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Studies and Reports > 2011 MN Biennial Report > Transmission Studies


Transmission Projects Report 2011
Chapter 3: Transmission Studies
 
pp. 8-28

3.0       Transmission Studies
3.1        Introduction

The Public Utilities Commission requires that the utilities include in each Biennial Report a “list of studies that have been completed, are in progress, or are planned that are relevant to each of the inadequacies identified” in the Report.  Minnesota Rules part 7848.1300, item F.  In the 2005 Biennial Report, the utilities not only identified completed, ongoing, and planned studies but also described in general terms the transmission planning process.  In the 2007 Report, the utilities again described the relevant studies and in addition, pursuant to legislative directive, described planning processes and studies related to compliance with Renewable Energy Standards. 

In this 2011 Biennial Report, the utilities follow the approach utilized in the 2009 Biennial Report to first identify in Section 3.2 a number of studies that have been completed that either address expansion of the transmission network to address generation expansion, in particular renewable energy, or address local inadequacy issues (noted with a Tracking Number). Section 3.3 describes ongoing regional studies that focus on expansion of the bulk electric system to address broad regional reliability issues and support expansion of renewable in the upper Midwest. Section 3.4 focuses on ongoing load serving studies that are attempting to resolve local inadequacy issues. Section 3.6 is a new section describing certain studies at the national level that are underway.

3.2        Completed Studies

The following studies have been completed and where specific transmission projects have been identified, a Tracking Number is provided. The Tracking Number identifies the year the project was first considered for inclusion in a Biennial Report and the zone where the project is located. 


