Studies and Reports > 2025 Biennial Report >Transmission Planning Zones

11.0  Compliance

11.1  Introduction

To facilitate review of the 2025 Report, Chapter 11 consolidates the various compliance requirements from the Commission’s orders, Minnesota legislation, and prior Commission Staff Information Requests.

11.2  2024 Order Accepting 2023 Report Compliance

In the Commission’s June 27, 2024 Order Accepting Report in Docket No. E999/M-23-91, the MTO was ordered to include the information required to be filed in the 2023 Report in their 2025 Report as well as the following:

1. An update on the progress and/or performance of the Grid North Partners’ proposal for nineteen transmission upgrade projects aimed at enhancing reliability and easing congestion in Minnesota;
   1. See Chapter 9 for an update on Grid North Partners work related to congestion and related issues.
2. Information about short-term solutions to increase the robustness of the transmission system they have deployed or plan on deploying along with a report on their performance such as:
   1. dynamic line ratings,
   2. transmission system optimization and reconfigurations,
   3. adjusting transmission conductor limitations to increase line ratings,
   4. increasing substation limiter sizes, and
   5. other grid enhancing technologies that they have deployed or plan on deploying;
1. Appendix B provides the GETs Report in compliance with the Commission’s September 10, 2025 ORDER ESTABLISHING REQUIREMENTS, in Docket No. E999/M-25-99. The specific order points are addressed within the GETs Report.
3. Updates to its response to the PUC Information Requests from May 12, 2023.
1. Section 11.5 below provides an update to these Information Requests.

11.3  Order Establishing Filing Requirements-Nobles County Substation Docket

In the Commission’s March 24, 2025 Order in Docket No. E999/CI-24-316 requires:

1. The MTOs shall include a cost-benefit analysis in their 2025 Biennial Transmission Report that compares any feasible battery storage solution to status quo conditions and to its performance under planned grid upgrades at the Nobles County Substation area.
2. In the 2025 Biennial Transmission Projects Report, to the MTOs shall include an update of the WECS curtailment and economic impact data as provided in the Department’s December 3, 2024 supplemental comments for the Nobles County Substation area and the areas of congestion identified as part of the GETs Study required under the 2024 Session Laws Ch. 126, article 6, section 52, subd. 2. In addition, the MTOs shall consult with the Department in preparation for the 2025 Biennial Transmission Projects Report.

Xcel Energy completed an screening economic analysis using historical Locational Marginal Price (LMP) data using a 300 MW BESS for years 2024 through 2025. Based on our current assumptions on how the BESS would typically operate it was concluded that a 300 MW BESS would help reduce curtailment in the Nobles area. In addition to the economic analysis, Xcel Energy completed a screening system impact study to determine the potential impact of adding 300 MW BESS at Nobles substation. The preliminary conclusion is a 300 MW BESS with grid forming capabilities improves the area response to local faults. These preliminary studies are available in Appendices C and D. The next steps are to perform a final analysis after the specific Nobles BESS details are determined and work with MISO to determine if the Operating Guide that limits generation due to prior outages can be modified to reduce the amount of generation needed to keep the system stable or remove the Operating Guide completely. This process will take time to complete.

11.4  Legislative Requirements (2024 Minn. Laws, Ch. 127, Article 42, Section 52)

2024 Minn. Laws, Ch. 127, Article 42, Section 52 requires that entities that own more than 750 miles of transmission lines in Minnesota provide a Grid Enhancing Technologies (GETs) Report as part of the 2025 Report. The full GETs Report is provided in Appendix B in compliance with the Minnesota legislation.

11.5  Updates to Responses to PUC Information Requests from May 12, 2023

Order point C from the Commission’s Order Accepting Report requires the MTO to update its response to the PUC Information Requests from May 12, 2023.

MPUC Information Request No. 1

Question:
Staff requests that the MTOs provide an assessment of the current transmission system in Minnesota and its ability to reach the carbon-free standard by 2040, as required by Minnesota Laws 2023, Chapter 7, section 10 recently passed by the Minnesota Legislature.

Response:
Minnesota Laws 2023, Chapter 7, contains several updates to the clean energy standards set forth in Minn. Stat. § 216B.1691, including additional milestones for renewable energy and new carbon- free energy standards. The standards now include:

*See Minn. Stat. § 216B.1691, subd. 2f, for additional detail relevant to the solar energy standards.

