term transmission system needs in the area identified that an in-place rebuild of 15 Line was a preferable solution.

Analysis: Reconductoring 15 Line provides the best solution for maintaining the reliability of the Duluth-area 115 kV system in view of current needs (to deliver hydroelectric generation from Thomson and Fond du Lac, to support current load levels) and long-term needs (projected load growth and transmission system modifications such as the Duluth 230 kV Project). While recent analysis has shown that it would be prohibitively expensive to reconductor a portion of existing conductor on lattice towers, new line ratings will still be sufficient to mitigate identified overloads on the line.

Schedule: MISO and Minnesota Power studies indicate that a need for the 15 Line Upgrade develops in 2017. Since construction will not be completed in 2017, an operating guide is in place to mitigate overloading until the project can be completed. The project was broken into two phases, with Phase 1 construction taking place in 2017 and Phase 2 construction (and project completion) taking place in 2018.

General Impacts: The 15 Line Upgrade project will provide necessary system improvements in the Duluth area without requiring the establishment of additional transmission line corridors, which will minimize any potential environmental impacts.

Project Description: Add a new 115/13.8 kV substation interconnected to the Taconite Harbor-Hoyt Lakes 115 kV Line (MP “1 Line”). A mechanically switched capacitor bank will also be included to provide necessary voltage support to the area between Hoyt Lakes and Taconite Harbor.

Alternatives: There are no viable alternatives to this project since the project is needed to provide transmission-level electric service at a specific proposed mine site.

Analysis:The Dunka Road Substation will be designed to provide redundant electric service and meet the projected near-term and long-term needs of the proposed Polymet mine site and the surrounding transmission system.

Schedule: The schedule for construction of the Dunka Road Substation is dependent on the schedule for the development of the Polymet mine. Construction of the Dunka Road Substation also needs to be coordinated with the completion of the Laskin-Taconite Harbor Voltage Conversion Project (Tracking Number 2017-NE-N2) to ensure that the legacy 138 kV system has been converted to 115 kV prior to energization of the new Dunka Road Substation.

General Impacts: The Dunka Road Substation is the most efficient and least environmentally impactful viable solution for meeting the near-term and long-term needs at the new mine site. The project supports industrial expansion in northeastern Minnesota and the attendant social and economic benefits that such expansion brings to the local area and the State. As part of enabling service to the new industrial load, the inclusion of a switched capacitor bank at the Dunka Road Substation 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 enables the realization of significant economic and environmental benefits from transitioning away from these units.

Project Description: Rebuild existing Wrenshall 115/14kV Distribution Substation and extend new feeder to Military Road.

Need Driver: Retirement of existing 46 kV line and equipment at Thomson Substation due to age and condition. Additionally, the assets at the existing Wrenshall Substation are near end of life.

Alternatives: Rebuild existing radial 46 kV circuit from Thomson to Military Road.

Analysis: Rebuilding the existing Wrenshall Substation and extending a new feeder to the Military Road area will allow for continued service to Minnesota Power customers in the Wrenshall area and allow for Minnesota Power to retire 46 kV line assets and equipment at Thomson Substation.

Schedule: The Wrenshall Substation Project is expected to be in service in late 2020.

General Impacts: The Wrenshall Substation Project will ensure a continuous and reliable power supply to Wrenshall and the surrounding area, while eliminating an aged segment of 46 kV line that is difficult and expensive to maintain due to its location and the surrounding terrain.

Project Description: The Great Northern Transmission Line Project includes approximately 225 miles of 500 kV transmission line between a point on the Minnesota-Manitoba border northwest of Roseau, MN, and Minnesota Power’s existing Blackberry Substation near Grand Rapids, MN. The project also includes the development of a new substation (Iron Range 500/230 kV Substation) located on the same site as the existing Blackberry Substation as well as a 500 kV midline series compensation station (Warroad River Series Compensation Station) located near Warroad, MN.

Need Driver: The purpose of the Great Northern Transmission Line Project is to efficiently provide Minnesota Power’s customers and the Midwest region with clean, emission-free energy that will help meet the region’s growing long-term energy demands, advance Minnesota Power’s EnergyForward strategy to increase its generation diversity and renewable portfolio, strengthen system reliability, and fulfill Minnesota Power’s obligations under its power purchase agreements with Manitoba Hydro, all in a manner that is consistent with Minnesota Power’s commitment to making a positive impact on the communities where it does business.

Analysis: The Great Northern Transmission Line provides the most effective and efficient long-term solution for supporting incremental power transfers on the Manitoba-United States interface.

Schedule: In anticipation of the Great Northern Transmission Line Project’s aggressive schedule and needing to meet a June 1, 2020, in-service date, Minnesota Power initiated a proactive public outreach program to key agency stakeholders and the public that started in August 2012 and continued through May 2015. Through this program, thousands of landowners, the public, and federal, state, and local agency stakeholders were engaged through a variety of means, including five rounds of voluntary public open house meetings held throughout the project area.

On September 23, 2014, Minnesota Power, Manitoba Hydro, and the Midcontinent Independent System Operator (MISO) executed a Facilities Construction Agreement (FCA) for the Great Northern Transmission Line Project, setting forth the ownership and financial responsibilities for the project, among other terms. Upon approval of the FCA by the Federal Energy Regulatory Commission (FERC) on November 25, 2014, MISO considered the project an approved project under the MISO tariff and moved the Great Northern Transmission Line Project to Appendix A of the MISO Transmission Expansion Plan 2014 (MTEP14). Subsequently, the Minnesota Public Utilities Commission granted Minnesota Power a Certificate of Need (MPUC Docket No. E015/CN-12-1163) and Route Permit (MPUC Docket No. E015/TL-14-21) for the Great Northern Transmission Line on May 14, 2015, and February 26, 2016, respectively. The final major approval – the United States Presidential Permit granting approval of the border crossing (DOE Docket No. PP-398) – was received from the United States Department of Energy on November 16, 2016. Following receipt of the Presidential Permit, Minnesota Power began construction of the project in early 2017 and is continuing to execute the project construction schedule in order to meet the required in-service date of June 1, 2020 in satisfaction of the contractual agreements between Minnesota Power and Manitoba Hydro.

General Impacts: The Manitoba Hydro hydropower purchases made possible by the Great Northern Transmission Line will provide Minnesota Power and other utilities in the Upper Midwest access to a predominantly emission-free energy supply that has a unique combination of baseload supply characteristics, price certainty, and resource optimization flexibility not available in comparable alternatives for meeting customer requirements. Minnesota Power has maintained its commitment to making a positive impact in the communities throughout the project area through a multiyear proactive public outreach program and through designing its routes to utilize existing transmission line corridors to the greatest reasonable extent when considering all human, environmental, and engineering constraints. The project is also expected to have a significant impact on local property taxes in the counties where it will be located.

Project Description: Replace thyristor valve halls with modern equipment on Square Butte – Arrowhead HVDC line.

Need Driver: The HVDC terminals were designed by General Electric (GE) for a 30 year operating lifetime and as of 2017 they have been operating reliably for over 40 years. The main components of the HVDC terminals include the thyristor valves and cooling, converter transformers, and smoothing reactors to complete the energy conversion. The original vendor, GE, left the HVDC business in the 1980s and over the past few years it has been increasingly difficult to procure spare parts 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 HVDC system remain limited. By taking action to modernize the thyristor equipment, Minnesota Power will greatly reduce the likelihood of a line failure. Minnesota Power is evaluating a series of modernization activities for each of the major components of the HVDC system. Along with the thyristor valves, Minnesota Power can reduce the likelihood of forced outages of the 465 mile transmission line by planning replacement of transformers and smoothing reactors. Minnesota Power continues to evaluate the timing and priority for modernizing each of these components.

Alternatives: There are two alternatives. “Do Nothing” (risk of extended outage due to equipment failure) or implement the HVDC 750 MW Upgrade (Tracking Number 2013-NE-N17).

Schedule: The timing of the HVDC Valve Hall Replacement Project will be identified based on Minnesota Power’s reliability and economic evaluations. Minnesota Power is actively monitoring the project and looking for an opportunity to execute it while balancing system reliability needs with costs to customers and prioritization of all capital projects. Following detailed specification and competitive bidding of the project, the earliest expected in-service date for the project is 2023. The delay is due to manufacturer lead times and Minnesota Power budgetary restrictions.

Project Description: Upgrade existing Square Butte-Arrowhead HVDC line and terminal equipment to 750 MW capacity.

Need Driver: With new equipment such as what would be necessary to complete the HVDC Valve Hall Replacement Project (Tracking Number 2013-NE-N16) there is opportunity to consider new designs, technology capabilities and system enhancements. Specifically with the thyristor valves, Minnesota Power has the opportunity to design a system capable for up to 750 MW while utilizing the existing building and real estate. The new valves provide advantages of life extension (of at least 30 years) and the option to allow energy to flow in both west to east and east to west directions that would add a new and positive dynamic to the regional transmission system. Additional equipment upgrades beyond replacement of the thyristor valves would be necessary to upgrade the capacity of the HVDC line to 750 MW. The converter transformers, AC filter banks, and transmission line capability would all need to be studied and either replaced or increased in size. The 230 kV system connecting the Arrowhead Substation to power sources on the Iron Range would also need to be evaluated to determine if additional 230 kV transmission line capacity would be necessary to enable east to west scheduling of the HVDC line. The decision to size the system for 750 MW operation will need additional study and be determined during the final design phase for the modernization activities.

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. Additional modifications to the HVDC system enabling higher transfer capability on the line would potentially provide an even better long-term solution, assuming that the additional costs can be justified.

Schedule: The timing of the HVDC 750 MW Upgrade Project will be identified based on Minnesota Power’s reliability and economic evaluations. Minnesota Power is actively monitoring the project and looking for an opportunity to execute it while balancing system reliability needs with costs to customers and prioritization of all capital projects. Following detailed specification and competitive bidding of the HVDC Valve Hall Replacement Project (Tracking Number 2013-NE-N16), the earliest expected in-service date for any HVDC upgrade is 2023. The delay is due to manufacturer lead times and Minnesota Power budgetary restrictions.

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 HVDC 750 MW 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.

Project Description: Construct a new 115/34.5 kV substation to be named Elisha, build approximately 2.0 miles of 115 kV transmission to interconnect Elisha to the Itasca Mantrap’s Potato Lake Substation, and build approximately 12.0 miles of 69 kV transmission, to be operated at 34.5 kV, to interconnect to Itasca Mantrap’s Pine Point Substation. The 230/115/34.5 kV Hubbard Substation will retire all of its 34.5 kV assets and the Elisha Substation will utilize the remaining 115/34.5 kV transformer at Hubbard. The newly established 34.5 kV loop served by Elisha and Long Lake will have a normally open point at the Osage Substation.

