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.

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 2013-NE-N1, for example, indicates that this matter is first reported in the 2013 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 MTEP15, 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. There are several Minnkota projects reported for the Northwest Zone for which there is no link to a MISO Project Number of a MTEP Report. All other projects are being considered by utilities that are members of MISO and both a project number and a MTEP reference are provided.

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.

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

In the 2005, 2007, and 2009 Biennial Reports, the utilities provided a separate subsection for each pending project by Tracking Number and included certain information about each project. In the 2011 and 2013 Report, those discussions were eliminated because the Commission had understandably authorized the utilities to rely on the MTEP Reports to provide all the necessary information regarding each project because transmission 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 2011 and 2013 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 MTEP 15 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 C, and then they move up to Appendix B and 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 2015-WC-N4 is used for illustrative purposes):

MPUC Tracking Number 2015-WC-N4 is the Douglas County – West Union 69 kV Line Rebuild, an Xcel project in Douglas County. The project can be found in Appendix A of the MTEP14 Report by following these steps:

Similar steps can be followed for all other projects identified in Chapter 6, including those few that are not Appendix A projects (recommended by MISO for approval). If the MTEP Report you are seeking is an older one, 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 Douglas County – West Union 69KV Line rebuild, Tracking Number 2015-WC-N4, 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).

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. Note that Minnkota Power Cooperative is not a member of MISO. The Minnkota projects are tracking numbers 2015-NW-N1 to 2015-NW-N6.

Utilities: Minnkota Power Cooperative (MPC) and 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.

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.

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 must be completed by the winter of 2023. This date is a revised date from the initial draft of the "High Voltage Study" report, and the revised date came from the "Winger – Thief River Falls Timing Analysis." A more definitive 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 741 acres, only 65 acres will actually be impacted.

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

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 Jct 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 2020 completion.

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

Schedule: The Schuster Lake project is currently planned for a 2020 completion.

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

Clearbrook West 115 kV-Bagley West 230 kV

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

Project Description: 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 16 mile line from the newly developed substation to the Clearbrook West 115 kV substation (as identified in 2015-NW-N3).

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 16 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 (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 16 mile line from the newly developed substation to the Clearbrook West 115 kV substation (as identified in 2015-NW-N3). 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," which was performed primarily by OTP. Of the options analyzed, the Clearbrook West 115 kV to Bagley West 230 kV option provided the best transmission option that met our transmission requirements. The study demonstrated a final upgrade requirement of looped service, to be completed by 2018.

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 2018. A schedule will be developed as definite mitigation plans are determined.

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, 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 July of 2016.

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.

Project Description: Due to the development of a new pump station load near Clearbrook, a new load service needed to be established. Since the forecast provided by the customer was beyond the availability of existing transmission facilities (41.6 kV transmission), the load service was specified for 115 kV. This required a new transmission line from a nearby 115 kV substation at Clearbrook (about 6 miles of line to the southeast), as well as a newly developed substation for service to the Clearbrook West pump station load

Need Driver: The Clearbrook area is a developing hub of crude oil pipelines, and those pipelines require pumping stations. A new pumping station is developing northwest of Clearbrook, 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 6-mile transmission line and a new substation.

Alternatives: There was one transmission alternatives that was considered as part of this load interconnection, and that alternative involved interconnection on Ottertail's 41.6 kV system.

The 41.6 kV option was considered and compared with the 115 kV option, and it was determined that the 41.6 kV option would not be capable of the full customer demand after full development. Also, a 115 kV interconnection is more robust and energy efficient than the 41.6 kV option.

Analysis: Reliability impacts from the new load interconnection were evaluated in the "Study for New Pumping Station Load," which was performed by MPC. The study showed that a fault on one of the two 115 kV lines that serve the Clearbrook area caused overloads on the other 115 kV line during peak conditions (this also assumed that the Solway peaking generator is offline). The study demonstrated a final requirement of 150 MVA in line upgrades and 40 MVAR in capacitor bank additions, but those additional upgrades were later replaced by the MPUC project 2015-NW-N1, which includes a new 230 kV source at Clearbrook to be completed by 2018.

Schedule: The study efforts mentioned above determined that the new load interconnection must be completed by the fall of 2017. A schedule will be developed as definite plans are determined.

General Impacts: This project is primarily rural in location. The route will have to navigate around some lakes within the area. Assuming a one hundred foot right-of-way, the project area will be nearly 73 acres, but the affected farmland should only be about 4 acres, assuming some general estimates on electrical poles and farmland equipment navigation. The project may follow some nearby roads to some existing pump stations, farmsteads, and the Clearbrook–Gonvick School District. This project is still in its early stages of planning, so all of this information is subject to change.

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. 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 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 4 acres, as stated in the environmental considerations.

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 being proposed 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 aren't 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 must be completed by the winter of 2017. A schedule will be developed as that timeframe approaches.

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 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.

Ulrich 115/69 kV Transformer Replacement

Project Description: To keep up with the changes on this substations native demand, a new 115/69 kV transformer, as well as a new capacitor bank, is being proposed for installation at the Ulrich substation.

Need Driver: The Ulrich area load is approaching the thermal limitations of the existing transformer. In additions to the current load topology, a load that is currently served by a neighboring utility will soon be transferred to the Ulrich source. To keep up with the changes on this substations native demand, a new 115/69 kV transformer, as well as a new capacitor bank, is being proposed for installation at the Ulrich substation.

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. Future transmission upgrades and ensuing load transfers also create some concerns during system intact conditions. 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 system intact conditions or a contingency. The transformer replacement is also a more robust and energy efficient option.

Analysis: There aren't any negative reliability impacts due to the transformer replacement and capacitor bank addition. This is primarily a capacity uprate.

Schedule: The study efforts mentioned above determined that the transformer replacement must be completed by the winter of 2018. 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 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.

Anderson/Thief River Falls Tap-New Thief River Falls Substation 115 kV Line (Load Tap/Transfer)

Project Description: A new load tap on the 115 kV system has been deemed necessary to meet the demand for more power from a member utility. The proposed load tap facilities include a 1.5 mile transmission line and a new substation.

Need Driver: One of MPC's utility members has reported that a new load tap is being planned for the Thief River Falls area. According to this report, the existing source is expected to be insufficient for the customer's expected demand.

Alternatives: There is a transmission alternative being considered as part of this load tap, and the alternative involves further investigation of the existing substation at Thief River Falls. The investigation is ongoing, and it will be compared with the 115 kV load tap option. To properly address this transmission request, a 115 kV load tap is the current transmission plan, but it may be changed if the investigation provides an equally cost effective project that is robust.

Analysis: Reliability impacts from the new load tap are currently evaluated in the annual TPL assessments (in terms of forecasting the existing Thief River Falls area loads). Impacts to the bulk power system are not the reason for this transmission project. Limitations of the existing substation are the reason for this transmission project. The load tap is to be completed by 2019.

Schedule: The study efforts mentioned above determined that the new load tap must be completed by the winter of 2019. A schedule will be developed as definite plans are determined.

General Impacts: This project is almost entirely urban in location. The route will have to avoid the nearby river within the area. Assuming a one hundred foot right-of-way, the project area will be nearly 18 acres, but the affected city area should only be about one acre, assuming some general estimates on electrical poles and clearance for navigation, similar to the farmland navigation. The project may follow some nearby roads to existing industrial locations and/or residences. 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 recent hospital development, but it will probably not have any additional impact on the community in terms of population or other social characteristics. It will likely impact some city area; however, it should only amount to about one acre, as stated in the environmental considerations.