As noted in previous Biennial Reports, the utilities that are required to submit the Biennial Transmission Projects Report are not identical to those that are required to meet the RES, SES, and now the CFS. The utilities participating in this part of the 2025 Biennial Report that will also report on renewable and carbon-free energy include the following:

Investor-owned Utilities
Minnesota Power
Northern States Power Company Otter Tail Power Company

Generation and Transmission Cooperative Electric Associations
Basin Electric Power Cooperative Dairyland Power Cooperative
East River Electric Power Cooperative
Great River Energy
L&O Power Cooperative⁴⁰
Minnkota Power Cooperative

Municipal Power Agencies
Central Minnesota Municipal Power Agency Minnesota Municipal Power Agency
Southern Minnesota Municipal Power Agency
Western Minnesota Municipal Power Agency/Missouri River Energy Services

Power District
Heartland Consumers Power District

Further details on RES and SES requirements are found in Chapter 8. As noted there, future biennial transmission plans will address the CFS as the Commission is currently providing guidance to utilities on various aspects of implementing this new standard.

MPUC Information Request No. 2

Question:
What upgrades, improvements, and future investments in transmission are being planned in order to achieve this requirement?

Response:
The MTO has been participating, along with Commission Staff and other stakeholders, in the robust planning effort that MISO is undertaking through the Long-Range Transmission Planning (LRTP) process. The base planning assumptions for Tranche 2.1 included implementing Minnesota’s new carbon free energy standards by 2040. Further details on MISO LRTP are provided in Chapter 10.

MPUC Information Request No. 3

Question:
Staff requests that the MTOs provide an assessment of how their project planning process will include an analysis of project impacts on environmental justice areas as defined in Minnesota Law 2023, Chapter 7, section 3, including an assessment of the expected local benefits as detailed in section 15 of the same law.

Response:
While each utility’s planning efforts differ slightly, the MTO anticipates the following analyses and engagement will be conducted as part of the planning activities for newly proposed transmission lines in Minnesota:

1. Early in the planning process, mapping tools will be used to identify and assess environmental justice (EJ) communities in the vicinity of each project area. Utilities have relied on the Minnesota Pollution Control Agency’s (MPCA) screening tools to help identify EJ areas.⁴¹ The MTO anticipates that MPCA’s screening tools will be updated to reflect the new EJ definition in Minnesota Laws 2023, Chapter 7, Section 3.
2. Utilities will engage with these potentially affected EJ communities to ensure equitable access to the planning processes, solicit diverse and representative input, and work to understand community values. This engagement is likely to occur through several outreach efforts, including open houses, discussions with community leaders, social media, and other efforts. The goals of this engagement include developing initial understanding of potential project impacts, both beneficial and adverse; gathering preliminary feedback; and establishing an ongoing two-way engagement process.
   
   Tribal governments and Tribal Historic Preservation Offices, identified through the U.S. Department of Housing and Urban Development’s Tribal Directory Assessment Tool or the Minnesota Indian Affairs Council as having historic ties to land in proximity to planned project areas will be notified early in the planning process, so that Tribes have the opportunity to advise of any sensitive historical or cultural sites to be avoided.
3. In parallel with the identification and engagement processes, the utilities will also work to identify local benefits as listed in Minnesota Laws 2023, Chapter 7, Section 15.

Consistent with current practice, the MTO anticipate information gathered in these processes will be reflected in any resulting Minnesota certificate of need and route permit applications, so the information is available for the MPUC’s consideration as part of the full record.

MPUC Information Request No. 4

Question:
Staff requests the MTOs provide comments on what actions are being taken to alleviate congestion in Southwest Minnesota and to help limit the curtailing of wind resources in that area.

Response:
MTO utilities have taken numerous actions in recent years to alleviate congestion in Southwest Minnesota in an effort to limit curtailment of wind resources in this area. These efforts include:

1. NSP System Upgrades: Xcel Energy did an internal analysis to determine small projects designed to remove system limiters on congested lines in Southwest Minnesota. These projects typically focused on substation equipment and sag limits. Projects budgeted are listed below:

Xcel Energy Congestion Projects

2. Xcel Energy initiated an out-of-cycle request to MISO for completing the second 345 kV circuit from Brookings Co-Lyon Co and Helena-Hampton for the existing CAPX Brookings-TC facility. This project is fully in service as of September 2025.
3. Market congestion projects:
   1. Forman 230/115 kV transformer upgrade
   2. De-bifurcation of High Bridge to Rogers Lake 115 kV line to give High Bridge additional outlet using existing transmission availability.
   3. Fergus Falls-Morris 115 kV line upgrades
   4. Hoot Lake 115 kV substation upgrades
   5. Canby-Granite Falls 115 kV line upgrade
   6. Xcel Energy and ITC Midwest constructed the Huntley-Wilmarth 345 kV Market Efficiency Project (MEP)
      