Need Driver: Provide a redundant, stronger source to the Osage load pocket to alleviate low voltage seen on the 12.47 kV end. Minimize the radial MW-Mile exposure on the Hubbard-Osage-Shell Lake-Pine Point 34.5 kV line.

Alternatives:Development of a 115/34.5 kV substation near Potato Lake and build a 34.5 kV line from the new substation to the Osage Substation.

Analysis: The Elisha Substation will serve the Osage, Pine Point, and Shell Lake substations system intact while Long Lake will act as a backup source to these loads. The voltage profile in the Osage area will increase significantly with the proposed Elisha Substation.

Schedule: GRE anticipates initiating the project development in 2018. The timing of this project is dependent on the Enbridge Pipeline construction schedule.

General Impacts: The Elisha 115 kV Project is the most efficient and least environmentally impactful viable solution for meeting the near term and long term needs in the Osage area. The Osage area will be served by a transmission grade source that will have less disruption resulting in greater reliability and also will also have less system losses.

Project Description: Reconductor existing Brainerd-Mud Lake 115 kV Line (MP “5 Line”) and replace limiting substation terminal equipment.

Need Driver: Post-contingent overload following loss of parallel 230 kV line.

Alternatives: Build a new 115 kV or 230 kV line between Mud Lake and Riverton.

Analysis: Reconductoring 5 Line provides the best solution for maintaining the reliability of the Brainerd-area 115 kV system in view of currently-identified needs, and should defer or eliminate the need for additional transmission line development in the area based on current projections.

Schedule: MISO and Minnesota Power studies first indicate a need for the 5 Line Upgrade prior to the 2019-2020 winter season. The earliest MP anticipates being able to begin construction of the project would be in 2019.

General Impacts: The 5 Line Upgrade Project will provide necessary system improvements in the Brainerd area without requiring the establishment of additional transmission line corridors.

Project Description: Reconductor existing Little Falls-Langola Tap-St. Stephen Tap 115 kV Line (MP “868 Line”) and replace limiting substation terminal equipment.

Need Driver: Post contingent overload following loss of parallel 230 kV, 345 kV, or 500 kV lines.

Alternatives: Build a new 115 kV or 230 kV line between Mud Lake and the St. Cloud area; thermal upgrade of existing conductor paired with deployment of Smart Wires power flow control devices to reduce power flow to within capability of existing conductor.

Analysis: Minnesota Power is continuing to evaluate the reconductor solution against the Smart Wires solution to determine which solution presents the best long-term value. Either solution should be sufficient for maintaining the reliability of the Little Falls-area 115 kV system in view of currently-identified needs, and should defer or eliminate the need for additional transmission line development in the area based on current projections.

Schedule: MISO and Minnesota Power studies first indicated a need for the 868 Line Upgrade prior to the 2019-2020 winter season. The earliest MP anticipates being able to begin construction of the project would be in 2019.

General Impacts: The 868 Line Upgrade Project will provide necessary system improvements in the area between Little Falls and St. Cloud without requiring the establishment of additional transmission line corridors.

Project Description: Rebuild & modernize existing 15th Avenue West Substation, including new 14 kV switchgear on adjacent property, one new 115/14 kV transformer, replacement of three 115 kV breakers and other 115 kV equipment, and miscellaneous site improvements.

Need Driver: The 15th Avenue West Substation is the largest single load-serving distribution substation in the Duluth area by total load, and serves one of Minnesota Power’s most high profile load pockets: downtown and central Duluth. Many of the assets within the substation are nearing the end of their useful life, including particularly the 14 kV switchgear and some of the foundations. In addition to the risks posed by the possible failures of end-of-life equipment, there are parts of the substation that do not meet modern design and safety standards, causing safety concerns and limiting accessibility within the substation. The purpose of the 15th Avenue West Substation Modernization Project is to address aging equipment, potential reliability and safety concerns, and long-term system needs at the 15th Avenue West Substation.

Alternatives: Development of a new 115/14 kV substation in downtown Duluth and retirement of the existing 15th Avenue West Substation; utilization of gas insulated substation (GIS) equipment to minimize project footprint.

Analysis: Much of the existing equipment in the 15th Avenue West Substation is at end-of-life, and its replacement is a prudent and necessary step in maintaining reliable electric service for the downtown and central Duluth area. The cost associated with the development of an entirely new 115/13.8 kV substation adjacent to the existing site – and subsequent retirement of the existing site – was not justified based on the fact that the reliability, accessibility, and safety needs on the site could largely be addressed by relocation the distribution equipment and remaining equipment on the site as necessary.

Schedule: Construction of the 15th Avenue West Substation Modernization Project began in 2017 and will continue in stages through 2018.

General Impacts: The 15th Avenue West Substation Modernization Project will ensure a continuous and reliable power supply for the downtown and central Duluth area in the most cost-effective and least environmentally impactful manner possible.

Project Description: Reroute a segment of the existing Arrowhead-16 Line Tap 115 kV Line around a proposed United Taconite tailings basin expansion.

Analysis: A fully-intact connection between Arrowhead and the 16 Line Tap is necessary for providing reliable electric service to the area between Duluth and Eveleth. Removal of the line off the proposed tailings basin expansion site without re-establishing this connection is not a viable solution.

Schedule: The 16 Line Relocation Project is expected to be completed by May of 2020 to meet United Taconite’s schedule for the planned tailings basin expansion. Since the 2015 Report, a two year delay of the project was agreed to with United Taconite to better align the timing of the project with the scheduled expansion of the tailings basin.

General Impacts: The 16 Line Relocation Project maintains an important source of power for the area between Virginia and Duluth while also enabling industrial expansion on the Iron Range.

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 have since been 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, 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 currently-desired incremental export capability from Manitoba to the United States and the majority of the benefits of wind and hydro synergy can be realized by the development of the Great Northern Transmission Line Project alone, without a 345 kV extension to Arrowhead. Because there are not sufficient transmission service requests to justify the 345 kV connection to Arrowhead at this time, Minnesota Power has determined that it will 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, it will be advanced at that time based on its own merits apart from the Great Northern Transmission Line Project.

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 is not needed or economically justified at this level of Manitoba Hydro export. MISO studies have confirmed this finding.

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

Project Description: Install new 69/46 kV transformer at Great River Energy’s existing Bear Creek Substation and remove existing Sandstone 69/46 kV distribution station.

Need Driver: Age and condition of Sandstone distribution station, as well as environmental concerns with the location of the Sandstone distribution station adjacent to the Kettle River.

Analysis: Relocating the 69/46 kV source from Sandstone to the nearby Bear Creek Substation will improve redundancy for Minnesota Power’s customers while also utilizing an already-developed substation site in a more accessible and environmentally favorable location.

Schedule: Expected to be placed in-service in early 2018 following a minor delay due to engineering resource constraints.

General Impacts: The Bear Creek 69/46 kV Transformer Project will replace end-of-life equipment and provide increased load-serving capacity and reliability for Minnesota Power’s customers along the Interstate 35 Corridor south of Duluth. Utilizing the existing Bear Creek Substation for the new 69/46 kV transformer and retiring the existing Sandstone distribution station site meets these needs in the most cost-effective and least environmentally impactful manner possible.

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.

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, 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.

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 95 Line Upgrade Project restores the capacity of 95 Line, a critical outlet for Boswell generation, to its original capacity.

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, and post-contingent overloads of 95 Line at its new lower rating were identified in the MTEP15 assessment as well as Minnesota Power’s own internal studies. The project is expected to be placed in-service in October 2017.

General Impacts: The 95 Line Upgrade Project will restore critical transmission outlet capability for the Boswell Energy Center without requiring the establishment of additional transmission line corridors.

Project Description: Tap the Mantrap to Potato Lake line near Potato Lake Substation and build approximately 7.5 miles of 115 kV transmission line to connect the future Two Inlets Substation. The substation will supply power to the Enbridge Two Inlets pump station.

Need Driver: Enbridge Pipeline has proposed a new pumping station about 12 miles northwest of Park Rapids.

Alternatives: The nearby distribution systems would not support the large pumping station load. Other alternatives would require longer 115 kV or higher voltage transmission lines.

Analysis: Large pumping stations with large electric motors require a robust voltage like 115 kV. The nearest 115 kV source is the Potato Lake Substation. A short, radial tap from the Potato Lake Substation to the new Two Inlets Substation will be constructed to provide electric service.

Schedule: The project is planned to be in-service by July 2019. The timing of this project is dependent on the Enbridge Pipeline construction schedule.

General Impacts: The Two Inlets Pumping Station Project is the most efficient and least environmentally impactful viable solution to serve the new pumping station load.

Project Description: Build an approximately 2.5 mile 115 kV transmission line from a new interconnection to the Minnesota Power 115 kV #142 line (Badoura to Pine River) to the Backus Pumping Station.

Need Driver: Enbridge Pipeline has proposed a new pumping station about 3 miles south of Backus.

Alternatives: The nearby distribution systems would not support the large pumping station load. Other alternatives would require longer 115 kV or higher transmission lines.

Analysis: Large pumping stations with large electric motors require a robust voltage like 115 kV. The nearest 115 kV source is the Badoura-Pine River (142 Line) 115 kV line. A short, radial tap from the 142 Line to the new Backus Pumping Station Substation will be constructed to provide electric service.

Schedule: The project is planned to be in-service by July 2019. The timing of this project is dependent on the Enbridge Pipeline construction schedule.

General Impacts: The Backus Pumping Station Project is the most efficient and least environmentally impactful viable solution to serve the new pumping station load.

Project Description: Build an approximately 13 mile 115 kV transmission line from MP’s 115 kV #13 line to the Enbridge Palisade Pumping Station.

Need Driver: Enbridge Pipeline has proposed a new pumping station about 5.5 miles northwest of the City of Palisade.

Alternatives: The nearby distribution systems would not support the large pumping station load. Other alternatives would require longer 115 kV or higher transmission lines.

Analysis: Large pumping stations with large electric motors require a robust voltage like 115 kV. The nearest 115 kV source is the Riverton-Cromwell (13 Line) 115 kV line. A radial tap from the 13 Line to the new Palisade Pumping Station Substation will be constructed to provide electric service.

Schedule: The project is planned to be in-service by July 2019. The timing of this project is dependent on the Enbridge Pipeline construction schedule.

General Impacts: The Palisade Pumping Station Project is the most efficient and least environmentally impactful viable solution to serve the new pumping station load.

Project Description: Build an approximately 0.5 mile long 115 kV line from Cromwell City line to the Cromwell Pumping Station.

Need Driver: Enbridge Pipeline has proposed a new pumping station about 5.5 miles south of the City of Cromwell.

Alternatives: The nearby distribution systems would not support the large pumping station load. Other alternatives would require longer 115 kV or higher transmission lines.