Study Title
Year Completed
Utility Lead
Description
LaCrosse to Madison 345 kV Transmission Line 2010 ATC Preliminary studies are complete for the 345 kV, $425 million Badger-Coulee line (also referred to as the La Crosse-Madison line), which would address electric system reliability issues in Wisconsin and Minnesota, provide economic savings and support renewable energy policy. The project was submitted to the MISO Transmission Expansion Plan in 2011 and is referred to as project #3127 in MTEP. The line also has been identified by MISO as a Candidate MVP (Multi-Value Project) and is expected to be presented to the MISO Board for approval in December. Project information and economic analysis information is available at www.badgercoulee.com.
Regional Outlet Generation Study (RGOS) 2010 MISO Renewable Portfolio Standards (RPS), passed by most MISO member states, mandate that increasing amounts of statewide electrical energy come from renewable energy sources. MISO recognized that implementing RPSs would require regionally compliant transmission portfolios. The Regional Generator Outlet Study (RGOS) objectives included 1) analyzing and planning for each state’s renewable portfolio standards, 2) setting goals for meeting load-serving entities’ renewable portfolio standards, 3) balancing distribution of wind zones to consider local desires, optimal wind conditions and distances from load, 4) providing consumers with energy solutions at the least-possible cost, 5) identifying transmission expansion starter projects.  Details can be found at misoenergy.org. Click on “Planning” then on “Study Repository”.
SMARTransmission Study 2010 Electric Transmission America, LLC The Strategic Midwest Area Renewable Transmission Study, or SMARTransmission Study, was a comprehensive study of the transmission needed in the Upper Midwest to support renewable energy development and to transport that energy to consumers. SMARTransmission was sponsored by Electric Transmission America – a transmission joint venture of subsidiaries of American Electric Power and MidAmerican Energy Holdings Company – American Transmission Company, Exelon Corporation, NorthWestern Energy, MidAmerican Energy Company – a subsidiary of MidAmerican Energy Holdings Company – and Xcel Energy. The sponsors retained Quanta Technology LLC to evaluate extra-high voltage transmission alternatives and provide recommendations for new transmission development in the Upper Midwest, including North Dakota, South Dakota, Iowa, Indiana, Ohio, Illinois, Minnesota and Wisconsin. Quanta conducted an analysis of transmission alternatives, and analyzed the impact and quantified the economic benefits of several transmission options. More information about the study is located at www.smartstudy.biz
Minnesota Transmission Assessment and Compliance Team 2010 Transmission Assessment (2010 – 2020) 2010 MTO This report is an annual transmission assessment investigating near-term, mid-term, and long-term transmission conditions.  This purpose of this study is to develop an understanding of the transmission system topology, behavior, and operations to determine if existing and planned facility improvements meet the North American Electric Reliability Corporation (NERC) Transmission Planning Standards TPL-001 through TPL-004.
Enbridge Transmission Study 2010 OTP This study investigated the capability of the existing transmission system to serve increased load projections for the various Enbridge Pump Stations located in Northwest Minnesota (see 2003-NW-N2 and 2007-NW-N3 for more details).
Fergus Falls Area Transmission Study 2010 OTP The analysis performed for this study focused on the challenges with serving the Fergus Falls area load from Audubon and the resultant voltage and loading concerns on the system.  The results of the study had indicated that the energization of the new Fergus Falls SE 115/12.5 kV substation transferred enough load from the Edgetown 115/12.5 kV substation to sufficiently resolve the transmission issues in the near-term timeframe (see 2009-NW-N1 for more details).
Gwinner Capacitor Bank Study 2010 OTP Voltage concerns near Gwinner during outage of the Forman – Gwinner 115 kV line prompted the need for additional voltage support in the Gwinner area.  A short study was completed to recommend the appropriate capacitor bank size and configuration to support voltages in this area when being served from Buffalo.
Browns Valley Area Study 2010 OTP The 41.6 kV system between Hankinson, Browns Valley, and Summit has been shown to have N-1 contingency concerns during winter peak conditions.  This study investigated different transmission alternatives to support this area.  The recommendations from this study involve adding a new 115 kV source into the 41.6 kV system in this area.
Cass Lake Capacitor Bank Study 2010 OTP Near-Term studies of the Bemidji area had identified voltage concerns at Cass Lake for an outage of the Bemidji – Helga 115 kV line or the Helga – Nary 115 kV line.  OTP completed a study to determine the appropriate capacitor bank size and configuration to support voltages in the area when being served from Badoura (prior to the Bemidji – Grand Rapids 230 kV line being energized). More details can be found under tracking number 2007-NW-N2.
Cromwell-Wrenshall-Mahtowa-Floodwood Area 2010 MP/GRE Area load-serving need for tracking #2003-NE-N2, MTEP Project ID 2634
Duluth Area 230 kV & 15 Line Upgrade 2010 MP Duluth Area Transmission Reliability Study tracking #2007-NE-N1 & 2011-NE-N2, MTEP Project ID 2548 & 2549
9 Line Upgrade 2011 MP 9 Line capacity requirements & upgrade requirements, tracking # 2011-NE-N1, MTEP 3373
25L Tap 2011 MP Transmission to serve Mining Resources LCC Tracking # 2011-NE-N7, MTEP 3532
Transmission Service Related Upgrades 2011 MPC MPC performed a delivery study to grant transmission service to a number of requests in the MPC OASIS delivery queue.  The study identified the need for a number of network upgrades.  Details of the results are reported in “Minnkota Power Cooperative Generation Study Report for Service to Native Load”.  Facilities identified for upgrade include the Richer – Roseau – Moranville 230 kV line and the Winger 230/115 kV transformer.  The Winger transformer had been previously identified for upgrade to address load serving issues.
Buffalo – Casselton 115 kV Project Study 2011 OTP The transmission system between Buffalo, Fargo, and Wahpeton has been shown to have emerging issues due to N-1 contingencies.  This study investigated these concerns and tested various transmission alternatives to meet acceptable loading and voltage concerns.  The recommendation of this study is to construct a new 115 kV line from Buffalo to Casselton to address the load serving concerns in this area.
Interconnection Study for Bemidji – Grand Rapids 230 kV Line 2011 MPC Transmission system studies have identified the Bemidji area as being increasingly susceptible to post-contingent voltage collapse conditions. These studies identified the Bemidji to Grand Rapids 230 kV line (i.e. Wilton – Boswell) as the best alternative to address the system inadequacies in the Bemidji area and the northern Red River Valley.  As part of the project, the new line will be tapped at Cass Lake to address voltage issues and growing demand on the 115 kV loop from Wilton to Badoura.  Other mitigations were also identified in studies evaluating performance of the Wilton – Cass Lake – Boswell 230 kV line (see list below).  The “Bemidji – Grand Rapids 230 kV Line System Impact Study” was completed in 2011 as part of the MAPP approval process.  The Bemidji – Grand Rapids project is being constructed by MPC and the CapX2020 group. Project completion is expected to be in late 2012. The project includes:
  • Boswell – Cass Lake 230 kV line
  • Cass Lake – Wilton 230 kV line
  • Cass Lake 230/115 kV transformer
  • New breakered 115 kV substation at Nary
  • Bemidji – Helga – Nary 115 kV line uprate
  • Nary – Cass Lake 115 kV line uprate
  • Temporary operating guide to protect Nary – Laporte 115 kV line prior to other planned transmission improvements
The Bemidji – Grand Rapids project is also listed in MTEP Appendix A under projects 279 and 3156.  
Minnesota Transmission Assessment and Compliance Team 2011 Transmission Assessment (2011 – 2021) 2011 MTO This report is an annual transmission assessment investigating near-term, mid-term, and long-term transmission conditions.  This purpose of this study is to develop an understanding of the transmission system topology, behavior, and operations to determine if existing and planned facility improvements meet NERC Transmission Planning Standards TPL-001 through TPL-004.
Ramsey Transformer Study 2011 OTP This study investigated the long-term load serving needs of the Devils Lake area.  Specifically, the analysis focused on the appropriate transformer capacity for the Ramsey 230/115 kV substation, which had originally been identified as an overload in the Langdon Wind Interconnection Study (see 2003-NW-N2 for additional information).
Otter Tail Power Company / Central Power Electric Cooperative Long Range Transmission Study 2011 OTP OTP has worked extensively with Central Power Electric Cooperative (CPEC) to develop detailed models of the joint 41.6 kV system for current year, 10-year, and 20-year winter peak timeframes.  A detailed review of the joint OTP/CPEC 41.6 kV system has identified some transmission projects needed for the upcoming 10 year time horizon that will be coordinated between OTP and CPEC.
Oakes – Forman 230 kV Line Rebuild 2011 OTP A short study was completed by OTP to determine the most optimal conductor to use for rebuilding approximately 7 miles of 230 kV line between Oakes (ND) and Forman (ND) that was damaged due to storms during the summer of 2011.