4. Transmission System Reconfiguration: Xcel Energy implemented a process to study reconfiguration requests from outside entities. These requests are looked at to determine effectiveness, duration, and impact to the transmission system. Reliability is the primary determinant to whether a reconfiguration request is approved. MISO is working on setting up their process which Xcel Energy will participate in.
5. The MTOs worked with MISO and other stakeholders to change how ERIS impacts are identified in the MISO DPP process. The original distribution factor (DF) was 20% and the proposal reduced the DF to 10% in some instances, to ensure that more generation is not interconnected without necessary transmission facilities being built to deliver the energy to the system.
6. Xcel Energy has initiated two projects, MN Energy Connection and King Connection, that are designed to utilize existing transmission access rights. The MISO interconnection queue has a significant number of new interconnection requests currently seeking to connect to a system that is already very congested. Reusing existing transmission rights through the MN Energy Connection and King Connection Projects allows Xcel Energy to interconnect additional MWs through its existing transmission rights, avoiding long delays often related to MISO queue interconnection studies.
7. Xcel Energy confirmed the first system reconfiguration project in Southwest Minnesota to help alleviate congestion in the area. This request was reversed after several months due to a policy issue with MISO and SPP. In October 2022, MISO and SPP began coordinating their Day Ahead studies to recognize some of each other’s flowgates which will help reduce SPP flows on the system. SPP previously did not recognize MISO flowgates and set a dispatch that could negatively impact MISO’s dispatch.
8. In 2023, Grid North Partners conducted a study which identified 19 projects which will address system congestion in the near-term. In 2025, the MTO published the inaugural GETs Study which identified 34 additional solutions to reduce congestion. See Section 9 for additional details.
9. MISO LRTP Tranche 1 projects in Minnesota are utilizing the existing 345 kV second circuit capabilities where possible which will increase the overall ability to transfer power across the system.
10. MISO LRTP Tranche 2.1 projects in Minnesota, specifically the PowerOn Midwest 765 kV line and transformation to the 345 kV system (Big Stone – Brookings, Brookings – Lakefield) will increase overall transfer capability of the system and should alleviate some of the acute congestion in Southwest Minnesota.
11. Xcel Energy has initiated an internal study process to determine any transmission system reconfigurations on the underlying transmission system able to have a positive impact on the bulk transmission system and congestion. Xcel Energy Transmission Operations takes system reliability and curtailment and congestion cost impact into consideration when scheduling transmission outages.
12. Xcel Energy has been monitoring congestion and curtailment on a weekly basis to find new issues as they arise and determine whether a permanent solution is warranted or if the congestion is related to temporary system conditions.
    
    GRE is examining factors that have led to increased market congestion, where congestion is occurring and what we can do in the near-term to address present congestion. GRE is undertaking this congestion effort with the goal of positioning the grid for operational reliability and market efficiency.
    
    In April 2021, GRE was asked to develop an operating guide associated with the Helena- Scott County 345 kV outage and the Chub Lake 345/115 kV transformer to alleviate congestion.

MPUC Information Request No. 5

Question:
Staff requests that the MTOs provide information on recent congestion problems, solutions to the problems implemented over the last 3 years, and potential mitigation alternatives still under consideration, including non-transmission alternatives.

Response:
See MTO’s response to MPUC Information Request No. 4 and the GETs Report in Appendix B.

MPUC Information Request No. 6

Question:
Staff requests that the MTOs provide comments on Minnesota area congestion problems and mitigation including non-transmission alternatives which may not be obvious from MISO MTEP planning.

Response:
Grid North Partners (DPC, OTP, MP, MRES, CMMPA, RPU, SMMPA, WPPI, Xcel Energy and GRE) conducted a study to identify the root causes of congestion from July 2020 to July 2022. The study identified 94 facilities in and around Minnesota causing congestion in Minnesota. The second circuit on the Brookings Co-Lyon Co and Helena-Hampton transmission lines, along with five other projects to upgrade facilities are already submitted in MISO’s MTEP to mitigate some of this congestion. The study identified 19 facilities able to be upgraded to mitigate congestion. Much of the congestion observed is due to high-wind weather patterns with much longer duration that the typical 4-hour batteries available as non-transmission alternatives.

Xcel Energy and other TOs have been working with MISO through the stakeholder process to request changes to the Generator Interconnection studies to ensure that necessary system upgrades are identified in the study process. Xcel, and other stakeholders including Transmission Owners have advocated for a few policy changes, including different Dispatch Assumptions within GI studies (for example, ensuring that Existing Resources of the same Type as the Study resources are dispatched at the same level as the Study Resources interconnecting at the same Bus) or changing the DFAX % which triggers upgrades. MISO did change the DFAX%, but has not agreed to change Dispatch Assumptions. Local Planning Criteria could be utilized to piecemeal these requirements, as OTP and others have done.