Analysis: Large pumping stations with large electric motors require a robust voltage like 115 kV. The nearest 115 kV source is the Cromwell-Savanna (156 Line) 115 kV line. A short, radial tap from the 156 Line to the new Cromwell Pumping Station Substation will be constructed to provide electric service.

Schedule: The project is planned to be in-service by July 2019. The timing of this project is dependent on the Enbridge Pipeline construction schedule.

General Impacts: The Cromwell Pumping Station Project is the most efficient and least environmentally impactful viable solution to serve the new pumping station load.

Project Description: Thermal upgrade of the Boswell-Canisteo 115 kV Line (MP “28 Line”) and replacement of limiting 115 kV terminal equipment at the Boswell Substation to increase capacity.

Need Driver: Post-contingent overload following loss of parallel 115 kV connections.

Alternatives: Build an additional 115 kV transmission line out of the Boswell 115 kV Substation.

Analysis: This issue was first identified in the MTEP15 assessment near-term models. Increasing the transmission line capacity provides the best solution for maintaining the reliability of the transmission system in the Grand Rapids area.

General Impacts: The 28 Line Upgrade Project will provide necessary system improvements on Minnesota Power’s 115 kV system in the Grand Rapids area without requiring the establishment of additional transmission line corridors or removal of the existing conductor.

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. At the Hoyt Lakes Substation, the existing bus will also be expanded to include two 20 MVAR capacitor banks, a bus-tie breaker, and an open dead end structure to connect a future transmission line to the Hoyt Lakes Substation.

Need Driver: Age and condition, removal of single points of failure, standardization of equipment, and voltage support concerns following conversion, idling, or retirement of coal-fired generators in the North Shore Loop.

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 ongoing 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 leadtimes (138/115 kV transformers), providing a more redundant and reliable transmission connection for the North Shore Loop. The project also incorporates the establishment of two 20 MVAR capacitor banks at the Hoyt Lakes Substation to replace voltage support historically provided by local baseload generators. 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 future transmission expansion, should it become necessary to further interconnect and enhance redundancy to the area. The establishment of a future 115 kV transmission line bay at the Hoyt Lakes Substation provides a place to connect the Hoyt Lakes 115 kV Project (Tracking Number 2017-NE-N23), should it become needed. Continued operation of the Laskin-Tac Harbor system at 138 kV would significantly increase the cost and complexity of making this future transmission connection into the area.

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.

Project Description: Reconfigure Little Falls 115 kV bus and add a tie breaker.

Need Driver: Low voltage was identified at the Pepin Lake, Blanchard, Bellevue, and Little Falls Substations following contingency events involving the Little Falls 115 kV Bus.

Analysis: This issue was first identified in the MTEP15 assessment and is being monitored. The addition of a bus tie breaker at the Little Falls Substation was submitted as a potential Corrective Action Plan. Depending on if and how the issue shows up in subsequent assessments, further analysis will be done to clarify the critical load level at which post-contingent voltage becomes a problem and determine what the most appropriate solution is.

Schedule: This issue was first identified in the MTEP15 2019 Winter Peak case. Minnesota Power is monitoring MTEP reliability assessment results and analyzing the load level in the area to determine if and when a project is needed.

Project Description: Increase capacity of Nashwauk-14 Line Tap 115 kV Line (MP “Nashwauk 14 Line”).

Analysis: This issue was first identified in the MTEP15 assessment and is being monitored. The capacity upgrade project was proposed as the most straightforward and likely Corrective Action Plan should the post-contingent overloads first observed in the MTEP15 assessment continue to show up in subsequent study results. The same issue was identified in the MTEP17 assessment, and based on those results the project will be moved to Appendix A in MTEP18.

Schedule: This issue was first identified in the MTEP15 2020 Shoulder (off-peak) case, and subsequently showed up in a similar MTEP17 2022 Summer Peak case. Based on the MTEP15 results, the project is targeted for an in-serviced date prior to May 1, 2020.

General Impacts: The Nashwauk 14 Line Upgrade Project will provide necessary system improvements on Minnesota Power’s 115 kV system without requiring the establishment of additional transmission line corridors.

Project Description: Increase capacity of Nashwauk-National 115 kV Line (MP “53 Line”).

Analysis: This issue was first identified in the MTEP15 assessment and is being monitored. The capacity upgrade project was proposed as the most straightforward and likely Corrective Action Plan should the post-contingent overloads first observed in the MTEP15 assessment continue to show up in subsequent study results. A similar issue was identified in the MTEP17 assessment, and based on those results the project will be moved to Appendix A in MTEP18.

Schedule: This issue was first identified in the MTEP15 2020 Shoulder (off-peak) case, and subsequently showed up in a similar MTEP17 case. Based on the MTEP15 results, the project is targeted for an in-serviced date prior to May 1, 2020.

General Impacts: The 53 Line Upgrade Project will provide necessary system improvements on Minnesota Power’s 115 kV system without requiring the establishment of additional transmission line corridors.

Project Description: Install breaker failure relay on Forbes 38-44 MW 115 kV bus tie breaker.

Need Driver: Bus fault followed by failure of breaker to operate causes overloading on area transmission lines. Breaker failure relay will keep post-contingent loading within the present capacity of the system.

Analysis: This issue was first identified in the MTEP15 reliability assessment and is being monitored. The addition of a breaker failure relay was submitted as a potential Corrective Action Plan. Further internal Minnesota Power studies have identified potential for additional issues associated with internal fault or failure of the Forbes tie breaker that may drive a need to add a redundant bus tie breaker rather than just a breaker failure relay. Further analysis is necessary to determine the most appropriate long-term solution.

Schedule: This issue was first identified in the MTEP15 2020 Shoulder (off-peak) case. Minnesota Power is monitoring the MTEP reliability assessment results, as well as its own internal study 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, 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.

Project Description: A new substation called the North Shore Switching Station will be constructed. The North Shore Switching Station involves the development of a 6 position ring bus in the Silver Bay-Taconite Harbor 115 kV Line approximately one mile northeast of the existing Silver Bay 115 kV Substation, as well as approximately one mile of double circuit 115 kV line from the new switching station along the existing transmission line corridor to the Silver Bay-Two Harbors 115 kV Line just outside the Silver Bay Substation. Two 20 MVAR switched capacitor banks and two 40 MVAR fast-switched capacitor banks will be established in the new switching station.

Need Driver: Voltage violations and voltage stability concerns in the North Shore Loop transmission system following conversion, idling, or retirement of local coal-fired generators.

Alternatives: Re-establish existing Silver Bay capacitor banks and load shedding scheme.

Analysis: Because of the rapid rate of change in the North Shore Loop transmission system, Minnesota Power has effected the re-establishment of several decommissioned (and deteriorating) capacitor banks at the Silver Bay Substation as well as a previously-retired automatic load shedding scheme at a large industrial plant in Silver Bay as interim solutions until the North Shore Switching Station can be constructed and placed in service. The North Shore Switching Station is a superior long-term solution for the voltage stability and performance issues in the Silver Bay area because it provides the necessary voltage support from reliable switched capacitor banks, further sectionalizes the North Shore Loop to eliminate some of the most severe contingency events, and provides fast-switched capacitor banks to eliminate dependence on a very simplistic customer-owned auto load shedding scheme. The North Shore Switching Station also provides a ready location for the establishment of the North Shore Dynamic Reactive Device (Tracking Number 2017-NE-N15) when that project becomes necessary.

Schedule: With the majority of generator transition already having taken place in 2015 and 2016, the North Shore Switching Station needs to be placed in service as soon as possible. Currently, the targeted in-service date is November 2017.

General Impacts: The North Shore Switching Station is a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. The establishment of new capacitor banks begins the process of replacing the voltage support previously provided by baseload coal units in the area, enabling the realization of significant economic and environmental benefits from transitioning away from these units. The location of the switching station and transmission line upgrades within the boundaries of a large industrial facility further limits human and environmental impacts from the project.

Project Description: Add a 12 MVAR capacitor bank to the existing Babbitt 115 kV Substation.

Need Driver: Voltage violations following conversion, idling, or retirement of North Shore Loop coal-fired generators.

Alternatives: There is no more economical or less impactful solution than adding a capacitor bank to an existing substation to provide the necessary voltage support.

Analysis: Minnesota Power internal analysis of the impact of transitioning away from local baseload coal-fired generators in the North Shore Loop identified low voltage violations in the Babbitt area. The Babbitt Capacitor Bank Project will replace the voltage support previously provided by the local generators, allowing for continued reliable operation of the system in the North Shore Loop and the surrounding area in their absence.

Schedule: The project was completed and placed in service in September 2017.

General Impacts: The Babbitt Capacitor Bank is a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. The establishment of new capacitor banks begins the process of replacing the voltage support previously provided by baseload coal units in the area, enabling the realization of significant economic and environmental benefits from transitioning away from these units. The location of the Babbitt Capacitor Bank at an existing substation considerably limits human and environmental impacts from the project.

Project Description: Add a 20 MVAR capacitor bank and replace a broken 115 kV switch at the existing ETCO 115 kV Substation.

Need Driver: Voltage violations following conversion, idling, or retirement of North Shore Loop coal-fired generators.

Alternatives: There is no more economical or less impactful solution than adding a capacitor bank to an existing substation to provide the necessary voltage support.

Analysis: Minnesota Power internal analysis of the impact of transitioning away from local baseload coal-fired generators in the North Shore Loop identified low voltage violations in the ETCO Substation area. The ETCO Capacitor Bank Project will replace the voltage support previously provided by the local generators, allowing for continued reliable operation of the system in the North Shore Loop and the surrounding area in their absence.

General Impacts: The ETCO Capacitor Bank is a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. The establishment of new capacitor banks begins the process of replacing the voltage support previously provided by baseload coal units in the area, enabling the realization of significant economic and environmental benefits from transitioning away from these units. The location of the ETCO Capacitor Bank at an existing substation considerably limits human and environmental impacts from the project.

Project Description: The Forbes 3T Breaker Replacement Project involves replacing a 115 kV circuit breaker on the secondary side of the Forbes 230/115 kV Transformer #3. The project also includes replacement of two 115 kV switches and any limiting power wiring between the transformer and the 115 kV bus. Replaced equipment will be seized appropriately to achieve the full emergency rating of the transformer. At the same time the breaker is replaced, the relay panel will be updated to include breaker failure functionality.

Need Driver: Updating the relay panel to include a breaker failure relay is necessary to address voltage stability concerns following a breaker failure event. The Forbes 3T breaker is also aging and due to be replaced as part of Minnesota Power’s ongoing asset renewal program, and much of the existing equipment and power wiring limits the emergency capacity available from the transformer.

Alternatives: There is no more economical or less impactful solution than replacing existing equipment and relaying to mitigate the identified issues.