Mahnomen/Ulrich Tap-Existing White Earth Substation 115 kV Line (Load Tap/Transfer)

Project Description: A new transmission line and substation modifications are being planned for the White Earth substation. A new load tap on the 115 kV (or 69 kV) system has been deemed necessary. The proposed load tap facilities include a 6-9 mile transmission line (only 3-6 miles of it will be completely new) and substation modifications to the existing White Earth substation.

Need Driver: In response to a neighboring system's request, a new transmission line and substation modifications are being planned for the White Earth substation. According to this request, the existing source is expected to be insufficient for the customer's expected demand during a contingency. As a result, a new load tap on the 115 kV (or 69 kV) system has been deemed necessary. The proposed load tap facilities include a 6-9 mile transmission line (only 3-6 miles of it will be completely new) and substation modifications to the existing White Earth substation.

Alternatives: There is a transmission alternative being considered as part of this load tap, and the alternative involves further investigation of a 69 kV load tap. The investigation is ongoing, and it will be compared with the 115 kV load tap option. To properly address this transmission request, a 115 kV load tap is the current transmission plan, but it may be changed if the investigation provides an equally cost effective project that is robust.

Analysis: Reliability impacts from the new load tap are currently evaluated in the annual TPL assessments (in terms of forecasting the existing White Earth area loads). Impacts to the bulk power system are not the reason for this transmission project. Limitations of the 41.6 kV transmission are the reason for this transmission project. The load tap is to be completed by 2019.

Schedule: The study efforts mentioned above determined that the new load tap must be completed by the winter of 2019. A schedule will be developed as definite plans are determined.

General Impacts: This project is primarily rural in location. The route will have to navigate around some lakes, forested areas, and potentially some reservation land within the area. Assuming a one hundred foot right-of-way, the project area will be nearly 42 additional acres (some existing transmission may be used for the project), but the affected farmland should only be about 2 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 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 2 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 planned 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 15 MVAR of capacitors and any necessary modifications to the existing Thief River Falls substation.

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 alternative of capacitor bank additions at Thief River Falls (15 MVAR). This will sufficiently support the system until the in-service date of the Winger-Thief River Falls 230 kV line (2023).

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 2023. 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 additions have been planned to be in-service in 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 (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.

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.

The table below identifies those projects by Tracking Number in the Northwest Zone that were listed as ongoing projects in the 2013 Biennial Report but have been completed or withdrawn since the 2013 Report was filed with the Minnesota Public Utilities Commission in November 2013. 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 2011 and the 2013 Reports 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 Northeast Zone by MISO utilities. There were no projects identified in this zone by non-MISO utilities.

Project Description: Construct new Savanna 115 kV Switching Station near Floodwood, Minnesota, and rebuild approximately 37 total miles of existing 69 kV line to 115 kV specifications between Lake Country Power's existing Cedar Valley Substation, the new Savanna Switching Station, Lake Country Power's existing Gowan Substation, and Great River Energy's existing Cromwell Substation. The project also includes a capacity upgrade of approximately 10 miles of existing 115 kV line from the Savanna Switching Station to Minnesota Power's 9 Line "Floodwood Tap."

Need Driver: General historical load growth in the areas between Duluth, Grand Rapids, and Brainerd as well as expected industrial expansion near Floodwood have exacerbated electrical reliability concerns on the existing 69 kV and 115 kV systems that serve the area and could potentially lead to line overloads and inability to maintain adequate voltage.

Alternatives: Several alternatives were considered, including: 1) a new local generation alternative; 2) various transmission solutions, including upgrading other existing facilities, different voltage levels and different endpoints; and 3) a no-build alternative focusing on reactive power supply improvements and demand side management.

Analysis: A solution that solves the identified inadequacies in three neighboring areas of the system (the Cromwell-Wrenshall-Mahtowa 115 kV system, the Cromwell-Four Corners 69 kV system, and the Floodwood 115 kV system) with one new transmission line provides an effective and efficient solution while minimizing social and environmental impacts. Making use of existing corridors and double-circuiting where practical with existing lines adds practicality and reduces social and environmental impacts.

Schedule: Great River Energy and Minnesota Power held a voluntary open house meeting in October 2010 to provide information about the Savanna 115 kV Project to the public. Subsequently, GRE and MP applied for both a Certificate of Need and a Route Permit for the Project in February 2011, culminating in the Commission's granting of both a CON and a Route Permit in February 2012 (MPUC Docket Nos. ET2,E015/CN-10-973 and ET2,E015/TL-10-1307). Since then, the majority of the components of the Savanna 115 kV Project have been constructed and are in-service, including the Savanna Switching Station, Savanna – Cedar Valley 115 kV Line, and Savanna – Cromwell 115 kV Line. Remaining work required to upgrade Minnesota Power's existing Savanna – Floodwood Tap 115 kV Line is expected to be completed in early 2016.

General Impacts: The Savanna 115 kV Project is a baseline reliability project that will ensure a continuous supply of secure and reliable electric energy to the project area while at the same time minimizing cost and impacts to the environment by utilizing existing utility corridors to the greatest reasonable extent.

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.

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, only approximately three miles of line construction will be required to provide a second 230 kV source to the Hilltop Substation. The majority of this construction will involve rebuilding an existing 115 kV line. 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 preferred project.

Minnesota Power is continuing to monitor line loading, voltage support and load growth in the Duluth area.

Schedule: Slower than anticipated load growth and external system improvements such as the Arrowhead – Stone Lake – Gardner Park 345 kV Line have delayed the need for this project. Recent study indicates that this project is not needed until the mid-2020 timeframe at the earliest. Therefore, the earliest that Minnesota Power currently anticipates initiating public outreach or permitting activities for this project would be in the early 2020s.

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 and economic development in the Duluth area in the most cost-effective and least environmentally impactful manner possible by utilizing existing utility infrastructure to the greatest extent possible.

Project Description: Transmission to serve Essar Steel, including development of two 230/13.8 kV substations (Calumet and McCarthy Lake) and approximately 27 miles of new 230 kV transmission lines. Future expansion could necessitate the addition of a third 230 kV source to the area from the existing Blackberry Substation.

Need Driver: New industrial customer load consisting of taconite mine and pellet plant. Possible future expansion could include a steel mill.

Alternatives: Several alternatives to connect Essar Steel Minnesota were studied, including: 500 kV to the site from the Forbes Substation; a single 230 kV source to the site; a 230/115 kV source to the site.

Analysis: Studies have shown that the 230 kV solution provides the best alternative to deliver the electric power from the Minnesota Power system to the Essar facility. See section 7.3.13 of the 2007 Minnesota Biennial Transmission Report for additional details.

Schedule: Minnesota Power held a voluntary open house meeting in February 2009 to provide information about the Essar 230 kV Project to the public and solicit the public's feedback on the routing of the 230 kV lines. Subsequently, MP submitted a Route Permit Application for the Project in June 2009, culminating in the Commission's granting of the Route Permit in August 2010. Phase 1, including three 230 kV lines and two 230 kV substations was completed in April 2013. There are no current plans to construct Phase 2 (the 230 kV line from Blackberry), which would only be required if Essar expanded to include a steel mill on the site.

