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Studies and Reports > 2021 Biennial Report > Biennial Report Requirements


Transmission Projects Report 2021
Chapter 2: Biennial Report Requirements

2.0 Biennial Report Requirements

2.1   Generally

Prior Reports
This is the eleventh 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. Minn. Stat. § 216B.2425. 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 2021 Report will also be posted on that webpage.

Biennial Report

MPUC Docket Number

MPUC Order

2021 E999/M-21-111  

2019

E999/M-19-205

 

2017

E999/M-17-377

June 12, 2018

2015

E999/M-15-439

May 27, 2016,
Errata June 7, 2016

2013

E999/M-13-402

May 12, 2014

2011

E999/M-11-445

May 18, 2012

2009

E999/M-09-602

May 28, 2010

2007

E999/M-07-1028

May 30, 2008

2005

E999/TL-05-1739

May 31, 2006

2003

E999/TL-03-1752

June 24, 2004

2001

E999/TL-01-961

August 29, 2002

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 that expand and clarify what is expected to be in the report (Minn. Rules Chapter 7848). 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 what efforts were 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 done 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 five biennial reports – 2011, 2013, 2015, 2017 and 2019 – the Commission has allowed the utilities to reference the latest MTEP Report to provide information about the identified inadequacies in Minnesota. The 2021 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 to addressing each inadequacy. The utilities explain in section 6.1 how 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 2021, 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. 

In its 2020 Order accepting the 2019 Biennial Report, the Commission said that the MTO shall include content similar to 2019 Report, and include a full discussion and analysis of next steps for identifying gaps between the existing and currently planned transmission system and the transmission system that will be required to meet the companies’ publicly stated clean energy goals. The MTO shall also address any need for new or expanded transmission to accommodate:

  1. The public clean energy commitments of the MTO member utilities,
  2. The requirements in all approved Minnesota resource plans, and
  3. Relevant Minnesota statutory goals.

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.
Consequently, the 2021 Report closely tracks the 2019 Report but also includes discussions on gaps in transmission related to companies’ clean energy goals and efforts to engage with MISO regarding Minnesota’s transmission needs.

Waiver Request for 2023 Report
The MTO requests that the Commission extend the rule variances granted in the August 19, 2020 Order accepting the 2019 Biennial Report (and previous orders) for the 2023 Biennial Report as well, such that the future report requirements will mirror the content, notice and participation requirements of this 2021 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” 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. Minn. Rule part 7848.0100, subp. 5. Each of the entities that is 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 26, 2021, the MTO filed a letter to the Commission in the instant docket that there would be no certification requests included with the 2021 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 found 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 that is several years in the future. The MPUC rules require the utilities to identify inadequacies that might affect reliability over the next ten years. Minn. Rule part 7848.1300, subpart D. A transmission planner is often unable to identify possible alternatives or the impacts of the alternatives, for projects that are 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 user 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 that the utilities are to identify general economic, environmental, and social issues associated with each alternative. This is a recognition that it is not always possible to know during the planning stage what 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 103 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 where specific alternatives have been identified. 

An in-depth analysis of potential impacts of a proposed project and the identified alternatives will be provided when 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 when the public generally begins to take notice of the need for a project and to participate in the analysis of alternatives. And this is when the utility must begin to pull together the information that is required to complete applications for a CON and for a permit. These applications, and any environmental review that is 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 that are 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. Minn. Stat. § 216B.2425, subd. 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.

MPUC Docket Number

Date Filed

E002/CI-15-962

October 30, 2015

E002/CI-17-776

November 1, 2017

E002/CI-18-251

November 1, 2018

E002/M-19-666

November 1, 2019

E002/M-21-694

November 1, 2021

 

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 103 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 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 particular issue at hand.

Non-wires alternatives are electric utility system supply-and demand-side projects and/or 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 maximum demand in specific grid areas.1  Examples of non-wires transmission alternatives may include: establishing new operating guides or procedures, demand side management (DSM), distributed generation (DG), and electricity and thermal storage.

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 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 solar and/or wind with storage offers the greatest impact to reduce loads regardless of season. Transmission planners continue to evaluate non-wire options that result in the avoidance of establishing new transmission corridors. 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 that 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 thus making it difficult to know how, when or where to reliably deliver the energy. Distribution automation likely will be needed to assist the operator in shifting load to other systems if the expected generation resource is 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 resource and increase its 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.

Non-Wire Alternatives

Type of Trans-mission Project

Solar/Storage

Wind/Storage

Demand Side Management

Load Inter-connection

A combination of solar and storage may be an option for load serving deficiencies.  Storage is needed to ensure that reliability is equal to the availability of transmission options.  Based on geographic locations, land constraints may be a challenge to installation of adequate solar generation to meet the new or expanding load.  In addition, current costs for solar/storage installations are often higher than transmission load serving options.

