Studies and Reports > 2023 Biennial Report > Biennial Report Requirements

2.0 Biennial Report Requirements

2.1   Generally

Prior Reports
This is the twelfth Biennial Transmission Projects Report to be filed by those utilities that own or operate electric transmission lines in Minnesota. The obligation to file such a report was created by the Minnesota Legislature in 2001.3 The statute requires the utilities to file their transmission report by November 1 of each odd-numbered year.

All previous reports are all available on the Commission’s eDockets webpage using the Docket Number from the table below. The past reports are also available on the webpage maintained by the utilities: http://www.minnelectrans.com/. The 2023 Report will also be posted on that webpage.

Minn. Stat. § 216B.2425 requires the utilities to list in the report specific present and reasonably foreseeable future inadequacies in the transmission system in Minnesota. The term “inadequacy” was not defined by the Legislature or by the Commission. The utilities have consistently stated that the term “inadequacy” is interpreted to be a situation where the present transmission infrastructure is unable or likely to be unable in the foreseeable future to perform in a consistently reliable fashion and in compliance with regulatory standards. This definition has been accepted by the Commission and others in past dockets.

The statute spells out certain categories of information that should be included in the report for each inadequacy, and the Commission has adopted rules to expand and clarify what is expected to be in the report.4 These laws generally require not only an identification of present and foreseeable inadequacies but also a discussion of alternative ways of addressing each inadequacy and the potential issues and impacts associated with possible solutions to the situation. The utilities are also required to provide opportunities for public input in the planning and development of solutions to the various inadequacies and to describe in the report the efforts undertaken to involve the public. The utilities discuss in Chapter 4 various efforts that have been undertaken to involve the public in transmission planning.

Over the years, in response to experiences with the rule requirements and to other developments in transmission planning, the MPUC has modified the application of the rules in a number of significant ways. One important modification recognizes that most transmission planning is now approved through MISO. MISO prepares a report each year, called the MTEP Report. MISO transmission planning is conducted in public forums and the MTEP Report is publicly available on the Internet. Unlike this state report, which is prepared every other year and focuses only on Minnesota, the MTEP Report is updated yearly and describes in detail transmission planning needs throughout the entire jurisdictional area of MISO, and not just in Minnesota. 

Consequently, for the past six biennial reports – 2011, 2013, 2015, 2017, 2019 and 2021 – the Commission has allowed the utilities to reference the latest MTEP Report to provide information about the identified inadequacies in Minnesota. The 2023 Report, with the Commission’s concurrence, also relies on the latest MTEP Report to identify upcoming transmission needs and to provide the necessary information about the possible alternatives considered to address each inadequacy. The utilities explain in section 6.1 ways to find the pertinent information about each inadequacy in the MTEP Report. 

The MPUC has also recognized that holding public meetings around the state and holding a webinar to describe ongoing transmission planning and needs has not resulted in any substantial participation by the public. The MPUC has granted the utilities a variance for the past several years from the requirement in the rules to hold yearly planning meetings in each transmission planning zone. For 2023, the MPUC has continued this variance and exempted the utilities from holding a webinar. However, the utilities continue to conduct transmission planning in a manner that is open to the public and opportunities are provided for the public to participate in such planning and in the discussion of alternative solutions to the transmission needs under review. MISO also holds meetings open to the public to discuss their transmission plans and processes.

In its 2022 Order accepting the 2021 Biennial Report, the Commission said that the MTO shall include content similar to 2021 Report, and include:

1. Expected sustained HVTL or generation planned outages;
2. Whether those outages are anticipated to have new or incremental congestion; and
3. Whether those outages are anticipated to contribute to sustained incremental congestion.

Waiver Request for 2025 Report
The MTO requests the Commission to extend the rule variances granted in the June 29, 2022, Order accepting the 2021 Biennial Report (and previous orders) for the 2025 Biennial Report as well, such that the future report requirements will mirror the content, notice and participation requirements of this 2023 Biennial Report. The MTO requests it be allowed to continue to reference the latest MTEP Report to provide information about the identified inadequacies in Minnesota and that the public meeting or webinar requirements in Minn. Rule 7848.0900 and related to outreach in Minn. Rule 7848.1000 be waived. As has been demonstrated in previous biennial report proceedings, application of these rules would excessively burden the MTO by requiring them to spend money and divert engineers and other experts to producing duplicative information and attend meetings that do not appear to have a corresponding public benefit; prior lack of public participation in the public meetings and webinars demonstrates that waiving the rules does not adversely affect the public interest, and granting the variances is not contrary to any standard imposed by law.