3.3        Regional Studies

While every study that is undertaken adds to the knowledge of the transmission engineers and helps to determine what transmission will be required to address long-term reliability and to transport renewable energy from various parts of the state to the customers, some studies are intentionally designed to take a broader look at overall transmission needs.  Regional studies analyze the limitation of the regional transmission system and develop transmission alternatives that support multiple generation interconnect requests, regional load growth, and the elimination of transmission constraints that adversely affect utilities’ ability to deliver energy to the market in a cost effective manner.  Many of these studies are especially important for focusing on transmission needs for complying with upcoming Renewable Energy Standards.

3.3.1 MISO Transmission Expansion Plans

The Midwest Independent Transmission System Operator (MISO) engages in annual regional transmission planning and documents the results of its planning activities in the MISO Transmission Expansion Plan (MTEP).  The MTEP process is explained in detail in chapter 6 since the latest MTEP reports are being relied on to provide information about the transmission inadequacies identified in this Report.  For convenience, the following brief description of the latest MTEP reports is presented.

MTEP09 Report

The 2009 MISO Transmission Expansion Plan was approved by the MISO Board of Directors on December 3, 2009.  The subtitle of the report is “Energizing the Heartland.” The MTEP09 Report identifies those projects required to maintain reliability for the ten year period through the year 2019 and provides a preliminary evaluation of projects that may be required for economic benefit up to twenty years in the future. 

At the first page in the Executive Summary, MISO states that MTEP09 recommends 274 new projects totaling $903 million of investment in transmission.  The addition of these projects brings the total number of projects in Appendix A to 576 with total investment of $4.3 billion. Since the first MTEP cycle that closed in 2003, transmission investment totaling $7.2 billion has been approved, $2.7 billion of which is associated with projects already in-service.

MTEP10 Report

The 2010 MISO Transmission Expansion Plan was approved by the MISO Board of Directors on November 30, 2010.  The subtitle of the report continues from 2009 – “Energizing the Heartland.” At page 1 of the Executive Summary, the Report states:

MTEP 10 recommends $1.22 billion in new transmission expansion through the year 2020 for inclusion in Appendix A. This is part of a continuing effort to ensure a reliable and efficient electric grid that keeps pace with energy demands.

The MTEP10 Report identifies those projects required to maintain reliability for the ten year period through the year 2020 and recommends 231 new projects for inclusion in Appendix A.

MTEP11 Report

The 2011 MISO Transmission Expansion Plan is still being finalized.  The following language from pages 3-4 of the Executive Summary in the draft MTEP11 Report explains the purpose of this planning activity.

MTEP11, the eighth edition of this publication, is the culmination of more than 18 months of collaboration between MISO planning staff and stakeholders. The primary purpose of this and other MTEP iterations is to identify transmission projects that:

  • Ensure the reliability of the transmission system over the planning horizon.

  • Provide economic benefits, such as increased market efficiency.

  • Facilitate public policy objectives, such as meeting Renewable Portfolio Standards.