General Impacts: The Essar 230 kV Project was 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 on the Iron Range and the attendant social and economic benefits that such expansion brings to the local area and the State.

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: Construct the new Zemple 230/115/23 kV Substation just east of Deer River, MN along U.S. Highway 2. To feed the new substation, a new segment of double circuit 230 kV line will be extended from the Boswell – Cass Lake 230 kV Line to the new substation. With the development of the new substation, Minnesota Power's existing 115/23 kV Deer River Substation will be retired and a new 115/23 kV transformer will be incorporated into the Zemple Substation. The 115 kV system in the Deer River area, which is currently fed from a single 115 kV line originating in Cohassett, will be interconnected to the new substation. A new segment of 115 kV line will be built to provide construction and maintenance flexibility as well as redundancy in the Deer River area, and the existing 115 kV line to Cohassett will be removed.

Need Driver: The Deer River area is currently served by a single 7.5 mile long 115 kV line (the Deer River Tap). This tap has multiple load-serving taps on it. Because all the power required to serve these customers must flow on the Deer River Tap, the line experiences high power flows under certain system conditions. Because of its age and condition, MP has reason to believe that this line may be approaching or exceeding its thermal capability at times. Anticipated expansion at a large industrial facility will further load the line, exacerbating this issue. Due to the radial arrangement of the Deer River Tap and the outage restrictions associated with this industrial facility, performing maintenance or upgrades on the line is very difficult and generally must be done while the line is energized. As an alternative to rebuilding the Deer River Tap, the Zemple 230 kV Project provides significantly improved reliability, constructability, and long-term load-serving capability. The Project will also enhance MP's ability to operate and maintain the transmission system in the Deer River area for the foreseeable future.

Alternatives: Because high voltage transmission is limited in the Deer River area, the only feasible alternative to the development of a new 230 kV source is to rebuild the radial 115 kV line that currently serves the Deer River area.

Analysis: In the past, MP proposed to add a 115 kV exit to the Boswell 115 kV substation and move the 28L Deer River tap to this new position. This would require construction of less than one mile of 115 kV transmission and split 28L into two separate lines, thus improving operating performance and reducing maintenance issues. However, since the Bemidji-Grand Rapids 230 kV line (Tracking Number 2005-NW-N2) was constructed through the Deer River area, the construction of a Deer River 230/115 kV substation is now possible. The establishment of this new 230/115 kV source will significantly improve reliability, redundancy, and load-serving capacity in the Deer River area.

Schedule: Minnesota Power held a voluntary public open house meeting in January 2013 to provide information about the Zemple 230 kV Project to the public. Subsequently, MP submitted a Route Permit Application for the Project in April 2013, culminating in the Commission's granting of the Route Permit in June 2014 (MPUC Docket No. E015/TL-13-68). Construction of the new 115 kV transmission line was completed in March 2015. Construction of the 230 kV transmission line and the Zemple 230/115 kV Substation are expected to be ongoing through the end of 2015. Removal of the existing 115 kV Deer River Tap is expected to occur in late 2016 or early 2017.

General Impacts: The Zemple 230 kV Project provides the most efficient long-term solution for the Deer River area and the surrounding transmission system while minimizing environmental and social impacts through the utilization of an existing substation site, as well as the removal of 7.5 miles of existing 115 kV line. In addition, the Zemple 230 kV Project supports the expansion of existing industrial facilities in the Deer River area and the attendant social and economic benefits that such an expansion will bring to the local area and the State.

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).

Schedule: MISO and Minnesota Power studies indicate that a need for the 15 Line Upgrade develops in 2017. The earliest MP would begin construction of the Project would be in the spring or summer of 2017.

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 138/13.8 kV substation interconnected to the existing Taconite Harbor – Hoyt Lakes 138 kV Line (MP "1 Line").

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.

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.

Project Description: Replace existing 115/46 kV transformers with a newer 115/46 kV transformer at the Laskin Substation.

Alternatives: Develop a new 115/46 kV substation and retire the Laskin 115/46 kV transformer and 46 kV distribution equipment.

Analysis: There is no compelling need to relocate the 115/46 kV source presently located at the Laskin Substation. Replacement of the existing 115/46 kV transformers with a single newer, higher-capacity transformer in the same location will reduce the risk of outages caused by transformer failure and support the long-term capacity needs of the 46 kV system served from Laskin.

Schedule: The Laskin Transformer replacement project has been delayed due to budgetary constraints. At this time, Minnesota Power expects that the earliest possible in-service date for the Project would be in 2018.

General Impacts: The Laskin Transformer project will ensure a continuous and reliable power supply for continued load growth in the area between Virginia and Hoyt Lakes in the most cost-effective and least environmentally impactful manner possible.

Project Description: Add 115/69 kV transformer and breakers at existing Wrenshall Substation site. Extend 69 kV to Military Road and interconnect to existing GRE 69 kV line originating at MP Stinson Substation.

Need Driver: Retirement of existing 46 kV line and equipment at Thomson Substation due to age and condition.

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

Analysis: The Wrenshall 115/69 kV source to the Fond du Lac area will provide load serving capability that the 46 kV system previously served over very lengthy lines that are hard to reach for outage restoration. This area will rely on a more robust system after the Wrenshall project is built.

Schedule: The Wrenshall Substation project has been delayed due to budgetary constraints. At this time, Minnesota Power and Great River Energy expect that the earliest possible in-service date for the Project would be in 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 to maintain due to its location and the surrounding terrain.

Project Description: Construct new 115/13.8 kV substation on existing Arrowhead – Cloquet 115 kV Line (MP "22 Line").

Need Driver: Load growth and reliability concerns for customers served out of the existing Cloquet and Midway substations. Canosia Road will unload these two existing substations.

Alternatives: Develop a new 115/13.8 kV substation at a different site, such as the existing Midway tap.

Analysis: The proposed Canosia Road Substation is optimally located to resolve the reliability concerns associated with the Cloquet Substation. Other existing sites, such as the Midway Substation, would not provide the same level of benefit to the Cloquet-Esko area. The Canosia Road Substation will be designed to meet the projected near-term and long-term needs of the area.

General Impacts: The Canosia Road Substation will enhance reliability of service to the Cloquet and Esko areas and support future load growth in the areas by shifting customers off of the Cloquet and Midway substations and providing a redundant source to the area.

Project Description: Expand existing Embarrass Switching Station to include a new 115/23 kV transformer.

Alternatives: Develop a new 115/23 kV substation tapped into the Laskin – Embarrass 115 kV Line.

Analysis: Locating the new 115/23 kV source at the existing Embarrass Switching Station makes the best use of existing infrastructure in the area and provides superior reliability to the alternative involving a single tapped feed from the Laskin – Embarrass 115 kV Line. The project is part of a larger plan to provide sufficient capacity, reliability, and redundancy of 115/23 kV sources for the area between Virginia and Hoyt Lakes.

Need Driver: Unload the 46 kV system between Virginia and Hoyt Lakes and establish a redundant backup source for the 23 kV system between Eveleth and Hoyt Lakes.

General Impacts: The Embarrass Transformer addition project will provide needed load-serving capacity and redundancy to the area between Eveleth and Hoyt Lakes. Utilizing the existing Embarrass Switching Station site for the new 115/23 kV source meets these needs in the most cost-effective and least environmentally impactful manner possible.