We will provide a link to the report on the MTO website, www.minnelectrans.com as well as directions to access the report via eDockets.

2.2    Reporting Utilities

Minn. Stat. § 216B.2425 applies to those utilities that own or operate electric transmission lines in Minnesota. The MPUC has defined the term “high voltage transmission line” (HVTL) in its rules governing the Biennial Report to be any line with a capacity of 200 kilovolts or more and any line with a capacity of 100 kilovolts or more and that is either longer than ten miles or that crosses a state line.5  Each of the entities participating in filing this report owns and operates a transmission line that meets the MPUC definition. Information about the utility and transmission lines owned by each utility is provided in Chapter 7 of this Report.  In addition, a contact person for each utility is included in Chapter 7.

The statute allows the entities owning and operating transmission lines to file this report jointly. The MTO has elected each filing year to submit a joint report and does so again with this report. The utilities jointly filing this report are:

American Transmission Company, LLC
Central Minnesota Municipal Power Agency
Dairyland Power Cooperative
East River Electric Power Cooperative
Great River Energy
ITC Midwest LLC
L&O Power Cooperative
Minnesota Power
Minnkota Power Cooperative
Missouri River Energy Services
Northern States Power Company d/b/a Xcel Energy
Otter Tail Power Company
Rochester Public Utilities
Southern Minnesota Municipal Power Agency

Of the above utilities, East River Electric Power Cooperative, L&O Power Cooperative and Minnkota Power Cooperative are not members of MISO; all the others are. Since the Mid-Continent Area Power Pool (MAPP) was dissolved in late 2015, resulting in the termination of MAPPCOR, the nonprofit organization that did the planning work for the MAPP utilities, MISO has performed many of the planning roles for Minnkota Power Cooperative.

2.3    Certification Requests

Minn. Stat. § 216B.2425, subd. 2, provides that a utility may elect to seek certification of a particular project identified in the Biennial Report. According to subdivision 3, if the Commission certifies the project, a separate CON under Minn. Stat. § 216B.243 is not required.

On May 30, 2023, the MTO filed a letter to the Commission in the instant docket that there would be no certification requests included with the 2023 Biennial Report.

2.4    General Impacts

In its May 12, 2014, Order approving the 2013 Biennial Report, the Commission recognized that reference to the latest MTEP Report was an appropriate way to provide useful information about the inadequacies identified in the Biennial Report, but that the MTEP Report did not provide general information about the potential environmental, social, and economic impacts of possible alternatives to address the inadequacy, as required by Minn. Stat. § 216B.2425, subd. 2(c)(3). The Commission stated in its Order at page 6 that “in the future the information [in the MTEP Report] must be supplemented with a fuller discussion of economic, environmental, and social issues related to proposed alternative solutions to inadequacies listed in the report.”

The Commission stated in its May 27, 2016, Order approving the 2015 Report that the MTO “shall include in the 2017 Report the requirements addressed in Minn. Stat. § 216B.2425, subd. 2(c)(3).” Since the Commission and the Department of Commerce staff determined that the information the utilities provided in the 2015 Biennial Report satisfied the obligation to report on these impacts, the MTO will address the potential impacts of the various projects in the same manner in this Report. The discussion below describes how these impacts are addressed.

First, it is difficult to provide significant information about a transmission need expected several years in the future. The MPUC rules require the utilities to identify inadequacies that might affect reliability over the next ten years.6 A transmission planner is often unable to identify possible alternatives or the impacts of the alternatives, for inadequacies ten years in the future. Moreover, it is not uncommon for a potential reliability issue that may be several years in the future to subsequently be delayed for several more years or even indefinitely because of unforeseen events such as an economic recession or the closing of a large industrial customer or even a change in government policy or tax provisions. Also, more pressing problems may develop that take precedence over more minor concerns and transmission planners may have to focus their attention on other projects. 

Importantly, the statute says the utilities are to identify general economic, environmental, and social issues associated with each alternative. These are issues not always possible to know during the planning stage; various issues may evolve when a particular project is developed in more detail. It is sufficient to address potential issues in a general way, as the utilities have done here. 