Analysis: Minnesota Power internal analysis of the impact of transitioning away from local baseload coal-fired generators in the North Shore Loop identified widespread voltage stability concerns following breaker failure events involving the Forbes 3T breaker. The addition of a breaker failure relay would enable fault isolation to occur locally, limiting the impact of the event and mitigating the voltage stability concerns present without the North Shore Loop generators online. Replacement of the Forbes 3T breaker at the same time reduces the likelihood of breaker failure by replacing an aging oil-filled circuit breaker. Replacement of limiting terminal equipment on the secondary side of the transformer allows for better utilization of the existing Forbes transformer to deliver power to the area during system outages.

General Impacts: The Forbes 3T Breaker Replacement is a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. The addition of a breaker failure relay mitigates voltage stability concerns present without the North Shore Loop generators online, preventing equipment damage and other adverse system impacts of a potentially widespread event. Replacement of the Forbes 3T breaker and other equipment in addition to adding a breaker failure relay provides for aging equipment to be replaced and for the full rating of the transformer to be realized. Accomplishing all of this within the footprint of an existing substation considerably limits human and environmental impacts from the project.

Project Description: Add a circuit breaker to the existing LSPI 10K capacitor bank.

Alternatives: “Do nothing” – leave capacitor bank and bus protection as-is.

Analysis: Capacitor bank faults cause the entire LSPI 115 kV bus, including load and networked 115 kV lines, to trip. Adding the breaker prevents the bus from tripping for capacitor bank faults.

General Impacts: This project improves reliability for a large area of western Duluth at a relatively minimal cost, making optimal use of existing assets and space at the LSPI Substation.

Project Description: Thermal upgrade of the Blackberry-Forbes 230 kV Line (MP “93 Line”) to increase summer normal/emergency ratings to 470/517 MVA.

Need Driver: Post-contingent overloads during high export conditions identified in Minnesota Power internal studies and confirmed by MISO in MTEP17.

Analysis: Post-contingent overloads on the Blackberry-Forbes 230 kV Line were first identified in summer 2020 models including high regional export levels. High regional export levels put stress on the Minnesota Power system, including causing this overload. Sufficient capacity can be achieved without replacing the existing conductor or building new transmission lines by increasing the thermal operating temperature of the line from 75 degrees Celsius to 100 degrees Celsius.

Schedule: The targeted in-service date for the 93 Line Upgrade Project is May 1, 2020.

General Impacts: The 93 Line Upgrade Project will provide necessary system improvements on Minnesota Power’s 230 kV system without requiring the establishment of additional transmission line corridors or removal of the existing conductor.

Project Description: The Boswell 230/115 kV Transformer Project involves adding a new 230/115 kV transformer to the existing Boswell 230 kV Substation, expanding the existing Boswell 230 kV Substation yard to include a new 115 kV yard in a breaker-and-½ configuration, and reconfiguring the existing 115 kV transmission lines in the area to terminate at the new 115 kV yard.

Need Driver: Voltage violations following retirement of Boswell Units 1 & 2 coal-fired generators.

Alternatives: Build new transmission line or add additional reactive devices to provide voltage support to the Grand Rapids area. Re-establish baseload generation in the Grand Rapids area.

Analysis: Minnesota Power internal analysis of the impact of transitioning away from Boswell Units 1 & 2 identified low voltage violations on the Grand Rapids 115 kV system without the local baseload generators online. Establishment of a new 230/115 kV source from the Boswell 230 kV Substation (which is not presently connected to the local 115 kV system) will replace the power and voltage support previously provided to the Grand Rapids-area 115 kV transmission system by Boswell Units 1 & 2.

Schedule: The project is planned to be in service by December 31, 2018, consistent with the planned retirement of Boswell Units 1 & 2.

General Impacts: The Boswell 230/115 kV Transformer Project is a critical component to maintaining a reliable system following the planned shutdown of Boswell Units 1 & 2. Establishing a new 230/115 kV connection will provide a new 230 kV source to the Grand Rapids area 115 kV system, allowing for the continued reliable delivery of power and voltage support to the area following the transition away from local baseload coal units and enabling the full realization of significant economic and environmental benefits from transitioning away from these units.

Project Description: Replacement of end of life oil circuit breaker at the Hibbard Substation in addition to terminal equipment upgrades to increase rating of Hibbard-Winter St.115 kV Line (MP “76 Line”). The Hibbard-Winter St. 115 kV Line is an important transmission connection between Duluth and Superior.

Need Driver: The MISO MTEP16 study results show potential thermal overloading of 76 Line as early as summer 2018 for certain contingencies. Replacing the end of life circuit breaker and upgrading the limiting terminal equipment will eliminate the risk of potential thermal overloads.

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

General Impacts: The 76 Line Upgrade Project is the most cost-effective solution to maintain baseline reliability without requiring the establishment of additional transmission line corridors across state lines.

Project Description: Install a new Static VAR Compensator (SVC) or Static Synchronous Compensator (STATCOM) system at the planned North Shore Switching Station in Silver Bay, MN. The SVC or STATCOM will control local mechanically switched capacitors (MSCs) at the North Shore Switching Station as part of an integrated Static VAR System (SVS).

Need Driver: Voltage and transient stability concerns in the North Shore Loop transmission system following conversion, idling, or retirement of coal-fired generators.

Alternatives: Large new transmission line(s) into the Silver Bay area, replacement dispatchable baseload generation in the Silver Bay area.

Analysis: Following transition of the last baseload coal-fired generator in the North Shore Loop, the dynamic reactive support formerly provided by local generators must be replaced to ensure continued reliable service to all customers in the North Shore Loop. Establishment of a new SVC or STATCOM system at the North Shore Switching Station is a low-impact, relatively low-cost solution compared to the alternatives, which involve building large new transmission from the Duluth area or the Iron Range to the Silver Bay area, or establishing replacement dispatchable baseload generation in the Silver Bay area. The North Shore SVC or STATCOM will also build upon the planned establishment of the North Shore Switching Station and capacitor banks, making good use of the site and the assets located there. The specific technology employed (SVC or STATCOM) will be determined following a competitive bidding process for the project based on the proposals received from the manufacturers.

Schedule: The targeted in-service date for the North Shore SVC or STATCOM is September 1, 2019, to ensure that the system is fully operational by the end of 2019.

General Impacts: The North Shore SVC/STATCOM is a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. The addition of the SVC/STATCOM to the planned capacitor banks at the North Shore Switching Stations completes the replacement of voltage support previously provided by baseload coal units in the area, enabling the full realization of significant economic and environmental benefits from transitioning away from these units. Locating the new SVC/STATCOM adjacent to the North Shore Switching Station within the boundaries of a large industrial facility greatly minimizes the human and environmental impacts from the project, especially compared to potentially routing large new transmission lines through highly-valued natural and recreational resources into the Silver Bay area or establishing new baseload generation in the area.

Project Description: Thermal upgrade of the Riverton-Pequot Lakes 115 kV Line (MP “51 Line”).

Need Driver: Post-contingent overload following loss of parallel 230 kV connections.

Analysis: Post-contingent overloads on the Riverton-Pequot Lakes 115 kV Line were first identified in the MTEP16 2021 Winter Peak case and are being monitored. A modest 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. 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 MTEP16 2021 Winter Peak case. Minnesota Power is monitoring MTEP reliability assessment results to determine if and when a project is needed.

Project Description: Reconductor existing ETCO-Forbes 115 kV Line (MP “18 Line”).

Need Driver: Post-contingent overloading following conversion, idling, or retirement of North Shore Loop coal-fired generators.

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 transmission lines, including 18 Line, which also carries power to serve loads on the eastern part of the Iron Range. Reconductoring 18 Line provides the needed capacity to ensure continued reliable delivery of power in the eastern part of the Iron Range and into the North Shore Loop following transition away from the local generation.

Schedule: Minnesota Power studies indicate that the 18 Line Upgrade is needed by the end of 2019. The targeted in-service date for the project is fall 2018.

General Impacts: The 18 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 the 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 18 Line Upgrade Project will provide necessary system improvements on the 115 kV system without requiring the establishment of additional transmission line corridors, which will minimize any potential environmental impacts.

Utilities: Minnesota Power (MP) & Grand Rapids Public Utility Commission (GRPUC)

Project Description: Minnesota Power will extend an existing 115 kV tap from the Boswell-Blandin 115 kV Line (MP “27 Line”) to a new GRPUC “Tioga” Substation. GRPUC will construct the new 115/23kV substation and connect to existing distribution.

Need Driver: GRPUC desires a backup substation that is capable of providing redundancy for their distribution system in addition to enabling future load growth.

Alternatives: Build a new 115 kV transmission extension to a different substation site.

Analysis: Since this project is utilizing an existing transmission line asset, it is the least-cost option for meeting GRPUC’s needs. Furthermore, the substation will be strategically located in an industrial park area that has potential for future commercial or industrial development.

General Impacts: Establishing a new distribution substation will provide reliability benefits to the Grand Rapids area as well as enable economic development in the project area. Location of the new substation near an existing transmission line eliminates the need to establish an additional transmission line corridor in the Grand Rapids area, providing a low-cost, low-environmental impact solution.

Project Description: Replace limiting substation equipment on the Ridgeview-Colbyville 115 kV Line (MP “56 Line”). Replace limiting substation equipment and complete a thermal upgrade on the Arrowhead-Colbyville 115 kV Line (MP “57 Line”). Replace limiting substation equipment and complete a thermal upgrade on the Arrowhead-Haines Road 115 kV Line (MP “58 Line”). Replace limiting substation equipment and reconductor 1.9 miles of the existing Colbyville-Two Harbors 115 kV Line (MP “145 Line”).

Need Driver: Post-contingent overloading following conversion, idling, or retirement of North Shore Loop coal-fired generators.

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 transmission lines, including 56 Line, 57 Line, 58 Line, and 145 Line. The coordinated upgrade of these four transmission lines via replacement of limiting substation equipment, thermal upgrades of existing conductors, and replacement of a small segment of conductor provides the needed capacity to ensure reliable delivery of power into the North Shore Loop following transition away from the local generation.

Schedule: Minnesota Power studies indicate that the North Shore Transmission Line Upgrades are needed by the end of 2019. The project will take place in stages between 2018 and 2019, with a targeted in-service date in fall 2019.

General Impacts: The North Shore Transmission Line Upgrades are a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. Increasing the rating of these transmission lines 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.

Project Description: Expand and reconfigure existing Two Harbors Switching Station to accommodate relocation of existing Great River Energy Waldo load-serving tap from Two Harbors-North Shore 115 kV Line (MP “42 Line”) onto a dedicated source from the Two Harbors Switching Station three spans away. Complete a thermal upgrade of existing 42 Line conductor to provide increased transmission line capacity.

Need Driver: Post-contingent overloading following conversion, idling, or retirement of North Shore Loop coal-fired generators.