Project Description: The Great Northern Transmission Line Project includes approximately 220 miles of 500 kV transmission line between a point on the Minnesota-Manitoba border northwest of Roseau, Minnesota, and Minnesota Power's existing Blackberry Substation near Grand Rapids, Minnesota. 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, Minnesota.

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 October 21, 2013, Minnesota Power submitted an Application for a Certificate of Need to construct the 500 kV Great Northern Transmission Line and associated facilities to the Minnesota Public Utilities Commission (MPUC Docket No. E015/CN-12-1163). This was the first major step in the regulatory review process. Subsequently, on April 15, 2014, Minnesota Power simultaneously filed a Route Permit Application (MPUC Docket No. E015/TL-14-21) and a Presidential Permit Application (DOE Docket No. PP-398), to the Minnesota Public Utilities Commission and the United States Department of Energy, respectively. On May 14, 2015, the Minnesota Public Utilities Commission granted Minnesota Power a Certificate of Need to construct the Great Northern Transmission Line. Decisions on the Route Permit Application and Presidential Permit Application are expected in early 2016.

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).

Pending the applicable regulatory approvals, Minnesota Power expects to begin construction of the Great Northern Transmission Line Project in 2017 in order to meet the required in-service date of June 1, 2020 in satisfaction of the contractual arrangements 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: Transmission line derates (i.e. capacity reductions) and physical mitigation of low priority lines on the MP and Superior Water, Light, and Power (SWLP) systems include the 115 kV, 138 kV and 161 kV systems.

Alternatives: There are no alternatives to this project as it was a matter of compliance with a NERC Alert.

Analysis: Minnesota Power's approach to the NERC Alert attempts to strike a right balance between transmission line derates – which reduce the capacity of the transmission system – and costly physical mitigation. Failure to comply with the NERC Alert may result in non-compliance with NERC Standards.

Schedule: The deadline for mitigation of discrepancies identified on Low Priority lines, as set forth in the original NERC Facility Ratings Alert Recommendation, was December 31, 2014. On February 27, 2014, Minnesota Power submitted a progress update to the Midwest Reliability Organization (MRO) with the findings of the completed analysis of its Low priority lines. By late December 2014, Minnesota Power had only mitigated approximately 29 percent of all discrepancies requiring physical construction on its Low Priority facilities. In early 2015, Minnesota Power requested and was granted an extension of the deadline for completing remediation of its Low priority facilities from December 31, 2014 to December 31, 2016. The mitigation work is currently progressing on schedule with all discrepancies expected to be mitigated by December 31, 2016. Minnesota Power will reassess its progress periodically to determine if more time is required for specific situations due to construction access constraints, outage constraints, or the type and complexity of mitigation.

General Impacts: The NERC Facility Ratings Alert projects represent tens of millions of dollars of investment in the transmission system, including many hours of construction labor. Because discrepancies have been identified on nearly every transmission line in the Minnesota Power system, the impact is felt throughout northeastern Minnesota. Minnesota Power is making an effort, within the time constraints imposed by NERC, to minimize the environmental impact and cost of construction by leveraging frozen ground conditions where possible for performing the NERC Facility Ratings Alert mitigation construction.

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 2015 they have been operating reliably for over 38 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 (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. The earliest expected in-service date for the Project is 2020.

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 (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. The earliest expected in-service date for the Project is 2020.

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: Rebuild and reconfigure the existing Hoyt Lakes Substation by replacing end-of-life equipment, adding a bus-tie breaker to sectionalize transmission lines, and adding a new 20 MVAr capacitor bank to support voltage.

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

Analysis: Much of the existing equipment in the Hoyt Lakes Substation is at end-of-life, and its replacement is a prudent and necessary step in establishing reliable electric service for the proposed Polymet plant. Replacement of this equipment also provides an opportunity for making improvements to the electrical configuration of the substation to support improved redundancy and provide necessary reactive power support for the proposed plant.

Schedule: The schedule for construction of the Hoyt Lakes Substation Modernization Project is dependent on the schedule for the development of the Polymet mine.

General Impacts: The Hoyt Lakes Substation Modernization Project is the most efficient and least environmentally impactful viable solution for meeting the near-term and long-term needs at the Polymet plant site and makes good use of an existing substation site for a new customer.

Project Description: The Menahga Area 115 kV Project consists of approximately 22.5 miles of new 115 kV transmission line between Great River Energy's existing Hubbard Substation and a new Minnesota Pipeline pumping station, as well as the construction of three new substations (Minnesota Power "Straight River," Great River Energy "Blueberry," and Todd-Wadena Electric Cooperative "Red Eye"), relocation and voltage conversion of the existing Todd-Wadena Menahga Substation, and modifications to the existing Great River Energy Hubbard Substation.

Need Driver: Identified capacity and voltage limitations on the 34.5 kV system between Verndale and Hubbard and a new Minnesota Pipeline pumping station located near Sebeka, Minnesota.

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

Analysis: The Menahga area will receive redundant electric service with the addition of the 115/34.5 kV substation in this area. Simply rebuilding the 34.5 kV system would not provide the power redundancy and also is more prone to momentary outages. The Menahga area 115 kV project will greatly improve the electric service performance in the Menahga area.

Schedule: The Menahga project is planned to be fully in-service by April 1, 2017.

General Impacts: The Menahga Area 115 kV Project is the most efficient and least environmentally impactful viable solution for meeting the near term and long term needs in the Menahga area. Pumping stations requires a larger voltage than 34.5 kV to start motors and not cause voltage violations on the system. The Menahga 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: Construct a new, 16.5 mile, 115 kV transmission line between the existing Itasca-Mantrap Cooperative Electric Association's (IMCEA) Potato Lake Substation and the existing Great River Energy (GRE) Hubbard Substation. The Project involves adding a new 115/34.5 kV substation to the Hubbard-Potato Lake 115 kV line to be named Elisha. The proposed project includes construction of a proposed new, 8.0 mile, 34.5 kV sub-transmission line from the Elisha 115/34.5 kV Substation to the existing IMCEA 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 two line sections; the Long Lake – Mantrap – Potato Lake – Arago 115 kV line and 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. A 115 kV loop (Hubbard – Mantrap – Potato Lake – Elisha – Hubbard) will be created providing two sources to the Elisha 115/34.5 kV substation.

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: The capacity of the existing Brainerd – Mud Lake 115 kV Line needs to be increased due to identified post-contingent overloads for contingencies involving the parallel Mud Lake – Riverton 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 load projections.

Schedule: MISO and Minnesota Power studies first indicate a need for the 5 Line Upgrade prior to the 2019-20 winter season. The earliest MP anticipates being able to begin construction of the Project would be in 2018.

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: The capacity of the existing Little Falls – Langola Tap – St. Stephen Tap 115 kV Line needs to be increased due to identified post-contingent overloads for contingencies involving parallel 230 kV, 345 kV, and 500 kV transmission lines in the area.

Alternatives: Build a new 115 kV or 230 kV line between Mud Lake and the St. Cloud area.

Analysis: Reconductoring 868 Line provides the best solution 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 load projections.

Schedule: MISO and Minnesota Power studies first indicated a need for the 868 Line Upgrade prior to the 2019-20 winter season. The earliest MP anticipates being able to begin construction of the Project would be in 2018.