While it is not possible for the utilities to provide specific discussion of potential impacts for each of the approximately 164 separate Tracking Numbers identified in this Biennial Report, transmission planners and utility staff are well aware of the kind of issues that arise with any large energy facility, whether a transmission line or a generating plant. For example, a transmission line may cross a wetland, or run through an agricultural field, or follow a residential street. A new generating plant has a certain footprint, and may result in the emission of various pollutants, and may require the transport of fuel. A large energy project has tax consequences for local government. Jobs will be created by the construction of a new facility, and the local area will be disrupted for a time while construction is ongoing. These are the kind of general impacts that can be addressed for projects that have not developed to the point of specific alternatives having been identified. 

An in-depth analysis of potential impacts of a proposed project and the identified alternatives will be provided once the utility has determined that a need for new infrastructure is certain enough and imminent enough that a project must be pursued. This is the time the public generally begins to take notice of the need for a project and to participate in the analysis of alternatives. And this is the time the utility must begin to pull together the information required to complete applications for a CON and for a permit. These applications, and any environmental review conducted as part of the application process, will examine potential economic, environmental, and social issues in depth, with opportunities for public involvement and input. 

The MTO can provide in this Biennial Report only a general discussion of the kind of impacts associated with certain types of energy projects, like transmission lines and substation upgrades and generating facilities. A more detailed discussion of impacts will be provided when a specific project has been identified, alternatives have been considered, and permit application have been submitted.

2.5    Renewable Energy Standards

The utilities are required to include in the Biennial Report a discussion of necessary transmission upgrades required to meet upcoming renewable energy standards.7 In 2023, the Minnesota Legislature amended the objectives set forth in Minn. Stat. § 216B.1691 to include additional milestones for renewable energy as well as creating new carbon-free energy standards (CFES) (see Minn. Laws 2023, ch. 7). As with previous reports, this discussion is included in Chapter 8.

2.6    Distribution Report & Grid Modernization

In 2015 the Legislature amended Minn. Stat. § 216B.2425 to add two additional requirements for utilities operating under multiyear rate plans, a category that at present includes only Xcel Energy. Subdivision 2(e) requires Xcel Energy, at the time of the Biennial Transmission Projects Report filing, to report:

investments that it considers necessary to modernize the transmission and distribution system by enhancing reliability, improving security against cyber and physical threats, and by increasing energy conservation opportunities by facilitating communication between the utility and its customers through the use of two-way meters, control technologies, energy storage and microgrids, technologies to enable demand response, and other innovative technologies.

This reporting requirement is often referred to as the Grid Modernization Report. The MPUC in May 2015 opened a separate docket for consideration of efforts related to modernization of the transmission and distribution grid. (MPUC Docket No. E999/CI-15-556.)

Further, subdivision 8, which was also added in 2015, provides:

Each entity subject to this section that is operating under a multiyear rate plan approved under section 216B.16, subdivision 19, shall conduct a distribution study to identify interconnection points on its distribution system for small-scale distributed generation resources and shall identify necessary distribution upgrades to support the continued development of distributed generation resources, and shall include the study in its report required under subdivision 2.

These reporting requirements apply only to utilities operating under an approved multiyear rate plan approved by the MPUC under section 216B.16, subd. 1, and Xcel Energy is the only utility currently operating under such a plan and the only utility required to file a distribution study and grid modernization plan. The table below shows the Biennial Distribution-Grid Modernization Reports that Xcel Energy has submitted under Minn. Stat. § 216B.2425.

2.7    Non-Wire Alternatives

Overview
In the Commission’s June 12, 2018 Order Accepting Report, Granting Variance, and Setting Additional Requirements, in Docket No. E999/M-17-377, Order Point 2 states:

In their 2019 Report, the MTO shall include content similar to 2017 Report, and include an improved and expanded assessment of non-wire alternatives . . . .

This section provides a broad discussion of non-wires alternatives to give context for the analysis that follows in Chapter 6, where potential non-wires alternatives are discussed for applicable transmission projects.

Application of Non-Wires Alternatives
Overall, this Report identified approximately 164 transmission inadequacies in the State and proposes transmission or non-wires alternatives to address them. The identified transmission inadequacies fall into the following general categories: load interconnection, generator interconnection, thermal overloads and voltage violations.