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 transmission lines, including 42 Line. Analysis of potential upgrade options for 42 Line determined that a costly reconductor of the line could be deferred – and potentially avoided completely – by shifting the Great River Energy Waldo load-serving tap from this line to a dedicated source from the nearby Two Harbors Switching Station and completing a thermal upgrade of the existing 42 Line conductor.

Schedule: Minnesota Power studies indicate that the Two Harbors 115 kV Project needs to be completed by the end of 2019. The targeted in-service date for the project is December 2019.

General Impacts: The Two Harbors 115 kV Project is a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. Increasing the available capacity of 42 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 while minimizing additional transmission line construction and maximizing the optimal use of existing transmission facilities.

Project Description: Thermal upgrades of the existing Hoyt Lakes-Laskin line (MP “43 Line”) and double circuit Hoyt Lakes-Taconite Harbor lines (MP “1 Line” and “2 Line”).

Need Driver: Post-contingent overloading following conversion, idling, or retirement of North Shore Loop coal-fired generators.

Alternatives: Build additional lines between Laskin and Taconite Harbor to relieve loading on existing transmission lines.

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 transmission lines, including 43 Line, 1 Line, and 2 Line. The coordinated upgrade of these three transmission lines via thermal upgrades of existing conductors and minor modification of existing structures provides the needed capacity to ensure reliable delivery of power into the North Shore Loop following transition away from the local generation.

Schedule: Minnesota Power studies indicate that the Laskin-Tac Harbor Line Upgrades are needed by the end of 2019. Construction of the project is expected to take place at the same time as the Laskin-Tac Harbor Voltage Conversion (2017-NE-N2) to utilize the same outage dates.

General Impacts: The Laskin-Tac Harbor Transmission Line Upgrades are a critical component to maintaining a reliable system in the face of significant changes in the North Shore Loop. Increasing the rating of these transmission lines 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.

Project Description: Replace three 115 kV circuit breakers at the Blackberry Substation due to age and condition and fault current projected to be over the breaker interrupting capability. Replace three additional 230 kV circuit breakers at the Blackberry Substation due to age and condition.

Need Driver: The six circuit breakers being replaced are older oil-filled circuit breakers. Three of those breakers will be over-dutied by increased fault currents in the 2020 timeframe. The other three will be replaced for asset renewal due to their age and condition.

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

The breakers were also identified to be replaced as part of MP’s asset renewal program due to the age and maintenance required for the existing circuit breakers.

Analysis: Minnesota Power internal analysis identified that an increase in fault current in the 2020 timeframe, corresponding to the in-service date for the Great Northern Transmission Line (Tracking Number 2013-NE-N13), causes three 115 kV circuit breakers at the Blackberry Substation to exceed their interrupting capability. These three breakers are approximately 40-year old oil-filled circuit breakers that were scheduled to be replaced as part of Minnesota Power’s ongoing asset renewal program. Three additional oil-filled 230 kV circuit breakers of a similar vintage will also be replaced at the same time to take advantage of the efficiencies of bundling the work.

General Impacts: Replacing the circuit breakers will accommodate increased fault current due to changing system topology in the area. Accomplishing this within the footprint of an existing substation considerably limits human and environmental impacts from the project.

Project Description: Extend the existing Forbes-Laskin 115 kV Line (MP “38 Line”) approximately 7 miles into the Hoyt Lakes Substation along the same corridor as the existing Laskin-Hoyt Lakes transmission line. Eliminate the existing connection to the Laskin Substation.

Need Driver: Voltage stability concerns in the Hoyt Lakes area following conversion, idling, or retirement of North Shore Loop coal-fired generators and expected industrial customer expansion at the Hoyt Lakes Substation.

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

Analysis: The Hoyt Lakes 115 kV Project provides needed redundancy for the northern end of the North Shore Loop, enabling industrial customer expansion in the area without the benefits of voltage support historically provided by local coal-fired baseload generators. Reconfiguring and extending the existing Forbes-Laskin 115 kV Line into the Hoyt Lakes Substation avoids a costly overhaul of the existing Laskin Substation or many miles of additional transmission line construction to establish fully redundant transmission sources.

Schedule: Minnesota Power studies indicate that a need for the Hoyt Lakes 115 kV Project develops when future industrial load at the Hoyt Lakes substation comes online. Therefore, Minnesota Power will initiate development of the Hoyt Lakes 115 kV Project only when – and if – the schedule for industrial customer expansion requires it.

General Impacts: The Hoyt Lakes 115 kV Project is a critical component to maintaining a reliable system in the face of significant changes and anticipated load growth in the North Shore Loop. When it becomes needed, the Hoyt Lakes 115 kV Project will make optimal use of existing transmission corridors in the area to provide the needed system improvements, supporting load growth and economic development in the Hoyt Lakes area in the most cost-effective and least environmentally impactful manner possible by utilizing existing utility infrastructure and transmission line corridors to the greatest extent possible.

Project Description: Great River Energy (GRE) will build a 0.2 mile, 115 kV tap line that will interconnect to Minnesota Power’s (MP) 115 kV 9 Line near the intersection of St. Louis River Road and Crosby Road in the Cloquet area via 3-way switch with motor operators in order to provide 115 kV electric service to Lake Country Power’s (LCP) new Knife Falls Distribution Substation. The Knife Falls Substation will serve existing system load that is currently served by LCP’s Solway and Grand Lake substations.

Need Driver: The Cloquet load pocket has been growing and Lake Country Power wants to upgrade the service they are providing to this area. At the moment Solway and Grand Lake substations provide ANSI B voltage to the Cloquet load pocket using two stages of regulation and a cap bank. The installation of the new Knife Falls Substation will allow for ANSI A voltage service to the aforementioned load pocket. LCP is planning to use a 7.5/10.5 MVA transformer that is protected by a transrupter. Knife Falls will serve 0.5 MVA and 2.0 MVA from the Solway and Grand Lake substations respectively.

Alternatives: The alternative to the Knife Falls Distribution Substation would be to continue serving load in the area with the existing distribution substations in the area. However, load growth in the area has reached a level that makes this not feasible. Stepping up the 12.5 kV to 25 kV and then stepping back down could alleviate the issues in the short term but would not be the least cost plan overall and would introduce a new voltage to the area. The best value plan to reliably serve customers in the area is to establish the Knife Falls Distribution Substation.

Analysis: Establishing a new 115/12.5 kV source near Cloquet alleviated the low voltage issues seen on the feeders from Solway and Grand Lake also providing redundancy to this load pocket between Cloquet and the Solway and Grand Lake substations.

Schedule:
Siting and Routing complete.......................................................................................... Feb 2017
ROW Easement Acquisition underway.............................................June 2017 – June 2018
Project Construction.................................................................................June 2018 – Sept 2018
Project In-service............................................................................................................. Sept 2018

General Impacts: The new Knife Falls Distribution Substation will be the most efficient (lowest system losses) and have the least impact on the environment for meeting the near-term low voltage needs and also meeting long term loading needs in the Cloquet area going into the future. The Knife Falls Substation will support the growing needs along Highway 33.

Project Description: Add fast-switched capacitor bank at Boswell 230 kV Substation in a size to be determined.

Need Driver: Transient voltage violations following local three-phase fault events.

Analysis: Transient voltage violations in the Boswell 230 kV Substation area were first identified in the MTEP16 stability assessment and are being monitored. A conceptual fast-switched capacitor bank was submitted as a potential Corrective Action Plan based on the limited information about the issue known at the time. 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 MTEP16 stability assessment. Minnesota Power is monitoring MTEP reliability assessment results to determine if and when a project is needed.

The table below identifies those projects by Tracking Number in the Northeast Zone that were listed as ongoing projects in the 2015 Biennial Report but have been completed or withdrawn since the 2015 Report was filed with the Minnesota Public Utilities Commission in November 2015. 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 2015 Report are not repeated here, but more information about those projects can be found in these earlier reports.

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

Project Description: Construct a 115 kV line from Brownton to McLeod 115 kV.

Need Driver: The Panther area is characterized by long 69 kV transmission lines from remote 115/69 kV sources with one 230/69 kV source (Panther) in the middle of the system. Although load growth in this area is slow, several relatively large spot loads are present (near Danube and Olivia). During the loss of the Panther 230/69 kV source or one of the 69 kV lines emanating from Panther, bus low voltage and line overloads occur.

The following are typical of the deficiencies in this area that could be expected based on the
summer peak conditions.

Alternatives: The following two alternatives were considered to address the low voltage and overload concerns in the area:

The first alternative will address the transformer overload concern, but will not address the low voltage problems at Hector. Alternative 2 is the preferred plan to address both the low voltage and overload concerns in the Panther area for a long-term.

Analysis: Doubling the Panther 230/69 kV transformer will only address the transformer overload, but it will not address low voltage problems. The Brownton 115/69 kV source instead will provide significant load serving reliability improvement by addressing both low voltage and overload problems in the system. It will also relieve loading from the Panther 230/69 kV and Franklin 115/69 kV transformers, sectionalize the extensive 69 kV system and make capacity available for future load growth in the 69 kV system.

Schedule: This project has been delayed indefinitely due to a drop in load growth. GRE continues to monitor the situation but there have not been any changes that would warrant proceeding with the project at this time.

General Impacts: The Panther Area Project is the most efficient solution that will address both the low voltage and transformer overload concerns in the area. The project also increases the overall load serving reliability of the 69 kV system.

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

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: Reconductor the Crooked Lake-Parkwood line to ACSS conductor and add a second 345/115 kV transformer at Elm Creek.

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.

General Impacts: The Elk River-Becker Area Project is the most efficient and least environmentally impactful viable solution for meeting the near term and long term needs in the area.

Project Description: Build a 115/69 kV substation to be named Priam three miles west of Willmar. Move the existing Willmar 115/69 kV transformer to the new Priam Substation.

Need Driver: This project provides a second delivery location to the City of Willmar.

These two options were not found to be the best value plan to Priam Substation plan.

Analysis: The project will move 115/69 kV transformer from the Willmar Substation to a new substation location about 3 miles west of Willmar, at the Priam Substation. The transformer will serve the same load that it now serves while at the Willmar Substation site. The separation of the two substations, however, provides better reliability to the system in such a way that a major outage causing event at Willmar Sub will not put both the 230/69 kV and 115/69 kV transformer out-of-service.

Schedule: This project is expected to be complete by summer 2019. The project schedule is being driven by land acquisition delays.

General Impacts: This project is the best value plan that will increase the reliability of the area served currently from the Willmar Substation.

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 will cause the current 115/41.6 kV Ortonville transformer to become overloaded and created reliability concerns.

Alternatives: Due to the small size of the project, little impact and low cost no alternatives were considered.

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: Currently the new Ortonville 115/41.6 kV transformer is scheduled to be replaced in the year 2020. However, faster or slower load growth could cause the date of the project to change.

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.