A combination of wind and storage may be an option for load serving deficiencies.  Storage is needed to ensure that reliability is equal to the availability of transmission options.  Based on geographic locations, land constraints may be a challenge to installation of adequate wind generation to meet the new or expanding load.  In addition, current costs for wind/storage installations are often higher than transmission load serving options.

Demand side management is not applicable for load interconnection projects as the deficiencies are driven by new load.  For existing load expansions, DSM is considered but may not be available in quantities or durations needed to reliably address the deficiency.

Generator Inter-connection

Not applicable for these projects.

Not applicable for these projects.

Not applicable for these projects.

Thermal Overloads

Solar and storage are looked at individually and in combination for transmission thermal overloads.  Since transmission availability is ~99%, viable alternatives will have to have similar availability.  Solar and storage can help alleviate flows on a transmission line depending on their duration and location, but the current costs of these options are typically significantly more expensive than traditional transmission solutions.

Wind and storage are looked at individually and in combination for transmission thermal overloads.  Since transmission availability is ~99%, any option will have to have similar availability.  Wind and storage can help alleviate flows on a transmission line depending on their duration and location, but the current costs of these options are typically significantly more expensive than traditional solutions.

Demand Side Management is an option for transmission thermal overloads.  DSM must be available in adequate amounts and duration and be sufficiently reliable to be called upon to address these transmission inadequacies. 

Voltage Violations

Solar and storage are looked at individually and in combination for voltage violations.  Since transmission availability is ~99%, any option will have to have similar availability.  Solar and storage can help alleviate low and high voltages depending on location, duration and applicability of the installation, but the current costs of these options typically are significantly more expensive than traditional transmission solutions.

Wind and storage are looked at individually and in combination for transmission voltage violations.  Since transmission availability is ~99%, any option will have to have similar availability.  Wind and storage can help alleviate low and high voltages depending on location, duration and applicability of the installation, but the current costs of these options typically are significantly more expensive than traditional transmission solutions.

Demand Side Management is an option for transmission voltage violations.  DSM must be available in adequate amounts and duration and be sufficiently reliable to be called upon to address these transmission inadequacies.

Conclusion
Non-Wire Alternatives are discussed in Chapter 6 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,2 planning,3 fact specific4 and annual reporting dockets.5

Federal Energy Regulatory Commission (FERC)
The 2019 Biennial Report discussed Federal Energy Regulatory Commission (FERC) Order No. 841, which addresses two different levels of participation of storage resources in wholesale markets.  Since the last report, FERC issued Order No. 2222, which removes barriers for distributed energy resource (DER) aggregations to participate in wholesale markets. The following is a brief summary of Order Nos. 841 and 2222 as they pertain to storage and non-storage DER aggregations participating in wholesale markets.

Order No. 841, adopted in February 2018, requires that RTOs and ISOs accommodate the various types of services that electric storage resources can provide, regardless of whether they are interconnected at transmission voltage or to the distribution system.

In September 2020, FERC expanded the requirements applicable to participation of resources interconnected to the distribution system in wholesale markets with issuance of Order No. 2222 in Docket No. RM18-9-000, Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators.

FERC’s Order 841, to the extent it addresses wholesale market participation by DER storage resources, and FERC’s Order 2222, left many key details regarding implementation to resolution by RTOs/ISOs and distribution utilities.  Under the rule, FERC has jurisdiction over the manner in which DER storage resources and DER aggregations participate in wholesale markets while FERC has devolved to the relevant electric retail regulatory authorities (RERRAs) responsibility for regulatory requirements needed to maintain the safety and reliability of the distribution system and allocation of costs associated with accommodating market participation by DER storage resources and DER aggregations.

MISO
According to its website, MISO has noted that “[a] high penetration of Distributed Energy Resources (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.” To that end, MISO has been hosting a series of workshops on DERs throughout the year. MISO is currently working with the Organization of MISO States (OMS) and other MISO stakeholders to develop a DER participation model that accounts for the distinctive characteristics of the MISO region and promotes reliability on a least cost basis.

MISO filed its Order No. 841 compliance filing in December 2018 with the provisions regarding DERs.6  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.
In Order No. 2222, FERC established a compliance date for the RTOs/ISOs of July 19, 2021. MISO filed a request to extend that date until April 18, 2022 and FERC granted MISO’s request.

In January 2021 MISO held the first meeting of its DER Task Force (DERTF). The DERTF has met every regularly since then and will continue meeting until MISO makes its Order No. 2222 compliance filing in April 2022. In addition to the regular monthly meetings of the DERTF, MISO has held one workshop to coordinate Order No. 2222 implementation with the relevant electric retail regulatory authorities (RERRAs) and has another workshop planned in October.