Depending on the type of issue and its magnitude, each project’s transmission owner may consider a broad range of alternatives for addressing reliability concerns. Alternatives considered may include both wire and non-wire solutions. The types of alternatives considered for a particular issue are dependent on the nature of the problem to be addressed. To be a viable alternative, a solution must be available (1) at the necessary time, (2) with the necessary response, and (3) for the necessary duration, to address the inadequacy at hand.

Non-wires alternatives are electric utility system supply-and demand-side projects and operating practices that defer or replace the need for specific transmission projects, at lower total resource cost, by reliably reducing transmission congestion at times of high demand in specific grid areas. Examples of non-wires transmission alternatives may include: establishing new operating guides or procedures, demand side management (DSM), distributed generation (DG), and storage of electricity or heat or ponded water.

Generally speaking, certain categories of non-wires alternatives may be best suited to address certain categories of identified transmission inadequacies. For example, the need for local load serving transmission could potentially be alleviated or delayed with DSM or appropriately sited renewable generation including DG interconnections on the distribution system. The availability of DG has the effect of reducing the need to serve the load from the transmission system and has the greatest impact if the DG is available during peak load conditions. Solar PV offers a positive, but not perfect, correlation with high load periods during the summer, while a combination of distributed solar and/or wind with distributed storage offers the greatest impact to reduce effective loads served. Transmission planners continue to evaluate non-wire options that result in the avoidance of establishing new transmission lines. As the costs of non-wire alternatives become more competitive with traditional wire solutions, the transmission planners are closely examining DG and other distribution solutions against transmission alternatives.

Implementation of non-wires alternatives can also bring different challenges. For example, as DG penetration grows, the communication technology will have to be improved to manage DG installations. There will be more points to monitor to ensure load can be reliably served from multiple generation resources. Real time system operations will become more complex as the generation becomes more variable and concentrated. Distribution automation likely will be needed to assist the operator in shifting load to other systems if the expected generation resources are not available. 

More DG on the system and in closer proximity to load decreases reliance on the transmission system. Solar is anticipated to be the more common type of DG in the future, but fuel-cell technology or some yet unknown generation source or Load Modifying Resource (LMR) may also become viable alternatives. It is expected that storage capabilities will follow the adoption and installation of solar and wind to allow more full use of the renewable resources and increase their value throughout the daily load cycle. Storage can also increase the off-the-grid opportunities for existing and future electric users.

The table below describes the benefits and challenges of different types of non-wires alternatives in addressing identified categories of transmission deficiencies.

Conclusion
Non-Wire Alternatives are discussed in Chapter 6 and are deployed as deemed appropriate by the project transmission owner based on the nature of the transmission inadequacy. The Minnesota Transmission Owners remain committed to evaluating non-wires alternatives to proposed transmission projects and may revisit these analyses based on future technological improvements and cost efficiencies.

2.8    FERC, MISO, and Commission Actions Related to Distributed Energy Resources and Distribution Planning

In the Commission’s June 12, 2018 Order Accepting Report, Granting Variance, and Setting Additional Requirements, in Docket No. E999/M-17-377, Order Point 2 states:

In their 2019 Report, the MTO shall include content similar to 2017 Report, and include  . . . a discussion of relevant actions by FERC, MISO, and the Commission related to distributed energy resources and distribution planning.

The Commission, the Federal Energy Regulatory Commission (FERC), and MISO, discuss distributed energy resources and distribution planning in a wide range of dockets and contexts. In this section we include the discussion of relevant actions by the Commission, FERC and MISO related to distributed energy resources and distribution planning.

Minnesota Public Utilities Commission
Broadly speaking, the Minnesota Public Utilities Commission has addressed distribution planning and distributed energy resources in a wide variety of policy,9 planning,10 fact specific11 and annual reporting dockets.12

FERC
The 2021 Biennial Report discussed FERC Order Nos. 841 and 2222 as they pertain to storage and non-storage Distributed Energy Resource (DER) aggregations participating in wholesale markets.  Since the last report, FERC issued Order No. 2023, adopting reforms to modernize the transmission grid by streamlining the interconnection processes for transmission providers.