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: Expand existing Maturi Substation to include a new 115/23 kV transformer.

Need Driver: Add load-serving capacity and improve redundancy for the 23 kV system between Hibbing and Virginia.

Alternatives: Develop a new 115/23 kV substation tapped into the Virginia – Hibbing 115 kV Line.

Analysis: Locating the new 115/23 kV source at the existing Maturi Substation makes the best use of existing infrastructure in the area and avoids the addition of another (third) load-serving tap on the Hibbing – Virginia 115 kV Line. The project is part of a plan to provide sufficient capacity, reliability, and redundancy of 115/23 kV sources for the area between Virginia and Hibbing.

General Impacts: The Maturi 115/23 kV Transformer addition project will provide needed load-serving capacity and redundancy to the area between Hibbing and Virginia. Utilizing the existing Maturi Substation site for the new 115/23 kV source meets these needs in the most cost-effective and least environmentally impactful manner possible.

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 is expected to begin in 2016 and 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 2018 to meet United Taconite's schedule for the planned tailings basin expansion.

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: The Motley Area 115 kV Project consists of approximately 16 miles of new 115 kV transmission line between a point on Minnesota Power's existing Scearcyville – Dog Lake Tap 115 kV Line (MP "24 Line") and a new Minnesota Pipeline pumping station, as well as construction of one new substation at the pumping station site (Crow Wing Power "Fish Trap Lake"), conversion of the existing Crow Wing Power Motley Substation from 34.5 kV to 115 kV service, and expansion of the existing Minnesota Power Dog Lake Substation to a more reliable ring bus design. Expansion of the Dog Lake Substation would require an additional one-half mile of 115 kV transmission line between the existing Scearcyville – Dog Lake Tap 115 kV Line and the Dog Lake Substation.

Need Driver: The project is needed to provide electric service to Minnesota Pipeline's (MPL) Fish Trap pump station. Also the project is needed to address circuit overloads that currently exist on the Dog Lake-Baxter 34.5 kV system and alleviate capacity issues identified on the lines between Dog Lake and Baxter.

Alternatives: Many alternatives were looked at such as: peaking generation, distributed generation, renewable generation, upgrading of existing facilities, different conductor, alternative voltages, alternative endpoints, double circuiting, undergrounding, reactive power supply, demand side management and conservation, and no build alternative.

Analysis: There are two need drivers in the Motley area; native load growth (34.5 kV system) and a large pump station. The 115 kV line needed for the large pump station integrated well with correcting the native load serving issues by allowing for the Motley distribution substation to be transferred from the 34.5 kV system to the 115 kV system alleviating the capacity concerns on the 34.5 kV system. The other alternatives studied didn't provide both solutions or wasn't the least cost alternative to providing solutions to both needs.

General Impacts: The Motley Area 115 kV Project was the most efficient way to provide electric service to MPL's pumping station and while addressing the issues on the neighboring 34.5 kV system.

Project Description: Replace existing Maturi 10 MVA 115/34.5 kV transformer with a larger-capacity 18.6 MVA transformer of the same basic physical size. Move Maturi 10 MVA transformer to new Straight River Substation (MTEP Project #7999).

Need Driver: Load additions proposed by the sole industrial customer served from the Maturi 115/34.5 kV transformer are anticipated to exceed the 10 MVA capability of the transformer.

Alternatives: Do nothing; or add a second 115/34.5 kV transformer at the site for the industrial customer.

Analysis: Doing nothing risks accelerating the end-of-life of the existing transformer by continually loading it above its designed capability. Adding a second 115/34.5 kV transformer is not viable due to space constraints on the site, and does not make optimal use of the existing transformer or the new transformer. Replacing the existing transformer with a larger one and relocating the existing transformer to a new site provides the most efficient and effective long-term solution.

General Impacts: The Maturi 115/23 kV Transformer addition project will provide needed capacity for Minnesota Power's industrial customer in the most cost-effective and least environmentally impactful manner possible.

Project Description: Construct a new 115/23 kV substation in Eveleth, Minnesota, adjacent to existing Laskin – 37 Line Tap 115 kV Line (MP "37 Line").

Need Driver: The Eveleth area is currently served by two 23 kV feeders from the Virginia Substation. These two feeders are currently located along U.S. Highway 53. When the United Taconite mining operation expands at the Thunderbird Mine, the land utilized for the current feeder route along the highway will be reclaimed for mining. A new source or route for the two feeders is required prior to the expansion of the United Taconite mine. Development of a new 115/23 kV source in Eveleth was determined to be the best long-term solution for re-establishing a source on the west side of the Eveleth area 23 kV system.

Analysis: Establishment of a new 115/23 kV source in the Eveleth area resolves the feeder relocation issue while also providing improved redundancy, reliability, and load-serving capability for the area between Hoyt Lakes and Virginia. Rerouting the 23 kV feeders around the mine pit proved to be uneconomical due to engineering constraints associated with either crossing the pit or rerouting a long distance around it.

General Impacts: The Hat Trick 115 kV Project will provide continued reliable service and increased long-term load-serving capability for the 23 kV system between Eveleth and Hoyt Lakes. The Project supports the expansion of the existing United Taconite mining operation in Eveleth, Minnesota, and the attendant social and economic benefits that the continued operation of the mine brings to the local area and the State.

Project Description: Add a 115 kV breaker and reconfigure transmission line terminations at the existing Arrowhead Substation such that the Arrowhead – Colbyville 115 kV Line and Arrowhead – Haines Road 115 kV Line are not terminated on adjacent buses subject to a single breaker failure event.

Need Driver: Identified post-contingent voltage collapse in the "Duluth Loop" area (Haines Road – Swan Lake Road – Ridgeview – Colbyville substations) caused by internal fault or failure of Arrowhead "115MW" bus tie breaker.

Analysis: Reconfiguration of the Arrowhead 115 kV bus is a low cost solution to the identified issue that can be implemented much more quickly than the development of a new 115 kV line.

General Impacts: The Arrowhead 115 kV Bus Reconfiguration will ensure continued reliable service and load-serving capacity for the Duluth area and position the Arrowhead 115 kV Substation for future modernization and reliability improvement, all without requiring any additional property for transmission line or substation development.

Project Description: Expand the 230 kV bus at the existing Minntac 230 kV Substation and add three 230 kV circuit breakers to convert it to a four-position ring bus arrangement. Relocate one 230 kV line to an adjacent line entrance to facilitate separation of sources and loads within the new ring bus arrangement.

Need Driver: Identified post-contingent voltage violations and transmission line overloads in the Virginia area transmission system caused by internal fault or failure of Minntac "80-96LW" 230 kV bus tie breaker. The impact of this breaker failure event is exasperated by the idling of the three coal-fired generation units at the Taconite Harbor Energy Center.

Alternatives: Increase capacity of overloaded lines and add reactive power support (cap banks) in the area.

Analysis: Reconfiguration of the 230 kV bus at the Minntac Substation defers or eliminates the need for additional capacity on several 115 kV lines in the surrounding area, and also improves redundancy for Minnesota Power's largest customer and other customers in the Virginia area. It is the most effective solution for mitigating the identified inadequacies.