Grid North Partners
Grid North Partners, an evolution of CapX2020, is a voluntary partnership of 10 Minnesota and surrounding area transmission owning utilities7 formed in 2004 to collaboratively expand the Upper Midwest transmission grid. A year ago, Grid North Partners, recognizing that a rapid change was occurring and the challenges facing the transmission grid needed to be identified, so solutions could be identified, published the CapX2050 Transmission Vision Report.8 While CapX2020 is a subset of the MTO members, the issues identified in the CapX2050 Transmission Vision Report impact all MTO entities.

The CapX2050 Transmission Vision Report highlighted four key implications which must be addressed for the future grid to remain reliable for all hours of the year:

  • Current dispatchable resources support the electric grid, by providing reliability attributes, in ways that wind and solar resources presently cannot
  • The ability for system operators to meet real-time operational demands will be more challenging and, therefore, we will need to develop new tools and operating procedures to address the challenges.
  • More transmission system infrastructure will be needed in the upper Midwest to accommodate the transition of resources.
  • Wind and solar alone will be incapable of meeting all consumer energy requirements at all times and therefore, we will need to understand and promote a future electric grid that can continue to meet consumer energy requirements safely, reliably and affordably.

Since the CapX2050 Transmission Vision Report’s publication, Grid North Partners has been working to identify solutions to address those key findings via two primary avenues:

  • Technical effort – Collaborative participation in MISO’s Long-Range Transmission Planning (LRTP) effort, and
  • Education & stakeholder engagement – Dialog with policy makers, utilities, stakeholders, and landowners discuss what it will take to ensure the transmission system in the Upper Midwest is prepared to deliver tomorrow’s energy 24 hours a day, 7 days a week.

Grid North Partners Technical Effort: In May 2020, CapX2020 sent a letter to the MISO requesting MISO initiate a comprehensive, long-term transmission planning analysis using an integrated approach to identify a plan to optimally meet the 2030 goals of utilities, their customers, and policymakers in the Upper Midwest. The letter supported the future assumptions MISO identified for use in their 2021 MTEP LRTP initiative. MISO kicked-off this planning effort at the August 12, 2020 Planning Advisory Committee meeting.

Grid North Partners members both individually and collectively are engaged and participating in the MISO LRTP effort. In support of the MISO LRTP, Grid North Partners has commenced an informal technical study effort focused on more localized issues within the Grid North Partners footprint. All relevant potential options and findings have and will be supplied to MISO for potential inclusion in the LRTP.

Education and Stakeholder Engagement: The CapX2050 report identified that changing fleet will have wide ranging implications and it will require everyone from legislators, regulators, local governments, property owners, utilities, environmental groups and others working together to ensure our transmission system is prepared. To help facilitate a dialog, on June 12, 2021 Grid North Partners hosted a conference called ‘Finding True North.’9 The conference was attended by over 300 registrants and included panel discussions featuring different Upper Midwest expert perspectives on planning the grid for resiliency, operating our future system, policy and the next regional buildout, and a keynote on planning for 100% clean energy.
 
Institute of Electrical and Electronics Engineers (IEEE)
While not specifically requested by Commission another important aspect is various entity’s work on IEEE 1547-2018, which is a recently published distributed energy resources (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 with Xcel Energy’s business practice decisions.

In terms of specifying DER response to abnormal grid conditions, IEEE 1547 indicates that 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 that 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 how local grid support functions are 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 has released several collaborative reports for phase 1 in July of 2021. Xcel Energy has 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/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 Process to ensure that our needs are being addressed and that 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 Process that Minnesota TOs are involved in.

MISO Planning Advisory Committee (PAC): The Planning Advisory Committee 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 Planning Subcommittee (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.

MISO Planning Subcommittee (misoenergy.org)

MISO Subregional Planning Meeting (SPM): In accordance with FERC Order 890 Attachment K, the MISO will host a series of subregional planning meetings (SPM) 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 that are potentially driving new transmission expansion on the grid.

Subregional Planning Meeting (misoenergy.org)

MISO Regional Expansion Criteria and Benefits Working Group (RECB): The Regional Expansion Criteria and Benefits Working Group (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 one RTO as it relates to benefits and who pays is causing some tension across MISO stakeholders.

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

MISO Interconnection Process Working Group (IPWG): The purpose of the Interconnection Process Working Group (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.

MISO is looking to streamline the process to help with timelines for Interconnection Customers.  Some TOs feel that this will put pressure on them with an already tight timeframe and MISO should just stick with the timelines already in the tariff.