Order No. 2023, adopted in July of 2023, includes several reform to the interconnection processes, such as instituting a first-ready-first-served cluster study process, increased financial commitments for interconnection customers, improved efficiency of the interconnection process, firm deadlines and penalties for transmission providers if they fail to complete their interconnection studies on time, and incorporating technological advancements into the interconnection process, such as consideration of advanced transmission technologies in the interconnection study process and an update of modeling and performance requirements for inverter-based resources to ensure continued system reliability.  The final rule requires all public utilities to adopt revised pro forma generator interconnection procedures and agreements to ensure that interconnection customers can interconnect to the transmission system in a reliable, efficient, transparent, and timely manner, and to prevent undue discrimination.

MISO
In 2021, MISO noted on its website that “[a] high penetration of [DERs] could have notable implications for MISO and require a stronger transmission and distribution interface. The DER issue [in the MISO stakeholder process] is intended to explore and advance collaboratively developed DER priorities with stakeholders.” MISO subsequently held a number of stakeholder workshops that resulted in a number of changes supporting the coordination of DER between DER interconnection customers, distribution providers, transmission owners, and MISO. Most notably, the creation of the MISO DER Affected System Study (AFS) will promote coordination and study of DER that exceed certain impact thresholds on the transmission system. The changes and improvements resulting from this new process may act as an important catalyst for enabling DER participation in the larger power system.

MISO filed its Order No.  841 compliance filing in December 2018 with the provisions regarding DERs. Subsequently, in their response to FERC’s request for more information filed in April 2019, MISO updated their Distribution Connected Electric Storage Resource (ESR) form agreement to require an attestation from the ESR that all necessary metering and other arrangements are completed before they can participate as a distribution connected ESR in MISO. FERC accepted MISO’s Order No. 841 compliance filing in November 2019 with an effective date of June 2022. The changes associated with this filing went into production on September 1, 2022.

In Order No. 2222, FERC established a compliance date for the Regional Transmission Operators (RTO) and Independent System Operators (ISO) of July 19, 2021. MISO filed a request to extend that date until April 18, 2022, and FERC granted MISO’s request. MISO’s proposal was submitted is currently awaiting ruling after additional comments were requested from MISO and submitted to FERC. MISO’s DER Task Force (DERTF) has continually met to discuss the topic of implementing Order No. 2222, which may transition to other DER related topics after the ruling on MISO’s filing of Order No. 2222 is complete.

Grid North Partners (GNP)
Grid North Partners, an evolution of CapX2020, is a voluntary partnership of 10 Minnesota and surrounding area transmission owning utilities formed in 2004 to collaboratively expand the Upper Midwest transmission grid. Approximately three years ago, GNP, recognizing a rapid change was occurring and the challenges facing the transmission grid needed to be identified, published the CapX2050 Transmission Vision Report so solutions could be identified. GNP has been working to identify solutions to address those key findings via two primary avenues:

• Technical efforts – consisting of collaborative participation in MISO’s Long-Range Transmission Planning (LRTP) effort, and
• Education & stakeholder engagement – including dialog with policy makers, utilities, stakeholders, and landowners to discuss needed improvements to ensure the transmission system in the Upper Midwest is prepared to deliver tomorrow’s energy 24 hours a day, 7 days a week.

GNP Technical Effort: GNP Members have been actively coordinating as MISO develops their LRTP Tranche 2 study. Coordination around system modeling, study assumptions and solution alternatives will help develop provide feedback as the LRTP Tranche 2 effort continues into 2024. A transmission congestion study was also completed by the GNP Technical Team. The study reviewed historical and projected transmission system congestion in the MISO market with an effort to identify potential system upgrades that could potentially reduce congestion in the GNP footprint. The congestion effort was wrapped up in 2023 and at least 21 projects from several GNP member companies are underway to increase transmission capacity and reduce market congestion in the GNP footprint.

Institute of Electrical and Electronics Engineers (IEEE)
While not specifically requested by Commission, another important aspect is various entities’ work on IEEE 1547-2018, which is a recently published DER interconnection and interoperability standard.