  • Address other issues or goals identified through the stakeholder proces

MTEP11 recommends $6.5 billion in new transmission expansion through the year 2021 for inclusion in Appendix A and construction. This is part of a continuing effort to ensure a reliable and efficient electric grid that keeps pace with energy and policy demands. Key findings and activities from the MTEP11 cycle include: 

    • Recommendation of the first Multi Value Project portfolio for approval by the MISO Board of Directors.

    • Recommendation of 198 new Baseline Reliability, Generation Interconnection, or Other projects totaling $1.4 billion for approval by the MISO board of directors.

    • Economic assessment of transmission expansion.

    • Confirmation of Long-Term Generation Resource Adequacy.

    • Determination of the potential impacts of EPA regulations on generation retirements.

    • Full implementation of a regional transmission planning approach.

The MTEP11 Report should be finalized for approval by the MISO board of directors before the end of 2011.  The MISO Expansion Plans are available on the MISO webpage. Visit http://www.misoenergy.org and click on “Planning.”

3.3.2 Manitoba Hydro-Electric Board Transmission Service Request

MISO continues to process generation interconnection requests and transmission service requests on the transmission system that they operate.  These studies could result in the need for new transmission in Minnesota. It is difficult to predict which projects, if any, will actually move forward, as the decision to move forward on a transmission project that is related to generation interconnection and transmission service is up to the generation developer and Power Purchase Agreement (PPA) recipient. There are a series of transmission service requests that involve the possible construction of transmission in Minnesota. 

One group of these transmission service requests involves an increase in the ability to transfer power from Manitoba into the United States by 1100 MW. Several transmission options with variations have been identified for accommodating this series of transmission service requests. One option involved a 500 kV line between Winnipeg and the Twin Cities via Northeast Minnesota, the second option involved a 500 kV line between Winnipeg and the Twin Cities via the Red River Valley (Fargo) and another option consisted of a 500 kV line between Winnipeg and Fargo and potentially extending as far south as Sioux Falls, SD, with possible termination points at select 345 kV substations in between. A second transmission service request involves a 250 MW PPA between Manitoba Hydro and Minnesota Power. A 230 kV transmission line from the Winnipeg area to the Iron Range area of Minnesota is being studied as one possible way to enable this PPA (MTEP Project ID# 3562). The MTO utilities continue to actively participate in MISO studies evaluating transmission options to accommodate these transmission service requests.

3.3.3 Manitoba Hydro Wind Synergy Study

At the prompting of Manitoba Hydro (MH) and the potential customers (including GRE) of output from their new hydro dams, MISO is undertaking a market study to determine the value of increasing hydro storage in combination with MISO wind generation.  MISO will be using a new study tool to analyze these Ancillary Services benefits.  MH has over 2000 MW of new hydro generation development possible between 2012 and 2023+, in addition to about 5000 MW on their system now.  This synergy study will be under full MISO stakeholder review, with scoping occurring this fall. The analysis is planned to be completed next year and the final report will be published in the fall of 2014.

3.3.4  Multi-Value Project Portfolio

In July 2010, MISO submitted tariff revisions to the Federal Energy Regulatory Commission (FERC) to establish a new category of transmission projects. The new Multi-Value Project (MVP) tariff provisions provide broad cost allocation for a portfolio of projects that meet at least one of the following three criteria:

1.     Enable the transmission system to deliver energy in support of public policy requirements (such as Renewable Energy Standards)

2.     Provide reliability and economic benefits in excess of project costs

3.     Address transmission issues associated with projected NERC violations and at least one economic–based transmission issue that provides economic benefits in excess of project costs across multiple pricing zones

FERC approved the MISO MVP tariff (and related tariff provisions related to generation interconnection costs) in December 2010, and FERC denied all requests for rehearing in October 2011.  FERC Docket No. ER10-1791-000 Order Conditionally Accepting Tariff Revision (Dec. 16, 2010).

MISO is currently considering 17 projects in the Upper Midwest for MVP certification, including the CapX2020 Brookings County-Hampton line. Other Upper Midwestern lines include proposed projects in Iowa, North Dakota, South Dakota and Wisconsin.

Brookings County-Hampton (CapX2020 project) received conditional MVP approval in June 2011; all 17 candidate MVP projects will be considered by the MISO board of directors for approval as a portfolio in December 2011.

MISO has completed a business analysis that demonstrates all MISO members will benefit from construction of the MVP projects in excess of project costs. The benefits range from 1.8 to 5.8 times the total cost of all projects. In other words, for every dollar spent on construction, MISO members will receive benefits between $1.80 and $5.80.