Schedule: In its evaluation of the impact of idling the Taconite Harbor generation, Minnesota Power determined that the Minntac 230 kV Bus Reconfiguration Project needed to be in place prior to shutting down the Taconite Harbor generators in the near-term. Therefore, the Project is expected to be in-service by October 2016 to facilitate the economic idling of Taconite Harbor units 1 and 2.

General Impacts: The Minntac 230 kV Bus Reconfiguration Project will ensure continued reliable service and load-serving capacity for the Virginia area without requiring any additional property for transmission line or substation development. The Project facilitates the shutdown of coal-fired generation at the Taconite Harbor Energy Center for economic and environmental reasons.

Project Description: Add a second 230/115 kV transformer with a top rate of 373 MVA at the existing Forbes 230/115 kV Substation ("2TR"). Replace Forbes "18L" 115 kV breaker due to increased short circuit interrupting current requirements associated with the transformer addition.

Need Driver: Widespread post-contingent voltage depression in the Hibbing-Virginia-Babbitt area and post-contingent overloads on existing Forbes 230/115 kV transformer caused by several contingencies, including internal fault or failure of Forbes "80L" 230 kV breaker. The impact of these events is exasperated by the idling of the three coal-fired generation units at the Taconite Harbor Energy Center.

Alternatives: Reconfigure bus connection of existing Forbes transformer to lessen the severity of the limiting contingencies and add local reactive power support (capacitor banks) at various locations throughout the eastern Iron Range.

Analysis: Adding a second transformer at the Forbes substation is the most effective long-term solution for the identified inadequacy, providing significant improvements in load-serving capacity and reactive power support for the surrounding area.

Schedule: In its evaluation of the impact of idling the Taconite Harbor generation, Minnesota Power determined that the Forbes 230/115 kV Transformer Addition Project needed to be in place prior to shutting down the Taconite Harbor generators in the near-term. Therefore, the Project is expected to be in-service by October 2016 to facilitate the economic idling of Taconite Harbor units 1 and 2.

General Impacts: The Forbes 230/115 kV Transformer Addition Project will ensure continued reliable service and load-serving capacity for the eastern Iron Range area without requiring any additional property for transmission line or substation development. The Project facilitates the shutdown of coal-fired generation at the Taconite Harbor Energy Center for economic and environmental reasons.

Project Description: Expand planned Iron Range (f/k/a "Blackberry") 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 (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 justify the need for 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.

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 is necessary to restore 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.

General Impacts: The 83 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: 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 is necessary to restore 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.

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 approximately7.5 miles of 115kV 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.

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 a ~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.

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 a ~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.

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.

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

The table below identifies those projects by Tracking Number in the Northeast Zone that were listed as ongoing projects in the 2013 Biennial Report but have been completed or withdrawn since the 2013 Report was filed with the Minnesota Public Utilities Commission in November 2013. 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 2011 and the 2013 Reports 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.

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: Construct approximately 2 miles of 115 kV transmission line from the LeSauk distribution substation to the new Sartell distribution substation.

Need Driver: The Sartell distribution substation is required by Stearns Electric Association to accommodate present and future residential/commercial growth in the City of Sartell. The sub will also relieve loading from the Le Sauk, Fischer Hill and Westwood distribution substations as well as provide backfeed capability in the surrounding area.

Alternatives: The alternative to the Sartell distribution substation plan is to continue serving the growing load in the area with the existing distribution substations in the area. However, load growth in the area has reached to the level that this is not possible. The best value plan to reliably serve customers in the area is to establish the Sartell distribution substation.

Analysis: The Sartell project will provide service to customers in the area of Sartell and provide contingency back up customers served from LeSauk, Fisher Hills and Westwood distribution substations. The project will make capacity available to serve expected commercial and residential load growth in the area while serving existing customers that are now served on long distribution feeders from LeSauk, Fisher Hills and Westwood distribution substations.

Schedule: This project is currently expected to be complete by summer 2016 but may be delayed depending on load growth in the area.

General Impacts: The Sartell distribution substation project will provide a long-term reliable service to customers in the area.

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: Convert Minn Valley - Panther - McLeod - Blue Lake 230 kV line to Double circuit 345 kV from Hazel to McLeod to West Waconia to Blue Lake.

Need Driver: In 2015, there is no current identified need for this project, but with EPA 111d and the Clean Power Plan on the near term horizon, States and utilities will be working together to determine the best way to manage the transition from existing generation resources to new generation resources. Xcel Energy believes that it is important to keep this project as one to be considered in future transmission build out scenarios. This project includes the conversion of an existing Minn Valley – Blue Lake 230 kV transmission line corridor to accommodate a double circuit 345 kV transmission line (aka "Corridor Project"). The Corridor Project would allow additional wind power to be transferred from the wind rich areas in southwest Minnesota to the Minneapolis/St Paul metro area load pocket. This project would be a potential candidate to be built after the wind zones around southwest Minnesota exceed the transmission capabilities of the CapX and MISO MVP lines.

Alternatives: Building a new line on new Right Of Way to increase the transfer capability from wind rich areas in SW MN and the Dakotas would have an increased impact on land use, so rebuilding the existing line is considered preferred.

Analysis: The Corridor conversion of the existing 230 kV to 345 kV has been studied multiple times over the past number of years. While there is currently no need for this line in 2015, Xcel Energy believe it is an important option to keep open and in consideration in future studies to increase transfer capability of the grid to deliver renewables to customers.

Project Description: Convert 69 kV St. Stephen substation to 115 kV service. This will include converting approximately 1 mile of existing 69 kV transmission line to 115 kV.

Need Driver: The West St. Cloud transformer overloads during n-1 outages. This project will move some of the 69 kV load to the 115 kV system.

Analysis: The project relieves loading from the West St. Cloud 115/69 kV transformer as St. Stephen will be served from the 115 kV system. SEA's Brockway and St. Stephen substations are now served from an old and radial 69 kV transmission line. A fault on the radial line would take both substations out-of-service. The conversion of the St. Stephen to 115 kV will increase system reliability in the area as only the Brockway substation is a shorter radial line. As St. Stephen will provide contingency back up to the Brockway substation, customers served from the Brockway substation will also see improved service reliability.

General Impacts: The conversion of the St. Stephen distribution substation will bring better reliability to customers who are served from this substation. In addition, it would provide a longer life to the existing West St. Could transformer and West St. Cloud to St. John 69 kV line.

Project Description: Build approximately 2½ miles of 115 kV line between Quarry 345/115 kV Substation to West St. Cloud 115/69 kV substation.

Need Driver: A two overlapping single contingency event (NERC TPL-001-4 P6) results in significant loadshed in the area northwest of St. Cloud. Potential cascade tripping in a confined area may occur.

Alternatives: The alternative to this project is to construct the Quarry to West St. Cloud 115 kV line along a route that is not in parallel with the existing West St. Cloud – Quarry line.

Analysis: The Quarry – West St. Cloud 115 kV line will ensure potential cascading outage in the system will not occur during critical contingencies in the area. This project will keep loads that would otherwise have to be shed in-service during critical contingencies in the system.

General Impacts: This project is the best value plan and will address the concern of an outage that result in wide ranging reliability impact.

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.

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: Install breaker and half layout at existing Quarry substation to allow new interconnection to West St. Cloud substation.

Need Driver: Great River Energy is building a new 115 kV Transmission line between NSP's Quarry substation and GRE's West St. Cloud substation to increase capacity and reliability of the 115 kV Transmission system in the St. Cloud area. This project will expand the Quarry substation to enable the new 115 kV connection.