The revised standard addresses three new broad types of capabilities for DER: local grid support functions; response to abnormal grid conditions; and exchange of information with the DER for operational purposes. The standard was written with a large set of required capabilities with an expectation that not all capabilities would be immediately implemented in the field. In this way, it offers options for grid operators preparing for scenarios with high penetration of DER. Some details associated with implementing the standard are part of the Commission’s E002/M-16-521 docket, especially in Phase II which considers statewide technical standards, and other details are expected to be associated in utility business practice decisions.

In terms of specifying DER response to abnormal grid conditions, IEEE 1547 indicates the Authority Governing Interconnection Requirements and Regional Reliability Coordinator possess a guidance role in implementing these capabilities, which, in Minnesota, are the Minnesota Commission and MISO respectively. Commission Staff requested information and guidance from MISO through a working group associated with the E002/M-16-521 docket. The response from MISO included a plan to convene a stakeholder group so guidance on the topic could be provided on a regional basis. The Commission’s interest in resolving questions associated with adopting these capabilities is helping to drive important stakeholder conversations.

Local grid support functions have generated interest in the industry in recent years based on implementation of these functions in states such as Hawaii and California in areas of high DER deployment. The IEEE 1547-2018 standard allows a utility to specify ways local grid support functions are to be used. Xcel Energy proposed in the E002/M-16-521 docket that use of the local grid support functions should be published in utility-specific technical manuals.

The interoperability aspects of IEEE 1547-2018, which include concepts of DER monitoring and control, mark the most future leaning required capabilities. When certified equipment is available, every DER will have a standardized communication interface for exchanging data and performing remote operations. A communication network would be necessary for making use of the interoperability interface.

Electric Power Research Institute (EPRI)
EPRI has led several efforts to understand the general technical needs to meet compliance with FERC Order 2222. The EPRI workplan is divided into phase 1 and phase 2. EPRI released several collaborative reports for phase 1 in July of 2021. Various MTO utilities have been participating in the working groups to aid in the development of the collaborative reports.

The first report focuses on the metering, data, information and telemetry requirements for ISOs and RTOs, distribution utilities, transmission utilities, DERs and aggregators. The report is a guidance for future market and interconnection requirement design. 

The second report focuses on the systems interoperability and cyber security of DER and aggregators to ensure best practices are identified to maintain system security in the decentralized environment. 

The third report focuses on the role of the distribution utility in enabling market participation for DERs and aggregators in wholesale markets. The report is intended to provide high level technical guidance for what is required to fulfill various roles. 

Finally, EPRI is also providing guidance to the Transmission Operators with a shorter technical briefing to provide guidance on the various ways to ensure reliability in a distributed environment. 

2.9    MISO and Minnesota’s Transmission Needs

In the Commission’s August 19, 2020 Order Accepting Report, Granting Variance, and Setting Additional Requirements, in Docket No. E999/M-19-205, Order Point 5(d). states:

The MTO shall describe its efforts to engage with MISO to ensure that Minnesota’s transmission needs have been met, and shall provide an assessment of whether MISO has been responsive to Minnesota’s identified and likely transmission needs.

Minnesota TOs participate in many different MISO processes to ensure our needs are being addressed and our voices are being heard. MISO has several different TO groups set up to address various functions under MISO control. Below are the MISO Groups and processes that Minnesota TOs are involved in.

MISO Planning Advisory Committee (PAC): The PAC is formed to provide advice to the MISO Planning Staff on policy matters related to the process, adequacy, integrity and fairness of the MISO-wide transmission expansion plan. The Planning Advisory Committee reports to the MISO Advisory Committee.

Issues the MISO PAC deal with are typically related to generation interconnection process, annual MTEP reliability process, and tariff and policy issues.
MISO Planning Advisory Committee (misoenergy.org)

MISO Planning Subcommittee (PSC): The PSC advises, guides, and provides recommendations to MISO staff with the goal to enable better execution of its planning responsibilities, in an efficient and timely manner, as set forth in the MISO Tariff, Transmission Owner Agreement, FERC Order 2000 and other applicable documents.
Recent issues have revolved around how storage is going to be treated in MTEP and Interconnection studies. A link to that Committee follows.

MISO Planning Subcommittee (misoenergy.org)

MISO Subregional Planning Meeting (SPM): In accordance with FERC Order 890 Attachment K, MISO will host a series of SPMs to encourage an open and transparent planning process. Early in the process, stakeholders will participate in discussions of planning issues and proposals on a more local basis to discuss projects, issues and concepts potentially driving new transmission expansion on the grid. A link to those follows.