Overall, the proposed MVP portfolio enables the delivery of 41 million megawatt hours of renewable energy annually.

MISO analysis also identifies significant reliability benefits that will be realized from the MVP projects by strengthening the overall transmission system. The candidate MVP portfolio resolves approximately 500 thermal overloads for approximately 6,400 system conditions, and resolves 150 voltage violations for approximately 300 system conditions.

The map on the following page shows the 17 MVP projects.

3.4        Load Serving Studies

Load serving studies focus on addressing load serving needs in a particular area or community.  Since many of the inadequacies in Chapter 6 are load serving situations, many of these studies relate to specific Tracking Numbers. 

Study title
Anticipated completion
Utility lead for Study
Description
Otter Tail Power/Minnkota Power Cooperative Long Range Transmission Study 2012 OTP Otter Tail Power Company (OTP) has worked with Minnkota Power Cooperative (MPC) to perform a detailed transmission planning study of the joint 41.6 kV and 69 kV system for current year, 10-year, and 20-year winter peak timeframes.  Transmission planning studies are currently underway to determine which areas of the joint system have challenges in meeting loading and voltage criteria.  Deficiencies and future projects to address these deficiencies are expected to be identified during 2012.
Otter Tail Power/Great River Energy Long Range Transmission Study 2012 OTP Similar to the OTP/MPC Long Range Transmission Study, OTP is working with Great River Energy (GRE) to perform a detailed transmission planning study of the joint 41.6 kV system for current year, 10-year, and 20-year winter peak and summer peak timeframes.  Transmission planning studies are currently underway to determine which areas of the joint system have challenges in meeting loading and voltage criteria.  Deficiencies and future projects to address these deficiencies are expected to be identified during 2012.
Otter Tail Power High Voltage Transmission Study 2012 OTP As a result of the transmission assessments completed by the MN TACT for NERC TPL compliance, OTP has initiated a high voltage transmission study to investigate reliability concerns that have been identified in the mid- to out-year timeframes.  The study work is planning to be coordinated with neighboring utilities and is expected to identify deficiencies and proposed mitigations to solve these deficiencies during 2012.
Deer River Area Reliability 2012 MP Load serving study of Deer River area 2009-NE-N2, MTEP 3531 and 2551
Wrenshall area 2012 MP MP 23L upgrade alternatives 2011-NE-N12, MTEP 3756
Keewatin Area 2012 MP Keewatin area load serving needs
Austin Area Load Serving Study 2013 SMP An Austin Area Transmission Study was conducted to investigate different alternatives for increasing load serving capability in the Austin area. The study identified two alternatives as the best options for increasing load serving capability and for satisfying reliability requirements. The preferred option is the construction of a new 161/69 kV substation in northwest Austin, MN. Tracking Number 2011-SE-N5
Xcel Energy 10-Year Plan Load Serving Study 2010, updated annually NSP NSP completes an annual load serving study for the Minnesota, North and South Dakota and Wisconsin territories. A slide presentation summarizing the most recent study and results is at the following link: http://www.xcelenergy.com/staticfiles/xe/Cor
porate/Corporate%20PDFs/NSP%202010%
20transmission%20plan%20-FINAL.pdf
Audubon Area Load Serving Study 2012 MRES This study is evaluating the need for more voltage/reactive support in the Audubon/Detroit Lakes area. Further work will be completed to more accurately determine timing and scope of upgrades. The preliminary conclusion is that capacitor bank(s) need to be installed in the Detroit Lakes area within the next 5-6 years.
3.5        MAPP Load & Capability Report

Since the 2009 Biennial Report, the Mid-Continent Area Power Pool (MAPP) has stopped supporting the MAPP Load & Capability Report. The most recent Load & Capability Report is dated May 1, 2009. The following introduction to the 2009 Load & Capability Report provides an overview of what the report was intended to do:

The MAPP Load and Capability Report is prepared in response to the requirement set forth in the MAPP Agreement and the MAPP Generation Reserve Sharing Pool Handbook for a two-year monthly and a ten-year seasonal load and capability forecast from each MAPP Participant.  The report contains actual and forecast monthly load and capability data for the period of May 2008 through December 2011 and seasonal load and capability data for the ten-year period Summer 2009 through Winter 2018-19.