Alternatives: Expand the Quarry substation to enable a new 115 kV termination to the West St. Cloud substation.

Analysis: This project will increase the transmission reliability in the St. Cloud area by allowing a new 115 kV circuit to be installed between Quarry and West St. Cloud.

Schedule: This project is scheduled to begin early in 2017 and be completed by May 2017.

General Impacts: This project is required to complete the project that is adding a 115KV line between Quarry substation and West St Cloud substation. The scope of this project is entirely within the existing Quarry substation and has no additional environmental impacts.

Project Description: Rebuild the Douglas County – West Union 69 kV line to 477 ACSR and transfer Osakis substation load to Douglas County

Need Driver: This 69 kV Transmission line is overloading for single contingency in high load scenarios.

Alternatives: Reconductor the 69 kV line to 477ACSR conductor which will increase the capacity.

Analysis: This section of 69 kV Transmission line has seen capacity increase over the years and it is no longer to reliably serve the area.

Schedule: This project will start early in 2016 and is projected to be complete by April 30, 2016.

General Impacts: This Transmission Line rebuild is the most efficient and least environmentally impactful solution to serve the increased load in the area. Any other solution would involve building new 69KV or 115KV transmission lines.

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.

Project Description: Build a new 345/115/69 kV substation near Melrose, Minnesota.

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.

General Impacts: The Riverview Rd 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: Build approximately 6.5 miles of 115 kV transmission line to serve a new Koch Pipeline pumping station load.

Need Driver: Koch Pipeline has proposed a new pumping station about 7 miles northeast of the City of Litchfield.

Alternatives: The 69 kV system nearby would not support the large pumping station load. Given the nature of the load it is prudent to serve it from the 115 kV system. 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 Swan Lake – Wakefield line. A 6.5 mile radial tap will be constructed to the new Stockade substation to provide electric service.

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

The table below identifies those projects by Tracking Number in the West Central Zone that were listed as ongoing projects in the 2013 Biennial Report but have been completed or withdrawn since the 2013 Report was filed with the Minnesota Public Utilities Commission in November 2013. 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 2011 and the 2013 Reports 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
2009-TC-N2	New Market & Cleary Lake Area Projects	20213/A	4008	Yes	GRE
2015-TC-N1	Bailey Road Substation	2015/C	8780	Maybe	XEL
2015-TC-N2	Cedar Lake Pumping Station	2015/C (seeking A)	7899	No	GRE
2015-TC-N3	SW Twin Cities Project	2015/C	3311	Maybe	XEL

Project Description: Establish 69 kV breaker stations at Jordan and Veseli, construct 5.4 mile double circuit 69 kV line (built to 115 kV standard) from New Market to Veseli, and rebuild existing 4/0A 69 kV lines (Prior Lake – Cleary Lake – Credit River Tap 69 kV line and Lake Marion Tap – Elko – New Market 69 kV line) to 115 kV standard with 795ACSS conductor.

Need Driver: The drivers for the Elko-New Market and Cleary Lake area projects are load serving concerns (low voltage and line overload) in the extensive 69 kV network that is bounded by the Carver County, Scott County, Faribault and Owatonna 115/69 kV sources. Substations along the Scott County – Jordan – New Prague 69 kV line experience low voltage problems for the loss of the Scott County – Gifford Lake 69 kV line. This contingency causes low voltage problems at Gifford Lake, Merriam Junction, Jordan, Sand Creek and New Prague distribution substations.

The Scott County – Gifford Lake 69 kV line outage also causes transmission line overload on the Carver County – Assumption and Assumption – Belle Plaine 69 kV lines in the near-term. Other contingencies, such as the loss of the Lake Marion – Lake Marion Tap 69 kV line, Lake Marion Tap – Elko and Lake Marion – New Market 69 kV lines, cause transmission line overload concerns in the near-term. These transmission line outages would overload the Prior Lake Junction – Credit River Junction 69 kV line, Credit River Junction – Cleary Lake 69 kV line and Cleary Lake – Credit River (NSP) 69 kV line.

Alternatives: The following are the alternatives considered to address the load serving issues in the area:

These alternatives include rebuild of existing transmission lines to 115 kV standard. Alternative 1, Alternative 2 and Alternative 3 include the rebuild of Carver County – Assumption – Belle Plaine 69 kV line. Alternative 1 also includes the rebuild of the Faribault – Circle Lake 69 kV line.

Alternative 2 includes the rebuild of the Chub Lake – Lake Marion Tap – Elko- New Market 69 line with 795 ACSS conductor that is constructed for 115 kV standard. Prior Lake Junction – Credit River Junction – Cleary Lake – Credit River (NSP) 69 kV lines will also be rebuilt with 795 ACSS conductor to 115 kV standard as part of Alternative 2. New breaker stations, at Jordan and Veseli, are part of the preferred alternative that will address the near-term load serving concerns in the area. As part of the out year recommendation of Alternative2 for system reinforcement, the rebuild of the Carver County – Assumption – Belle Plaine 69 kV line to 115 kV standard and a 115/69 kV source at Veseli are recommended.

Analysis: Alternative 2 is the preferred alternative and in 2012 a certificate of need and a route permit were applied for to authorize this project. MPUC Docket Nos. ET2/CN-12-1235 and ET2/TL-12-1245.

Schedule: On August 5, 2014, the MPUC granted a Certificate of Need and a Route Permit for the project. This project is scheduled to be in service by spring 2016.

General Impacts: The New Market & Cleary Lake Area Projects are the most efficient and least environmentally impactful viable solutions for meeting the near term and long term needs in the area.

Project Description: Add a new Bailey 345/115 kV substation located east of the Red Rock substation on the existing Red Rock-Allen S. King 345 kV line. Install two 345/115 kV, 448 MVA transformers. Reterminate four existing 115 kV lines from Red Rock to Bailey Road. Add 115/34.5 kV, 70 MVA distribution to the substation.

Need Driver: There are several transmission issues associated with the Red Rock substation. The available fault current level at Red Rock is currently projected to exceed 56 kA for the summer peak in 2019 with Twin Cities generation running. In addition for 2019 summer peak the 448 MVA transformers at Red Rock are exceeding their emergency rating. Distribution planning is projecting a total load growth for the Woodbury and surrounding areas at approximately 290 MW which is stressing the existing distribution system.

Analysis: This project will increase the distribution reliability in the southern Woodbury area. The preferred substation site location is south of an existing high school in Woodbury, due to existing infrastructure located in the area. This project combines several needs for distribution load serving and transmission thermal overloads and fault current issues. Expanding the Red Rock substation would be difficult due to its proximity to the Mississippi River. By building a new Bailey Road substation located in south Woodbury it will allow distribution to expand and feed the load from the south as well as address the transmission deficiencies at Red Rock. Currently the preferred substation site is farmland. The substation is expected to require 15 acres of land, entirely converting the existing land use. Siting will be coordinated with the appropriate local, state, and federal authorities. The work could be completed in approximately two years and would likely be constructed by Xcel Energy employees. The estimated cost is approximately $29M and would have a targeted in-service date of 2019.

Schedule: The work could be completed in approximately two years and would likely be constructed by Xcel Energy employees.