MISO Interconnection Process Working Group (misoenergy.org)

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

A recent issue brought up 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 feel reconfiguring the transmission system to accommodate outages is a good option. TOs feel that these types of requests and studies do not adequately address reliability concerns.

MISO Transmission Owners Compliance Task Team (TOCTT):  This is a closed group that deals with the compliance efforts at MISO relating the FERC and NERC.



2. For example, In the Matter of Updating the Generic Standards for the Interconnection and Operation of Distributed Generation Facilities Established under Minn. Stat. §216B.1611, Dockets No. E999/CI-16-521 and E999/CI-01-1023;  In the Matter of a Commission Inquiry into the Creation of a Subcommittee under Minn. Stat. §216A.03, subd. 8, Docket No. E999/CI-17-284; In the Matter of Xcel Energy's Tariff Revisions Updating Interconnection Standards for Distributed Generation Facilities Established under Minn. Stat. §216B.1611, Docket No. E002/M-18-714; In the Matter of Xcel Energy's Petition for Tariff Modifications Implementing Rules on Cogeneration and Small Power Production, Docket No. E002/M-16-222; In the Matter of Possible Amendments to Rules Governing Cogeneration and Small Power Production, Minnesota Rules, Chapter 7835, Docket No. E999/R-13-729; In the Matter of a Commission Inquiry into Fees Charged to Qualifying Facilities, Docket No. E999/CI-15-755; In the Matter of a Commission Inquiry into Standby Service Tariffs, Docket No. E999/CI-15-115; In the Matter of Establishing a Distributed Solar Value Methodology under Minn. Stat. §216B.164, subd. 10(e) and (f), Docket No. E999/M-14-65; In the Matter of the Commission Investigation on Grid Modernization, Docket No. E999/CI-15-556. 

3. For example, In the Matter of Xcel's 2017 Biennial Distribution Grid Modernization Report, Docket No. E002/M-17-776; In the Matter of Xcel Energy's 2018 Integrated Distribution Plan, Docket No. E002/CI-18-251; In the Matter of Xcel's 2017 Hosting Capacity Study, Docket No. E002/M-17-777; In the Matter of Xcel's 2018 Hosting Capacity Study, Docket No. E002/M-18-684; In the Matter of Distribution System Planning for Dakota Electric Association, Docket No. E111/CI-18-255; In the Matter of Distribution System Planning for Minnesota Power, Docket No. E015/CI-18-254, In the Matter of Distribution System Planning for Otter Tail Power, Docket No. E017/CI-18-253.

4. For example, In the Matter of the Petition of Northern States Power Company, dba Xcel Energy, for Approval of its Proposed Community Solar Garden Program, Docket No. E002/M-13-867; In the Matter of the Appeal of an Independent Engineer Review Pertaining to the SunShare Linden Project (Community Solar Gardens Program), Docket No. E002/M-19-29; In the Matter of a Formal Complaint Against Xcel Energy by Sunshare, LLC, Docket No. E002/CI-19-203; In the Matter of the Petition of Northern States Power Company d/b/a Xcel Energy for Approval of Competitive Resource Acquisition Proposal and Certificate of Need, Docket No. E002/CN-12-1240.

5. For example, In the Matter of Annual Cogeneration and Small Power Production Filings, Docket No. E999/PR-19-9; Distributed Generation Interconnection Report, Docket No. E999/PR-19-10. 

6 Excerpt from 2018 IDP regarding key aspects of MISO’s compliance filing: “One of the key aspects of MISO’s compliance filing will be the relationship between MISO, the DER, and the applicable distribution system operator (DSO).  After reviewing MISO’s draft agreement with the DER, we have tentatively concluded that it may be appropriate to file a tariff at FERC that would address aspects of DER participation in wholesale markets.  If the Company were to go forward with this concept, the tariff would address matters such as direct assignment of distribution system upgrade costs incurred due to DER participation in wholesale markets, the need for a DER to establish to the satisfaction of the utility that it has metering capability needed to ensure that it does not charge a storage resource at wholesale rates for retail usage, mechanisms to limit DER output to the extent that reliability of the distribution system is compromised by the DER’s activities, and cost recovery for services provided by the distribution system operator to the DER.” 

7 Grid North Partners member utilities include: Central Municipal Power Agency/Services, Dairyland Power Cooperative, Great River Energy, Minnesota Power, Missouri River Energy Services, Otter Tail Power Company, Rochester Public Utilities, Southern Minnesota Municipal Power Agency, WPPI Energy, and Xcel Energy

8 https://gridnorthpartners.com/wp-content/uploads/2021/02/CapX2050_TransmissionVisionReport_FINAL.pdf

9 A full recording of the conference is available at: https://gridnorthpartners.com/conference/