Need Driver: This project is needed to address contingency low voltage issues as well as transformer and 69 kV line overload concerns in the system.

Alternatives: The following are the alternatives considered in the study of this matter:

Analysis: The Riverview Road Substation will relieve system intact and contingency overloads in the 69 kV system. The project also addresses low voltage problems during critical contingencies in the system. As the project relieves loading from the Douglas County, Wakefield, Paynesville and West St. Cloud 115/69 kV transformers and it is directly sourced from a stiff 345 kV system, additional capacity will be available for reliable service to future load growth in the system.

Schedule: This project is expected to be complete by winter 2018. The project schedule is being driven by land acquisition delays.

General Impacts: The Riverview Road 345/115/69 kV Substation Project is the best value plan that will address the load serving problems in the 69 kV systems (bounded by Douglas County, Paynesville, Wakefield and West St. Cloud) for the long-term.

Project Description: Install 14.4 MVAR capacitor bank at GRE’s Benson Substation.

Need Driver: Contingencies in the transmission system while Benson Power is offline cause low voltage problems at multiple substation that are served from the Morris to Benson 115 kV transmission line. The capacitor bank is needed to alleviate the low voltage problems.

Alternatives: The first alternative is the Do Nothing Option. This option involves transferring of load to adjacent sources and shedding off load in the system for some transmission events. Load shedding is a violation of the NERC criteria for this outage scenario; therefore, this option wasn’t considered further. Installing SVC, synchronous condenser, a 230/115 kV substation by Benson and bringing 115 kV line from Paynesville, Appleton, or Alexandria were considered as alternatives. These alternates were not considered as they are costly and can’t be put in place in relatively short period to time.

Analysis: The simulation results show that the preferred capacitor bank size that can be switched in with a capacitor-switcher is 14.4 MVAR. Switching this capacitor bank requires a cap-switcher with 250Ω pre-insertion resistor. The cap-switcher manufacturer should review the resistor value to determine the optimum resistor size.

Schedule: The Benson capacitor bank is scheduled to be in-service in December 2017.

General Impacts: The Benson Capacitor Bank Project is the best value plan that will address the low voltage problems in the Benson area.

Project Description: Construct 0.2 mile, in/out, 115 kV line from NSP’s Big Swan to Crow River 115 kV line with 795 ACSS conductor to interconnect Wright-Hennepin Cooperative Electric Association’s (WHECA) Brooks Lake Distribution Substation. GRE will construct the high side, and install two 2000A, 115 kV load break switches and metering equipment at WHECA’s Brooks Lake Substation.

Need Driver: Existing substations are determined not capable of serving growing load in the Brooks Lake area including the expected expansion of WHECA’s largest load customer in the area. The Brooks Lake Distribution Substation will serve growing loads in the Brooks Lake area and unload nearby distribution substations that are reaching capacity. Brooks Lake will also provide contingency back-feed to nearby substations.

Alternatives: WHECA considered upgrading existing feeders to provide service to growing loads in the Brooks Lake area. This option, however, is not chosen as the expected load growth is too large to serve with upgraded feeders.

Analysis: The magnitude of the local load growth requires a new distribution substation.

Schedule: The Brooks Lake 115 kV Distribution Substation Project is scheduled to be in service by summer 2019.

General Impacts: The Brooks Lake 115 kV Distribution Substation Project is the least impact solution to serving the local area load reliably.

Project Description: Install a 3-way, 115 kV switch on GRE’s AG-BK line and construct about 3 mile of 115 kV line with 477 ACSR conductor from the new 3-way switch to Agralite Electric Cooperative (AEC) Cashel West Distribution Substation.

Need Driver: AEC needs Cashel West Substation to serve a new spot load of 2 MW and pick up additional load that is now served from the Cashel Substation.

Alternatives: AEC examined the possibility of upgrading the Cashel Substation as opposed to building a new one, but it was quickly ruled out. The Cashel Substation is an all wood structure substation that was built in 1958. The largest obstacle to upgrading or keeping this substation in the location where it is situated is its proximity to a river. Cashel Substation sits in a low spot approximately 200 feet from a creek. AEC has experienced flooding in this substation from this creek before. AEC also has concerns in regard to environmental issues related to oil spills given the close proximity of the creek. The elevation difference between the substation surface and the road makes it extremely difficult to safely move heavy equipment in an out of the substation. An upgrade to this substation would involve a new transformer, bus upgrades, regulators upgrades, new recloser, and a feeder upgrade. Given the aforementioned issues, AEC does not feel upgrading this substation in its current location is a good investment of funds.

Analysis: A new spot load in the area requires electric service from an existing substation, or a new substation, the Cashel Substation that exists in the area doesn’t have capacity to serve the 2 MW spot load in the area. In addition, the existing substation is scheduled for retirement in 2019 due to age and condition of the substation. A new substation has to be constructed in the area to serve the 2 MW spot load in the Cashel West area.

General Impacts: The Cashel West Distribution Substation will have sufficient capacity to serve the spot load and growing loads in the area reliably. This substation facilitates the retirement of the existing Cashel Substation that has had reliability concerns. It is also the least environmentally impactful solution to serve the new load and address concerns related to the Cashel Substation.

Project Description: Install a 3-way 115 kV switch on GRE’s AG-BK line, and construct about one span of 115 kV line with 477 ACSR conductor from the new 3-way switch to Agralite Electric Cooperative (AEC) Cashel East Distribution Substation.

Need Driver: AEC needs to construct the Cashel East Substation to serve all the Cashel Substation load that will not be served from Cashel West Substation, provide contingency back to the Cashel West Substation, and facilitate the retirement of the Cashel Substation. Cashel Substation will be retired due to age and condition.

Alternative: The alternative to keep the Cashel Substation instead of constructing a new substation was not considered further as the existing Cashel Substation is deemed not reliable due to its age and condition. In addition, AEC has concerns in regard to environmental issues related to oil spills given the close proximity of the creek to the substation.

Analysis: The Cashel East Substation will increase load serving reliability in the area. As it facilitates the retirement of the existing Cashel Substation, it addresses environmental concerns that is related to the Cashel Substation.

General Impact: The Cashel East Substation will provide a reliable electric service to the area that is now served from the Cashel Substation. Contingency back feed between Cashel East and Cashel West Substation will bring better service reliability than that currently exists.

Project Description: Rebuild GRE’s existing 69 kV transmission line from Willmar to Litchfield Muni Tap to 115 kV standard with 795 ACSR conductor for continues operation at 69 kV.

Need Driver: GRE’s Willmar to Litchfield Muni Tap 69 kV line (DS line) is one of the oldest 69 kV transmission lines in the area. It is in need of a replacement due its age and condition. In addition, this transmission line provides support to a large load center at Litchfield Muni. System analysis shows the existing transmission system doesn’t have margin to serve new or growing loads in the Litchfield area within the required voltage criteria. In order to improve system voltage, and address reliability concerns due to the transmission line age and condition, GRE will rebuild the transmission line. Better system reliability and load serving performance will be gained in this area with 115 kV transmission line that extends between Willmar and Big Swan area. As a result, GRE will rebuild the DS line to 115 kV standard, but will continue to operate the line at 69 kV until the need to operate the transmission line at 115 kV is justifiable in the future.

Alternative: The driver for the line rebuild is mostly age and condition of the transmission line. GRE could rebuild the transmission line to 69 kV standard, but this will limit the load serving capacity of the transmission system in the Litchfield area. Rebuilding the line to 115 kV at a later date will also be costly.

Analysis: The DS Line Rebuild Project brings efficiency improvement as there will be less power loss on the transmission line. It also provide better load serving reliability as it will be new, and construction of the line will be done to the 115 kV standard. The line rebuild makes capacity available in the transmission system for a new load that may come to the areas that are served from the DS line.

Schedule: The schedule for the line rebuild is currently unknown. GRE is in the process of getting this project scheduled.

General Impact: The DS Line Rebuild Project reduces power loss on the transmission system and fosters economic development. It is also the least environmentally impactful viable solution to address age and condition the DS line.

The table below identifies those projects by Tracking Number in the West Central Zone that were listed as ongoing projects in the 2015 Biennial Report but have been completed or withdrawn since the 2015 Report was filed with the Minnesota Public Utilities Commission in November 2015. 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 2015 Report are not repeated here, but more information about those projects can be found in these earlier reports.

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

MPUC Tracking Number	MISO Project Name	MTEP Year/App	MTEP Project Number	CON?	Utility
2017-TC-N1	Airport-Rogers Lake 115 kV Rebuild	2016/B>A	10074	No	XEL
2017-TC-N2	City of Chaska Interconnection	2016/B>A	10045	No	XEL
2017-TC-N3	Southtown Area Upgrades	2016/B>A	10066	No	XEL
2017-TC-N4	Black Dog-Wilson 115 kV Uprate	2017/C>A	11993	No	XEL
2017-TC-N5	Wilson Substation	2017/C>A	4695	No	XEL
2017-TC-N6	Plymouth-Area Power Upgrade	2018/C>A	14054	No	XEL
2017-TC-N7	Lebanon Hills 115 kV	2018/C>A	12211	No	GRE

Project Description: Rebuild the existing 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: 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.

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

General Impacts: This line crosses the Mississippi River, multiple lakes, two cemeteries, three highways, and an interstate, so the permitting process is expected to be very involved and time consuming. Otherwise, this project is a replacement of what exists today.

Project Description: The City of Chaska will build a new distribution substation tapping Xcel Energy’s 115 kV line from Bluff Creek and Scott County. Xcel Energy will build and own the 115 kV side of the new substation.

Analysis: The City of Chaska is planning on serving their complete load from the new substation. This substation will also accommodate future load growth in the City of Chaska.

General Impacts: The project is expected to cost $3.2M and be in-service in 2018.

Project Description: Upgrade the Southtown-Cedarvale 115 kV line to a minimum of 290 MVA emergency rating. Upgrade the Southtown-Shepard 115 kV line to a minimum of 270 MVA emergency rating. Add an 80 MVAR cap to the Hiawatha Substation.

Need Driver: Local load growth in the southeast Minneapolis area causes thermal overloads and voltage violations under certain contingencies.

Alternatives: Bring a new 115 kV line into the new Midtown Substation from western Twin Cities.

Analysis: This project is needed due to the load growth in the area under certain contingencies causing thermal overloads and voltage issues. These projects will address all the thermal and voltage issues in the area.

Schedule: The majority of this project is already complete with the remainder being completed by the end of 2017. The work took approximately two years to complete and used Xcel Energy employees.

General Impacts: This project will use existing right of way and substation land. The cost estimate is approximately $3.2M and has a targeted in-service date end of 2017.

Project Description: This project is to uprate the existing 115 kV lines from the Black Dog Substation to the Wilson Substation.