General Impacts: Currently the preferred substation site is farmland. The substation is expected to require 15 acres of land, entirely converting the existing land use. Siting will be coordinated with the appropriate local, state, and federal authorities. The estimated cost is approximately $29M and would have a targeted in-service date of 2019.

Project Description: Install an approximately 6 mile long transmission line to connect to Minnesota Valley Electric Cooperative's Cedar Lake pump station sub. Line is to be built to 115 kV specs but initially energized at 69 kV.

Need Driver: Koch Pipeline has proposed a new pumping station about 2 miles northeast of the City of New Prague.

Analysis: Large pumping stations with large electric motors require a robust voltage like 115 kV. The New Market – Veseli 69 kV system will be converted to 115 kV in the future. A radial line to Cedar Lake substation will be constructed at 115 kV standards in anticipation of the 115 kV conversion.

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

Project Description: Rebuild existing 69 kV lines around the Chaska area to 115 kV and rebuild a single circuit 115 kV line in Chanhassen to a double circuit 115 kV line. This project also includes substation work at multiple substations throughout the area surrounding Eden Prairie, Chanhassen, and Chaska. This project also includes the new Scott County 345/115 kV substation and the Bluff Creek 115 kV substation.

Need Driver: The worst contingency in the SW Twin Cities project area is loss of the Eden Prairie – Westgate double circuit 115 kV line. This outage isolates the largest load in the area from the best source in the area at the Eden Prairie 345 kV.

Alternatives: Rebuilding Westgate – Deephaven – Excelsior – Scott County 69 kV line to 115 kV.

Analysis: This project is needed due to load growth in the region under contingency conditions causing both low voltages and line overloads. The series of projects associated with the SW Twin Cities project will be built using existing right of way whenever possible. After the completion of these projects, the study area will no longer have any low voltages or overloads and allow for future load growth. The majority of the SW Twin Cities projects are already in service, with the remaining projects to be completed by end of 2016.

Schedule: The work could be completed in approximately two years and would likely be constructed by Xcel Energy employees.

General Impacts: This project is rebuilding the existing 69 kV line to 115 kV using the same right of way. Siting will be coordinated with the appropriate local, state, and federal authorities. The estimated cost is approximately $8M and would have a targeted in-service date of 2016.

The table below identifies those projects by Tracking Number in the Twin Cities Zone that were listed as ongoing projects in the 2013 Biennial Report but have been completed or withdrawn since the 2013 Report was filed with the Public Utilities Commission in November 2013. 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 2011 and the 2013 Reports 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.

Project Description: This project is to install a 25 MVAR switched reactor at the existing Yankee substation in Southwest Minnesota.

Need Driver: The 115 kV transmission system between the Nobles County and Brooking County substations in southwest Minnesota are experiencing high voltages during no-wind conditions. The reactor will help bring the voltages back within equipment limits.

Alternatives: An alternative proposal was to install single 25 MVAR fixed reactors at Yankee and Fenton and installing a +/-60 MVAR SVC near the Pipestone substation

Analysis: Transmission studies and real-time operating data has identified that the 115 kV system in Southwest Minnesota is susceptible to high voltage issues. This area has added many large wind farms and the addition of the CapX Brookings will further enable continued wind growth. The high voltages in the area are due to lack of electrical load in the localized area and the reactive power produced from the wind farm feeder networks under no-wind conditions. The study results have identified that reactor installations at the existing Yankee and Fenton will help mitigate the high voltage issues. The work will be done in two separate projects, at the Yankee substation first and then at the Fenton substation, and would likely be constructed by Xcel Energy employees.

Schedule: Construction is expected to begin in 2015 with a completion date of fall of 2016.

General Impacts: This reactor instillation will be contained in the existing Yankee substation and will not require expanding the substation site. Xcel Energy construction crews are expected to perform the work.

Project Description: This project is to install a 25 MVAR switched reactor at the existing Fenton substation in Southwest Minnesota.

Alternatives: An alternative proposal was to install single 25 MVAR fixed reactors at Yankee and Fenton and installing a +/-60 MVAR SVC near Pipestone substation.

Analysis: Transmission studies and real-time operating data have identified that the 115 kV system in Southwest Minnesota is susceptible to high voltage issues. This area has added many large wind farms and the addition of the CapX Brookings 345 kV line will further enable continued wind growth. The high voltages in the area are due to lack of electrical load in the localized area and the reactive power produced from the wind farm feeder networks under no-wind conditions. The study results have identified that reactor installations at the existing Yankee and Fenton will help mitigate the high voltage issues. The work will be done in two separate projects, at the Yankee substation first and then at the Fenton substation, and would likely be constructed by Xcel Energy employees.

Schedule: Construction is expected to begin in 2018 with a completion date of summer of 2019.

General Impacts: This reactor instillation will be contained in the existing Fenton substation and will not require expanding the substation site. Xcel Energy construction crews are expected to perform the work.

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 2016 with a completion date of early 2017.

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.

The table below identifies those projects by Tracking Number in the Southwest Zone that were listed as ongoing projects in the 2013 Biennial Report but have been completed or withdrawn since the 2013 Report was filed with the Minnesota Public Utilities Commission in November 2013. 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 2011 and the 2013 Reports 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 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: Install four 69 kV breakers and provisions for 115 kV terminations. Future plan is to upgrade two GRE owned 69 kV lines to 115 kV lines.

Need Driver: GRE has been rebuilding transmission facilities north of Veseli substation and the project allows these transmission lines to terminate into the substation. This creates a much more reliable source for the area and allows for future load growth.

Analysis: This project will have the associated construction projects by Xcel Energy and GRE employees. This project will increase local reliability and allow for future load growth.

Schedule: Project is currently underway. Planned in service date is December 31, 2015.

General Impacts: Expansion of the existing substation will minimize future land impact. Alternatives would have been more costly and more environmentally impactful. Construction of a new substation would have required additional land.

MISO Project Description: Install 3 new 69 kV breakers at the Jordan Substation.

Need Driver: This project ties closely with the Veseli Substation project. By adding breakers at the Jordan substation it allows for far greater reliability in the area. Previously a single element contingency would result in large amount of load loss, this solution mitigates that.

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

Analysis: By expanding the existing substation there will be minimal land impact. This will also increase local reliability and will allow for future load growth.

Schedule: Project is currently underway. Planned in service date is December 31, 2015.

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 345kV 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. Planned in service date is 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.

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 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.

The table below identifies those projects by Tracking Number in the Southeast Zone that were listed as ongoing projects in the 2013 Biennial Report but have been completed or withdrawn since the 2013 Report was filed with the Minnesota Public Utilities Commission in November 2013. 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 2011 and the 2013 Reports 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

6.2 The MISO Planning Process

6.2.1 The MISO Transmission Expansion Plan Report

6.3 Northwest Zone

6.3.1 Needed Projects

Clearbrook West 115 kV-Bagley West 230 kV

Moranville 230/69 kV Transformer Replacement

Ulrich 115/69 kV Transformer Replacement

Anderson/Thief River Falls Tap-New Thief River Falls Substation 115 kV Line (Load Tap/Transfer)

Mahnomen/Ulrich Tap-Existing White Earth Substation 115 kV Line (Load Tap/Transfer)

Thief River Falls 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

6.7.2 Completed Projects

6.8 Southeast Zone

6.8.1 Needed Projects

6.8.2 Completed Projects