Subregional Planning Meeting (misoenergy.org)

MISO Regional Expansion Criteria and Benefits Working Group (RECBWB): The RECBWG is the forum for stakeholders to discuss existing or proposed criteria and cost allocation policies for regional and interregional cost-shared transmission projects.
The main issue for this group currently is cost allocation related to the recent LRTP effort on-going in MISO. Efforts to split MISO vs maintaining MISO as one RTO for cost-allocation purposes, as it relates to benefits and who pays is causing some tension across MISO stakeholders. A link to that group follows.

MISO Regional Expansion Criteria and Benefits Working Group (misoenergy.org)

MISO Interconnection Process Working Group (IPWG): The purpose of the Interconnection IPWG is to provide stakeholders a forum to develop revised generator interconnection queue process procedures with the goal of reducing study time and increasing certainty. It is intended that the work product of this Working Group will be included in Tariff filings to FERC and modifications to the Generator Interconnection Business Practice Manual. (BPM-015).
MISO is looking to streamline the process to help with timelines for Interconnection Customers. Some TOs feel this will put pressure on them with an already tight timeframe and MISO should just stick with the timelines already in the tariff. A link to that group follows.

MISO Interconnection Process Working Group (misoenergy.org)

MISO Reliability Operations Working Group (ROWG):  This is a closed group with focus on grid operation and reliability of the system.

A recent issue brought to MISO is related to Transmission System reconfiguration requests from third party sources for economic reasons only. During construction or outages there is some significant congestion noted on the system that is costing some customers money, and they feel reconfiguring the transmission system to accommodate outages is a good option. TOs feel these types of requests and studies do not adequately address reliability concerns.

MISO Transmission Owners Compliance Task Team (TOCTT):  This is a closed group to deal with the compliance efforts at MISO relating to FERC and North American Electric Reliability Corporation (NERC).

MISO Coordination
In the Commission’s June 29, 2022 Order Accepting Report, in Docket No. E999/M-21-111, Order Point 6 states:

The MTO must file, within 90 days, additional information as set forth in ordering paragraph 5(d) of the Commission’s August 19, 2020, order, in Docket E-999/M-19-205, which required a filing within 90 days that included “an assessment of whether MISO has been responsive to Minnesota’s identified and likely transmission needs.”

The MTO believes MISO has been responsive to Minnesota’s identified and likely needed transmission, recognizing a number of challenges that abate progress in these areas.

The need for transmission in Minnesota, and throughout the region, is currently being driven by the continuing transition from central station conventional generation to a generation fleet geographically dispersed and highly dependent on wind and solar as primary fuels, supplemented with hydro, nuclear, and natural gas generation. MISO and the MTO are experiencing continued acceleration in this transition, despite limitations related to planning and constructing the transmission needed to fully facilitate the transition.

Partially in response to a request from the MTO via Grid North Partners and the State, MISO undertook a long-term transmission expansion planning initiative in late 2020 to assist in planning for this transition.  MISO’s Renewable Integration Impact Assessment (RIIA) identified renewables in the MISO footprint would reach 40% penetration in the next decade, based on public announcements, and transmission solutions are needed to significantly reduce curtailment of wind and solar generation sources.

The LRTP considered three generation and load profile “futures” (i.e., scenarios), with Future 3 being the more aggressive penetration of renewables and electrification. This comprehensive analysis required the development of robust models incorporating changes in generation and load to reflect Future 1. MISO and the MISO stakeholders engaged in multiple meetings to vet modeling assumptions, study results, and transmission alternatives to address the reliability issues presented by Future 1, which was developed to meet 100% of utility IRPs and 85% of utility announcements, state mandates, goals, or preferences. While the MTO would have preferred a more accelerated study process, we recognize the many challenges MISO addressed leading up to the MISO Board of Directors approving $10.4 billion in transmission enhancement on July 25, 2022.

MISO and the upper Midwest transmission owners are now beginning studies to leverage and build upon the no-regret Tranche 1 transmission projects and identify additional transmission projects to address reliability, economic, and resiliency issues present in the MISO Futures 2 and 3. The goal is to put forward another set of transmission projects (labeled Tranche 2) which could be approved by the MISO Board in late 2023 or 2024.