Need Driver: Load has continued to grow in the southern metro area putting additional pressure on the existing facilities to continue to serve the load reliably. Under certain conditions the existing 115 kV lines from Black Dog-Wilson #1 and #3 are likely to be overloaded in the 2020 summer peak cases.

Alternatives: Alternative 1 was to build a 4th 115 kV line from Black Dog-Wilson. This option was shown infeasible due to a new river crossing and the difficulty in getting into the Wilson Substation due to the line congestion and the location of the substation.

Alternative 2 was to convert the Black Dog Substation to breaker-and-½. This option was shown to be a very expensive solution as most of the existing Black Dog Substation would have to be rebuilt to accommodate this solution.

Analysis: This project is needed due to the load growth in the area under certain contingencies causing thermal overloads. Under certain contingencies Black Dog generation would have to be reduced to prevent overloading the 115 kV lines feeding the Bloomington/494 area.

Schedule: The work will take approximately two years to complete and used Xcel Energy employees.

General Impacts: This project will use existing right of way and substation land. The cost estimate is approximately $4.2M and has a targeted in-service date of summer 2019.

Project Description: Convert the existing Wilson Substation from a straight bus configuration to a breaker-and-½ configuration.

Need Driver: This project is needed to interconnect a 4th distribution transformer at Wilson Substation, remove a three terminal line, and add flexibility for real time operations and maintenance.

Alternatives: An alternative to this project is a new substation in the area and new transmission lines to the new substation. This area is already very congested and routing new transmission lines would be very difficult.

Analysis: This project is needed due to the load growth in the area and to address the lack of load serving flexibility in the area. This substation is one of the largest substations on the Xcel Energy system with a straight bus design; the breaker-and-½ design will address load serving concerns in this area.

Schedule: The work will take approximately two years to complete and use Xcel Energy employees.

General Impacts: This project will use existing substation land. The cost estimate is approximately $17M and has a targeted in-service date of summer 2020.

Project Description: This project includes the rebuild of the existing Parkers Lake to Gleason Lake 115 kV double circuit line into two single circuit lines in the same right of way and installation of a 40 MVAR capacitor bank at Gleason Lake. Additionally, this project constructs a new substation called Pomerleau Lake, located on the Parkers Lake to Plymouth 115 kV line, re-energizes the existing Hollydale to Plymouth 69 kV line, and re-terminate that 69 kV line into Pomerleau Lake Substation. Finally, the Hollydale Substation will be expanded to accommodate serving load from 69 kV on a permanent basis.

Need Driver: Regular load growth in the area in and around Plymouth has required the need for the project. The City of Plymouth asked for a long term solution in this area after extensive public input. This set of projects was the result of this public input.

Alternatives: This project has gone through many years of public involvement and included many alternatives. The project listed above is the project that came out of all of this public involvement.

Analysis: This project is needed due to the load growth in the area under certain contingencies causing voltage and thermal violations. Assuming normal load growth in the Plymouth area, the project as listed above should mitigate these load serving violations for at least the next 20 years.

Schedule: While this project will occur in phases, the entire project is planned to be in-service by summer of 2020.

General Impacts: The public process that was followed to establish this as the preferred project considered various potential impacts of various alternatives, and this was the preferred project.

Project Description: Build 1.25 miles of double circuit 115 kV transmission line to the Dakota Electric Association Lebanon Hills Substation.

Need Driver: The Lebanon Hills Distribution Substation is served on the 69 kV system from Inver Grove source with a contingency back up from the Pilot Knob Substation. The future plan of the area involves reconfiguration of the Pilot Knob Substation and the transmission system in the area. The Pilot Knob Substation will be reconfigured in such a way that the 115 kV side will have a breaker-and-½ design and the 69 kV side is a simpler straight bus configuration. The transmission system reconfiguration involves overheading the underground cables towards Deerwood and Lemay Lake and retirements of the DA-PKX, DA-RE, DA-LE, DA-LEX and DA-LK lines. With this future plan, the Lebanon Hills Substation will be better served from the 115 kV system in the area.

The Pilot Knob Substation consists of breakers and transformers that are old and have been failing. Breaker and underground cable pot head replacement projects were done in the past. Remaining breakers and pot heads will continue to be sources of failure that could cause outages in area. In additions, the transformers are old and are likely to fail causing extended outage at the substation. Replacements of these equipment at Pilot Knob Substation are efficient as the substation can be reconfigured in to a more reliable configuration that is up to GRE’s current substation design standard. This proposed Pilot Knob reconfiguration project, in a long run, saves on cost of equipment replacement and frequent maintenance while resulting in a more reliable transmission system in the area. The Lebanon Hills Substation conversion to the 115 kV system is among few projects that need to be completed before the start of Pilot Knob reconfiguration project.

Alternative: Continued 69 kV service for Lebanon Hills-this option makes service to Lebanon Hills unreliable after the proposed configuration of the Pilot Knob Substation. The proposed configuration will retire the underground 69 kV line out of Pilot Knob to Pilot Knob Tap and the line from Pilot Knob Tap that connects to Lebanon Hills. Therefore, Lebanon Hills will depend on service from Chub Lake during contingencies along the Inver Grove to Lebanon Hills 69 kV line. This causes low voltage at Lebanon Hills.

Keep the underground 69 kV line from Pilot Knob to Pilot Knob Tap and use it for contingency backup for Lebanon Hills. The underground 69 kV lines out of Pilot Knob that connects to Pilot Knob Tap have had historical reliability concerns related to the underground cable pot head failures. The line termination breakers are also old and there is not much service life left in them. In addition, part of Pilot Knob Substation reconfiguration plan involves elimination of these underground cables and line termination breakers. Therefore this option wasn’t considered further as these lines won’t be available when the Pilot Knob area is reconfigured. This is also inefficient and costly in a long run in terms of reliability and replacement cost of pot heads.

Analysis: The 69 kV transmission system that serves the Lebanon Hills Substation consists of high impedance conductors. As a result, power loss on the 69 kV system is significant with Lebanon Hills served from the 69 kV system. In addition to the added reliability improvement from serving Lebanon Hills on the stronger 115 kV system, conversion of the Lebanon Hills to the 115 kV system will have financial benefit in relation to loss saving in a long run.

Schedule: The Lebanon Hills 115 kV Project is scheduled to be in service by summer 2020.

General Impact: The Lebanon Hills 115 kV Project is the least impact solution to serving the local area load reliably.

The table below identifies those projects by Tracking Number in the Twin Cities Zone that were listed as ongoing projects in the 2015 Biennial Report but have been completed or withdrawn since the 2015 Report was filed with the Public Utilities Commission in November 2015. 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 2015 Report are not repeated here, but more information about those projects can be found in these earlier reports.

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

Heron Lake Capacitors

Need Driver: Low voltage in the Heron Lake area requires the addition of a 42 MVAR capacitor bank at the Heron Lake 161 kV Substation. The addition of the capacitor bank will require rebuild of Heron Lake Substation to a breaker-and-½ configuration.

Alternatives Considered: The capacitor bank was the only alternative evaluated. Expansion of the transmission system in the area would have been a more costly alternative.

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. The capacitor bank will help support system voltage. The existing facility is not able to accommodate the capacitor bank. The 161 kV substation will be constructed in a breaker-and-½ configuration, which will require expansion of the existing facility.

Schedule: It is expected that the project would be complete by December 2022.

General Impacts: The capacitor bank addition will increase reliability by adding voltage support for the area. Site expansion will be coordinated with local authorities and landowners to minimize impacts.

MVP #3

Project Description: MVP #3 is a new 345 kV path from that will begin at Lakefield Junction in Jackson County and continue through Martin County to Faribault County near Winnebago Junction, then continue south into Iowa. In conjunction with MVP #4, a new 345 kV network will connect Lakefield Junction to multiple points on the existing 345 kV system in Iowa.

Need Driver: MVP #3 is part of a portfolio of transmission expansion projects that were developed to address public policy while also addressing reliability and economic needs of the system. The portfolio of projects was approved by MISO in 2011, and triennial reviews have occurred in 2014 and 2017. The 2017 triennial review estimated a benefit to cost ratio of 2.2 to 3.4, identified $12-$52.6 billion in net benefits over the next 20 to 40 years and also identified enablement of 52.8 million MWh of wind energy to meet renewable energy mandates and goals through year 2031. The MVP analysis and triennial review reports can be found at

Analysis: MVP #3 is a portion of multiple high voltage projects that were developed through multiple years of analysis with the cooperation of MISO and Transmission Planning personnel from utilities across the MISO footprint. Details of the analysis can be found in the MTEP11 report. Triennial reviews of the MVPs are also provided as part of the MTEP14 and MTEP17 reports.

General Impacts: The Department of Commerce prepared an Environmental Impact Statement on this project, which was finalized on July 11, 2014. The Public Utilities Commission found, on November 25, 2014, that the EIS and the record in the matter were adequate, and that the project would provide benefits to society in a manner compatible with protecting natural and socioeconomic environments, including human health.

Project Description: Plan is to cutover the existing Buffalo Ridge feeder 321 to Yankee by building 2 miles of new 34.5 kV line. Will require installation of a 3rd 115/34.5 kV transformer and 115 kV breaker addition/s at Yankee.

Need Driver: Existing Feeder 321 is susceptible to voltage instability during high wind output from the Alpha and Zulu wind farms. Additionally the Buffalo Ridge 115/34.5 kV transformer #2 could overload during high wind conditions under contingency.

Alternatives: An alternative proposal was to install a 25 MVAR STATCOM at the end of the 321 feeder and curtail wind under contingency.

Analysis: This project will decrease the wind farm feeder length from approximately twenty miles to approximately seven miles by tying into the Yankee Substation. Shortening the feeder length will correct the voltage instability issue at the Alpha and Zulu wind farms and the reduction of wind output on the Buffalo Ridge feeders will fix the overloading issue. This project will likely be constructed by Xcel Energy employees.

Schedule: This project is scheduled to begin in 2019 with a completion date of early 2020.

General Impacts: The substation portion of the project will be contained in the existing Yankee Substation and will not require expanding the substation site. This project will require some new 34.5 kV line extension to complete the cutover to from Buffalo Ridge to Yankee. Xcel Energy construction crews are expected to perform the work.

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: 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.

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 2019.

General Impacts: The rebuild will occur on existing right of way in order to minimize impacts. The rebuild will increase the reliability of electric service in the area.

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

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

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 2019.

General Impacts: The rebuild will occur on existing right of way in order to minimize impacts. The rebuild will increase the reliability of electric service in the area.

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.

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 2020.

General Impacts: The rebuild will occur on existing right of way in order to minimize impacts. The rebuild will increase the reliability of electric service in the area.

The table below identifies those projects by Tracking Number in the Southwest Zone that were listed as ongoing projects in the 2015 Biennial Report but have been completed or withdrawn since the 2015 Report was filed with the Minnesota Public Utilities Commission in November 2015. 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 2015 Report are not repeated here, but more information about those projects can be found in these earlier reports.