3.6        Other Studies
3.6.1 Eastern Interconnection Planning Collaborative

In June of 2009, the United States Department of Energy (DOE) issued a Funding Opportunity Announcement (FOA), DE-FOA0000068, alerting the public that the DOE was prepared to provide funding for analysis of transmission requirements under a broad range of alternative futures.  The DOE FOA covered two specific topics.  Topic A was to fund Interconnection-level analysis and planning work while Topic B was to fund cooperation among States on electric resource planning and priorities.  The DOE anticipated issuing three awards under each Topic corresponding to the three geographic areas served by the three interconnections (Eastern, Western, and Texas).

In August of 2009, the Planning Authorities in the Eastern Interconnection reached final agreement on the formation of the Eastern Interconnection Planning Collaborative (EIPC).  Under the construct of the collaborative, these Planning Authorities in the Eastern Interconnection intended to “roll-up” their respective regional expansion plans, which were developed under FERC Order 890 approved regional planning processes, to form a model of the Eastern Interconnection.  This model would provide a basis for interconnection-wide analysis that would feed information back into regional planning processes and allow EIPC members to identify any inconsistencies among the established regional plans while also allowing members to identify opportunities for potential transmission enhancements to increase the ability to move power or reduce costs.  The core objectives served as the foundation for a proposal that EIPC submitted in August 2009 to perform the Topic A work under the DOE FOA.  All twenty-six (26) EIPC members support the work prescribed for Topic A.  Eight (8) of the twenty-six members are designated as Principal Investigators who bear additional responsibilities under the DOE FOA with respect to project management and reporting.  PJM serves as the lead Principal Investigator under the proposal. PJM is a regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 eastern states and the District of Columbia, comparable to what MISO does in the Midwest.

The 39 states (plus the District of Columbia and the City of New Orleans) in the Eastern Interconnection, including Minnesota, formed the Eastern Interconnection States Planning Council (EISPC) and, at the same time that EIPC was crafting its proposal, submitted a proposal for the Topic B work under the DOE FOA.  On December 18, 2009; the DOE announced that EIPC and EISPC had been selected to perform the Eastern Interconnection work under Topic A and Topic B, respectively, with a total of $16 million in funds made available to EIPC and a total of $14 million in funds made available to EISPC.  As part of its proposal, EIPC had retained Whiteley BPS Planning Ventures LLC to support project management, The Keystone Center (Keystone) to support stakeholder process facilitation, and Charles River Associates (CRA) to support macroeconomic analysis and production cost studies.

The EIPC proposal incorporated a Statement Of Project Objectives (SOPO) as required under the terms of the DOE FOA.  The SOPO was originally submitted as part of the proposal in August 2009 and was then revised during contract negotiations with the DOE in February 2010. 

The first objective was to establish processes for aggregating the modeling and regional transmission expansion plans of the entire Eastern Interconnection and to perform interregional analyses to identify potential conflicts and opportunities between regions.  This interconnection-wide analysis was to serve as a reference case for modeling various alternative grid expansions based on the scenarios developed by stakeholders.

The second objective was to perform scenario analysis as guided by a broad stakeholder input and the consensus recommendations of a stakeholder committee formed under the proposal.  The analysis would serve to aid federal, state and provincial regulators as well as other policy makers and stakeholders in assessing interregional options and policy decisions.

The scope of work proposed by the EIPC in the SOPO was divided into 13 tasks with two distinct parts or phases.  Phase 1 included the following tasks:

  • Task 1 – Initiate Project (January – October 2010)
    • EIPC to meet with Topic B Awardee (EISPC) to discuss approach for interaction between entities and to gather feedback on Stakeholder Steering Committee (SSC) structure.
    • The Keystone Center to facilitate the formation of the SSC and any necessary subgroups.
  • Task 2 – Integrate Regional Plans (January – December 2010)
    • EIPC to generate Roll-up Model using regional plans for year 2020.
    • EIPC to perform inter-regional analysis on Roll-up Model.
    • EIPC to indentify conflicts between plans and/or opportunities for regional plan improvement.
  • Task 3 – Production Cost Analysis of Regional Plans (Task was eliminated after original scope of work was developed)
    • CRA to perform production cost analysis on Roll-up Model.
  • Task 4 – Macroeconomic Futures Definition (January – May 2011)
    • SSC to reach consensus on eight Futures (each Future having up to nine Sensitivities totaling 80 cases).
  • Task 5 – Macroeconomic Analysis (March – September 2011)
    • CRA to perform macroeconomic analysis and report on each Future and Sensitivity.
    • EIPC to produce high level transmission cost estimates for each of the 8 Futures scenarios.
  • Task 6a – Expansion Scenario Concurrence (September – November 2011)
    • EIPC to assist SSC in selecting three scenarios from the Task 5 work as options for the transmission expansion, analysis, and costing work in Phase 2 of the project.
  • Task 6b – Interim Report (July – December 2011)
    • EIPC to produce interim project report on Phase 1 activities.