Also see MTO’s response to MPUC Information Request No. 4 and the GETs Report in Appendix B.

MPUC Information Request No. 7

Question:
Staff requests information about the status of MISO’s Long Range Transmission Planning (LRTP) and the MISO-Southwest Power Pool (SPP) Joint Targeted Interconnection Queue (JTIQ) processes.

For the LRTP, provide specific information on the status of the MISO-approved Tranche 1 projects and the Tranche 2 study.

Response:
See Chapter 10 for information regarding MISO LRTP and related MISO projects in Minnesota. MISO and SPP released the completed JTIQ study in March of 2022.⁴² The study identified a seven-project JTIQ Portfolio with a planning level estimated cost of $1.65 billion. The recommended JTIQ Portfolio is expected to fully address the set of transmission constraints evaluated in the JTIQ Study as being significant barriers to the development of new generation along the SPP-MISO seam. The Planning Advisory Committee within MISO presented the JTIQ draft tariff additions and revisions on April 26, 2023, and comments were due by May 10, 2023. MISO and SPP are targeting filings with FERC for approval of the tariff and related interconnection agreements in Q3 of 2023 and MISO and SPP Board approvals in December of 2023 or Q1 of 2024.⁴³

MPUC Information Request No. 8

Question:
Staff requests as assessment of whether the LRTP and JTIQ processes are progressing and that the identified upgrades will be available in a timely manner.

Response:
See response to MPUC Information Request No. 7. The MTO utilities are working with MISO to ensure these projects are approved in a timely manner, but the nature of cost allocation changes increases uncertainty in approval timing.

With respect to LRTP processes, the MTO utilities are progressing on a timeline to place the projects in service by the MISO-approved dates. We are continually analyzing project timelines to leverage any efficiencies that may be available.

MPUC Information Request No. 9

Question:
Staff requests a discussion of the steps taken by utilities to encourage MISO to keep the LRTP and JTIQ processes on-track for a timely decision by MISO’s board of directors.

Response:
Both LRTP Tranche 2.1 and JTIQ Portfolios were approved in December of 2024 by the MISO Board of Directors.

Each of the MTO utilities that are members of MISO regularly participated in MISO workshops and planning activities to support the timeline completion of the LRTP and JTIQ processes. These efforts include, but are not limited to, providing timely responses to information requests and carefully reviewing modeling assumptions to ensure they are as accurate as possible.

For example, Xcel Energy is a regular participant in open stakeholder meetings, as well as individual meetings with MISO staff and leadership to underscore the urgency needed in these efforts. To better assist MISO, Xcel Energy has increased the rigor of feedback and provided detailed information on model building as well as early routing and siting impacts to ensure efforts to advance JTIQ and LRTP Tranche 2.1 aren’t subjected to excessive iteration in the stakeholder process. Xcel Energy has also increased coordination with our neighboring utilities to better understand the positions of each company and address any misalignment prior to MISO’s project submission and alternatives request.

L&O and EREPC are members of SPP’s Zone 19 (Upper Missouri Zone or “UMZ”) and participate in the applicable UMZ meetings. Due to their location along the SPP-MISO seam, L&O and EREPC promote SPP-MISO coordination and proposed projects & improvements along the seam. This includes helping to keep the JTIQ process moving forward.

11.6  Congestion Order

Chapter 9 provides the information in compliance with the Commission’s March 24, 2025 ORDER ESTABLISHING FILING REQUIREMENTS, in Docket No. E999/CI-24-316.

40 L&O Power Cooperative (“L&O”) and East River Electric Power Cooperative (“EREPC”) are members of and contract with Basin Electric Power Cooperative (“Basin”) to supply all generation beyond L&O’s and EREPC’s Western Area Power Administration (“WAPA”) allocation. It will be Basin’s obligation to adhere to the applicable generation laws in Minnesota. Also, L&O and EREPC are members of Southwest Power Pool (“SPP”) who performs the transmission planning on the system. L&O and EREPC intend to construct new or upgrade existing facilities as directed by SPP as a result of additional load flows realized by the addition of local carbon-free generation sources.

41 See e.g., https://mpca.maps.arcgis.com/apps/MapSeries/index.html?appid=f5bf57c8dac24404b7f8ef1717f57d00.

42https://www.spp.org/engineering/spp-miso-jtiq/

43https://cdn.misoenergy.org/20230426%20PAC%20Item%2006c%20JTIQ%20Update%20and%20Draft%20Tariff %20Presentation628664.pdf