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

Project Description: Re-build 13 miles of 69 kV line from Arlington-Green Isle in existing right of way.

Need Driver: This line was flagged during the CapX study as an underlying facility that needed upgrading. With the loss of the CapX lines under high transfers this 69 kV line will overload.

Alternatives: Adding additional transmission lines would mitigate this issue but would require far greater cost and land usage.

Analysis: This project will have the associated construction projects by Xcel Energy employees. This project will help maintain local reliability and uses existing right of way to minimize impact.

Schedule: The line rebuild was not a part of the 2015, five-year budget. The rebuild of the line expected to occur within approximately 6-7 years.

General Impacts: Replacement of the line will provide for additional system capacity and reduce maintenance cost on the existing, aging infrastructure.

Project Description: Build new substations to feed load growth in the Victoria/Chaska area. A single distribution transformer will be installed with an “in and out” configuration on the 115 kV.

Need Driver: This is a distribution driven project. The existing distribution system in the area has reached its limits and requires an additional source. This new substation will offload West Waconia and Westgate substations.

Alternatives: Many locations were considered for this new substation. Adding this load onto the existing 69 kV in the area will not work as the line cannot handle that amount of load growth. Additional 115 kV locations were found to work from a transmission perspective, but the selected location minimizes feeder lengths.

Analysis: This project will have the associated construction projects by Xcel Energy and GRE employees. This will help enable local load growth. Our team worked closely with local community to minimize substation footprint.

General Impacts: This project will have the associated construction conducted by Xcel Energy and GRE employees. This will help enable local load growth. The team will work closely with local community to minimize substation footprint.

Project Description: Rebuild 3.6 miles of 0714 69 kV line from Madelia Switching Station to Village of Madelia to 336 ACSR.

Need Driver: With the loss of both 345 kV lines heading into Wilmarth, this line will overload. Rebuilding it to a higher ampacity mitigates the issue.

Alternatives: Alternatives would have been more costly and environmentally impactful. Such alternatives include construction of a new transmission line which would have required additional land and right of way.

Analysis: This project will have associated construction jobs. This project will help maintain local reliability and uses existing right of way to minimize impact.

Schedule: Project is currently underway. Construction began in 2015 and should be completed by June 1, 2019.

General Impacts: This project will have associated construction jobs. This project will help maintain local reliability and uses existing right of way to minimize impact.

Project Description: Rebuild 5.3 miles of DPC’s Twin Lakes-Freeborn 69 kV line between DPC’s Alden and Mansfield distribution substations, improving reliability to all three distribution substations on this line which was originally constructed in 1951.

Need Driver: This 69 kV line was built in 1951 and increased maintenance costs have required that this line be rebuilt due to age and condition. The line also has some long spans that can be prone to galloping due to high winds.

Alternatives: The primary need driver is age and condition issues resulting in reliability concerns. Because of this need, the only alternative that was considered is a rebuild of the existing line. An alternative on new right-of-way was not considered as this line serves several distribution substations and new right-of-way would present routing difficulties and a higher cost.

Analysis: The plan to replace the existing 64-year-old transmission line with new poles, conductor and shield wire will solve the reliability concern caused be the age and condition of the existing transmission line serving Mansfield, Alden and Freeborn distribution substations. The estimated cost is approximately $1.5M and has a targeted in-service date of 2018.

Schedule: Construction would occur September-November 2018.
General Impacts: Dairyland construction crews will rebuild this line in 2018 requiring approximately ten weeks to construct. This 69 kV line follows a road, resulting in minimal impacts to the local right-of-way.

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: A rebuild on existing ROW was the sole alternative considered to solve the age and condition issue.

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. 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 2019.

General Impacts: The line is near the end of its useful life. The capacity of the line will be increased to approximately 77 MVA with the rebuild.

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: Rebuilding the line to a greater capacity on existing ROW was the sole alternative considered to alleviate the system capacity constraint.

Analysis: 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.

Schedule: The rebuild of the line is expected to occur within approximately 5-6 years.

General Impacts: Replacement of the line will provide for additional system capacity and reduce maintenance cost on the existing, aging infrastructure.

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: 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.

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. Further, MISO has found that this project does create unintended reliability issues for the transmission system.

Schedule: Planned in service date is 2022. A certificate of need application is anticipated for early 2018.

General Impacts: This project will utilize the existing Wilmarth and Huntley substations. New 345 kV right will need to be acquired to construct the new 345 kV circuit. Siting will be coordinated with the appropriate landowners, local, state, and federal authorities.

Project Description: Upgrade Winona and Goodview bus. Reconfigure normally open from Merrick to Goodview, normally open from Goodview 1 to Goodview 2, normally closed from Winona Tap to Goodview Tap. Install remote operators at Winona Tap.

Need Driver: With the loss of both 161 kV lines heading into Marshland, potential voltage collapse will occur in the Bluff Siding area including Goodview and Winona.

Alternatives: Alternatives would have been more costly and environmentally impactful. Such alternatives include construction of a new transmission line which would have required expanding existing right of way and a new breaker station at existing Winona Tap.

Analysis: This project will have associated construction jobs. This project will help maintain local reliability and uses existing facilities to minimize impact.

General Impacts: This project will have associated construction jobs. This project will help maintain local reliability and uses existing facilities to minimize impact.

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 constraint as part of the MISO generation interconnection queue process. MISO studied the interconnection of a 202 MW wind farm in Mitchell County, Iowa with MISO queue number J449. The study identified the Rochester-Wabaco 161 kV line as requiring a higher capacity in order to allow the wind farm to connect to the transmission system.

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.

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 capacity issues as determined by MISO. This will allow for the connection of a new 202 MW wind farm to the transmission system. The wind farm will fund the upgrade and it has a targeted in-service date of October 2018.

General Impacts: Dairyland construction crews will rebuild this line in 2018 requiring approximately sixteen weeks to construct. The upgraded line will add to the capacity of the transmission system allowing a new wind farm to connect to the transmission system.

Project Description: The project calls for the Huntley to Freeborn 161 kV line to be tapped approximately 14 miles west of Freeborn and an approximately 7 miles-long 161 kV line to be routed to the Walters Substation. The Walters Substation would be expanded and upgraded in order 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: 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.

Analysis: The new substation at Walters 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 Walters 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 the end of December 2018.
General Impacts: The seven mile long 169 kV line will seek to utilize existing rights of way, and the upgrade will help support area voltage and provide a new 161 kV source for future needs. Line routing and facilities siting will be coordinated with necessary local, state and federal authorities.

Project Description: The Winnebago Junction 69 kV Substation facilities are being relocated to Huntley 69 kV Substation in conjunction with construction of the Huntley 345/161 kV Substation for MVP #3 (Tracking Number 2013-SW-N4). One of the two transformers at Winnebago Junction will be relocated to Huntley, and one of the 161/69 kV transformers will not. One of the two transformers is being replaced by a 75 MVA unit that was previously replaced at Adams Substation. Winnebago Junction Substation will be retired after Huntley is placed in service.

Need Driver: The Winnebago Junction 69 kV facilities’ age and condition and increased maintenance costs warranted relocation of the 69 kV facilities to the new Huntley Substation, which is being constructed under the scope of work for MVP #3 (Tracking Number 2013-SW-N4). One of the 161/69 kV transformers is in poor condition, and it will be replaced with a unit previously in service at Adams Substation.

Alternatives: Rebuilding facilities at the existing Winnebago Junction was considered, but relocating the 69 kV to new facilities was the preferred solution.

Analysis: Rebuilding 69 kV facilities at the existing Winnebago Junction site after retirement of 161 kV facilities would require extensive work and outages, and costs for maintaining facilities at Winnebago Junction warranted the establishment of new 69 kV facilities at the new Huntley Substation.

Schedule: Construction and relocation of facilities is expected to be completed by the end of 2017.

General Impacts: Existing facilities and rights of way were utilized for new facilities to the extent practical, and construction of new facilities is being coordinated with local, state, and federal authorities and with the cooperation of landowners.

Project Description: Expand the 161 kV ring bus at Glenworth by adding a 161 kV breaker and new terminal for the interconnection of a 200 MW wind-powered generating facility and replace the existing 100 MVA, 161/69 kV transformer with an 150 MVA unit.

Need Driver: The expansion of Glenworth and the replacement of the existing 100 MVA transformer with a 150 MVA unit are required for the Interconnection Service for project J407 under the MISO Tariff.

Alternatives: The interconnection was evaluated under the MISO’s DPP February 2015 system impact study. No alternatives for the interconnection or the overload of the transformer were identified.

Analysis: The interconnection of project J407 was evaluated as part of the MISO February 2015 system impact study. The expansion of facilities at Glenworth are required to provide a point of interconnection for project J407, and the transformer was shown to overload under contingency with the interconnection of project J407 to Glenworth.

General Impacts: The upgrades will occur within the existing Glenworth 161 kV Substation. Termination of the J407 generator tie line will be coordinated with the interconnection customer and necessary authorities.

The table below identifies those projects by Tracking Number in the Southeast Zone that were listed as ongoing projects in the 2015 Biennial Report but have been completed or withdrawn since the 2015 Report was filed with the Minnesota Public Utilities Commission in November 2015. 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 2015 Report are not repeated here, but more information about those projects can be found in these earlier reports.

6.0 Needs

6.1 Introduction

6.1.1 Needed Projects

6.1.2 Description of Each Project by Tracking Number

6.1.3 Completed Projects

6.2 The MISO Planning Process

6.2.1 The MISO Transmission Expansion Plan Report

6.2.2 Finding a Project in a MTEP Report

6.3 Northwest Zone

6.3.1 Needed Projects

Clearbrook 115 kV-Bagley West 230 kV

Bagley North 115 kV Ring Bus

Moranville 230/69 kV Transformer Replacement

Ulrich 115/69 kV Transformer Replacement

Richwood-Oakland 69 and Audubon-Erie Junction 41.6 kV Lines (Load Transfers)

Thief River Falls 115 kV Capacitor Bank Addition

Lake Park Substation

Itasca-MPL Laporte 115 kV Line (and Northwoods Circuit Breaker Addition)

Thief River Falls-Plummer Pipe 115 kV Line Uprate

Donaldson 115 kV Capacitor Bank Addition

6.3.2 Completed Projects

6.4 Northeast Zone

6.4.1 Needed Projects

6.4.2 Completed Projects

6.5 West Central Zone

6.5.1 Needed Projects

6.5.2 Completed Projects

6.6 Twin Cities Zone

6.6.1 Needed Projects

6.7 Southwest Zone

6.7.1 Needed Projects

Heron Lake Capacitors

MVP #3

6.7.2 Completed Projects

6.8 Southeast Zone

6.8.1 Needed Projects

6.8.2 Completed Projects