Phase 2 of the project proposed building and analyzing transmission expansion options for the three scenarios selected by the Stakeholder Steering Committee in Task 6a at the end of Phase 1.  For each of the three scenarios selected, the work in this phase proposed the following tasks with the following timeframes:

  • Task 7 – Interregional Transmission Options Development (January – June 2012)
    • EIPC to modify power flow models built in Task 2 to create interregional transmission expansion models for each scenario.
  • Task 8 – Reliability Review (June – August 2012)
    • EIPC to perform reliability analysis consistent with NERC reliability criteria on each scenario.
  • Task 9 – Production Cost Analysis of Interregional Expansion Options (July – September 2012)
    • CRA to perform economic analysis using production cost modeling for each scenario.
  • Task 10 – Generation and Transmission Cost Estimates (July – October 2012)
    • EIPC to perform high level cost estimates for transmission expansion options for each scenario.
    • Costs associated with resource additions and retirements will be developed by CRA for each scenario.
  • Task 11 – Review of Results (August – November 2012)
    • EIPC to produce a draft report on the Phase 2 effort.
    • EIPC to present the results of the analysis, respond to questions, and solicit input from stakeholders.
    • SSC to provide consensus-based comments on the draft report.
  • Task 12 – Phase 2 Report (September – December 2012)
    • EIPC, with CRA providing technical support, to review the input received from the SSC and address it in the final report.

A Phase I report will be filed with the Department Of Energy in December of 2011.  Phase II work is expected to be completed by the end of 2012, at which time a Phase II report will also be filed with the Department Of Energy.
MTO utilities participate directly in the EIPC effort representing our customer’s interests, and MISO participates as a Planning Authority, on behalf of utilities in the MISO area.

             http://www.eipconline.com

3.6.2 NERC Facility Ratings Alert

The North American Electric Reliability Corporation (NERC) is requiring Transmission Owners and Generator Owners of bulk electric system facilities across the country, including those joining in this Biennial Report, to review their current facility ratings methodology for their transmission lines. Each owner must verify that the methodology used is based on actual field conditions and determine if their ratings methodology will produce appropriate ratings when considering differences between design and field conditions. For additional information see:

             http://www.nerc.com/pa/rrm/bpsa/Pages/Facility-Ratings-Alert.aspx

By January 18, 2011, these Transmission Owners were required to submit to NERC their plans to complete such an assessment of all their transmission lines, with the highest priority lines to be assessed by December 31, 2011, medium priority lines by December 31, 2012, and the lowest priority by December 31, 2013. The MTO utilities will comply with the December 2011 deadline. For information on NERC line prioritization categories follow this link:

            http://www.nerc.com/docs/alerts/Assessment_Plan_Review_Criteria_20110511.pdf

At the conclusion of each year, each Transmission Owner and Generator Owner must report to its Regional Entity a summary of the assessments and identification of all transmission facilities where as-built conditions are different from design conditions (resulting in incorrect ratings) and their associated mitigation timelines. For the MTO utilities, the Regional Entity is the Midwest Reliability Organization (MRO).  Remediation is expected to be complete within one year from identification of an issue or on a schedule approved by the Regional Entity if longer than a year. Owners are also expected to coordinate with their respective Reliability Coordinator (RC) and Planning Authority (PA) to coordinate interim mitigation strategies. For MTO who are MISO members, the Midwest Independent Transmission System Operator serves as the RC and PA. For the MTO members who are not MISO members, the Mid-Continent Area Power Pool (MAPP) serves as the PA and Midwest Independent Transmission System Operator serves as the RC.

If discrepancies are found, various alternative methods could be used for remediation.  These could be as simple as de-rating the transmission line, upgrading its capacity by increasing clearance, reconductoring or rebuilding the line or construction of new transmission facilities to reduce loading on the identified transmission element. The alternative of choice will be dependent the outcome of an engineering analysis that will take into account future expected transmission needs and cost.

