Source: http://minnelectrans.com/documents/2019_Biennial_Report/html/Ch_2_Biennial_Report_Requirements.htm
Timestamp: 2019-12-14 00:41:54
Document Index: 197794155

Matched Legal Cases: ['§ 216', '§ 216', '§ 216', 'art 7848', '§ 216', '§ 216', '§ 216', '§ 216', 'art 7848', '§ 216', '§ 216', '§ 216', '§216', '§216', '§216', '§216']

Studies and Reports > 2019 Biennial Report > Biennial Report Requirements
Chapter 2: Biennial Report Requirements
2.0 Biennial Report Requirements
This is the tenth 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 2019 Report will also be posted on that webpage.
MPUC Docket Number
MPUC Order
E999/M-19-205
E999/M-17-377
E999/M-15-439
Errata June 7, 2016
E999/M-13-402
E999/M-11-445
E999/M-09-602
E999/M-07-1028
E999/TL-05-1739
E999/TL-03-1752
E999/TL-01-961
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 publically 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 four biennial reports – 2011, 2013, 2015 and 2017 – the Commission has allowed the utilities to reference the latest MTEP Report to provide information about the identified inadequacies in Minnesota. The 2019 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 2019, 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 June 12, 2018, Order accepting the 2017 Biennial Report, the Commission said that the MTO shall "shall include content similar to 2017 Report, and include an improved and expanded assessment of non-wire alternatives and a discussion of relevant actions by FERC, MISO, and the Commission related to distributed energy resources and distribution planning." Consequently, the 2019 Report closely tracks the 2017 Report but also includes discussions on non-wire alternatives and relevant actions by other agencies related to distributed energy resources and distribution planning.
Waiver Request for 2021 Report
The MTO requests that the Commission extend the rule variances granted in the June 12, 2018 Order accepting the 2017 Biennial Report (and previous orders) for the 2021 Biennial Report as well, such that the future report requirements will mirror the content, notice and participation requirements of this 2019 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. R. 7848.0900 and related to outreach in Minn. R. 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.
Additionally, given changes in technology and web accessibility, the MTO proposes that this will be the last year electronic copies of the report will be served by CD. In future years, 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:
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 31, 2019, the MTO filed a letter to the Commission in the instant docket that there would be no certification requests included with the 2019 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 95 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 new reporting requirement is often referred to as the Grid Modernization Report. The PUC in May 2015 opened a separate docket for consideration of efforts related to modernization of the transmission and distribution grid. Docket Number E999/CI-15-556.
Further, subdivision 8, which was also added in 2015, provides:
On October 30, 2015, Xcel Energy filed its 2015 Biennial Distribution-Grid Modernization Report under Minn. Stat. § 216B.2425. The MPUC assigned a separate docket number to the Report. Docket Number E002/M-15-962. On June 28, 2016, in that docket, the MPUC accepted the Grid Modernization part of the Report and directed Xcel Energy to file a separate Distribution System Study by December 1, 2016, which Xcel Energy did.
As mentioned above, 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. Accordingly, Xcel Energy has submitted its Grid Modernization Report and its Hosting Capacity/Distribution Study Report under separate cover for MPUC consideration in two separate dockets.
2.7 Non-Wire Alternatives
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 95 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.
Type of Trans-mission Project
Wind/Storage
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.
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.
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.
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 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.
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
FERC Order No. 841, which was issued in February 2018, amended FERC regulations to remove barriers to the participation of electric storage resources in the capacity, energy, and ancillary service markets operates by regional transmission organizations and independent system operators by requiring RTOs and ISOs to revise its tariff to recognize the physical and operational characteristics of electric storage resources and facilitate their participation in markets. FERC has received requests to consider similar rules for DERs. In May 2018, FERC held a two day technical conference on DERs. There are two ongoing FERC dockets related to DERs. The first is Docket No. RM18-9, which relates to the Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators, and is a continuation of the rulemaking FERC originally commenced in Docket No. RM16-23. The second is Docket No. AD18-10, which relates to Distributed Energy Resources – Technical Considerations for the Bulk Power System.
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.
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.
1. www.nrri.org
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.