3.6.3 Eastern Renewable Generation Integration Study

The National Renewable Energy Laboratory (NREL) has kicked off an Eastern Renewable Generation Integration Study (ERGIS) which is a follow-up to two previous wind integration studies: the Joint Coordinated System Plan and the Eastern Wind Integration Transmission Study.  This study objective of ERGIS is to explore transmission grid planning and operations with significant amount of installed renewable generation in order to answer new questions/concerns such as regional and inter-regional impacts as well as mitigation.  The transmission options, developed in the earlier two studies, will be refined and used in this study assumption. New study tools will be used to better simulate real time system operations. Stakeholders have been invited to participate on a Technical Review Committee and the study is expected to be complete in the spring of 2013.

3.7        Strategic Planning

As part of the PUC’s consideration of the 2009 Biennial Report, it rejected the suggestion by the Department of Commerce staff that it provide greater direction to the MTO regarding how to set priorities for competing transmission projects.  Instead, in its May 28, 2010, Order approving the 2009 Report, the Commission directed the MTO to discuss the issue of strategic planning in the 2011 Biennial Report and to include a list of projects that the MTO believes warrant designation as priority projects. 

The MTO is unsure how to describe the concept of strategic planning.  Each utility, of course, must constantly be cognizant of demands on its system, to ensure that customers have a reliable source of power.  The utilities have in the last several Biennial Reports identified the load-serving studies that are underway or have been completed in the past reporting period.  Section 3.4 of this Report describes a number of load-serving studies that are underway.  Each utility must prioritize its efforts on these kinds of issues by determining how imminent the problem is and how severe the situation is.  Obviously, efforts will be devoted to problems that must be addressed in the near term.  Any of the load-serving projects with Tracking Numbers that need to be completed within a few years are higher priority than those with a longer timeframe.

While each utility must continue to be aware of these local issues, there are other factors outside the direct control of the utility that affect planning efforts.  The Renewable Energy Standards that the Minnesota Legislature has established, along with similar standards in many other states, affect the planning efforts of all utilities.  At the same time, since MISO is responsible for operating the transmission grid in Minnesota and surrounding states, much of the transmission planning that is undertaken is established by MISO and conducted under their control. 

Nationally, the Department of Energy and the Federal  Energy Regulatory Commission often take action that affects transmission planning, through the offering of funding and the establishment of cost allocation mechanisms.  The MTO has described some of these studies in this Report and mentioned in the 2009 Report that cost allocation was a significant issue that affected the scope of planning and the prioritizing of projects. 

Nor is it possible to develop a specific list of priority projects.  The 2009 Biennial Report in section 8.10 contains a list of transmission projects that the utilities identified as high priority projects for achieving the RES milestones, and several of these projects have been completed.  The MTO utilities have maintained for years that the CapX2020 projects are high priority for a lot of reasons, and these lines are included in that list. 

To assist the Commission in prioritizing transmission projects across the Midwest, the 17-projects included in the Multi-Value Project Portfolio study described in section 3.3.4 are as good a place to start as any.  These 17 projects can be considered as priority projects for the MISO region and Minnesota as they are deemed necessary for the MISO states to meet the year 2026 renewable standards in the most efficient manner.  This suite of projects are inter-related in that they allow for the reliable integration of approximately 9 GW of new renewable generation into the MISO market.  These projects are expected to constructed and in-service between 2015 and 2020. 

One of the CapX2020 projects (Brookings to the Twin Cities) is one of these projects.  While this CapX2020 project is the only MVP project entirely in Minnesota, two others are along the border and all of them are significant for achieving the renewable energy utilities across the Midwest needed to meet upcoming RES milestones. 

The most important and essential projects beyond the CMVPP have yet to be determined.  However, there are multiple study efforts in preliminary stages of development that could affect the region and the entire Eastern Interconnect.  These analyses will serve to provide a vision for the necessary transmission expansion in the 2020 timeframe and beyond.  Because these analyses have not been completed, or even begun in some cases, it is not possible with any certainty to identify the next transmission projects that warrant the greatest priority.  Further, project details such as endpoints, configurations, in-service dates and even voltages are unknown.  Additionally, given the much delayed need for additional wind generation for MN RES purposes, the locations for future wind farms are unknown and thus the associated transmission expansions are also unknown. 

The most certain information with regard to future generation sources is the sale of 250 MW of power by Manitoba Hydro to Minnesota Power beginning in 2020.  The transmission project(s) to support this transfer along with others may be determined in the MISO MH Wind Synergy Study or in the TSR examination by MISO. Once these studies are completed, the transmission projects and associated in-service dates will become more defined.  Once any project is identified, it will be beneficial to examine it with a wide stakeholder group and alongside any load serving issues in the region and other generation market needs in order to develop a coordinated and synergetic build out of the high voltage grid.