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Studies and Reports > 2013 MN Biennial Report > Transmission Studies


Transmission Projects Report 2013
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. Information about the transmission planning process and about previous studies that have been completed over the years can be found in earlier Biennial Reports, beginning with the 2005 Report.

In this 2013 Biennial Report, the utilities first identify in Section 3.2 a number of studies that have been completed since the 2011 Biennial Report was submitted in November 2011. These studies primarily 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 3.5 describes certain studies at the national level that are underway. Section 3.6 describes the MAPP Load & Capability Report, which PUC rules (part 7848.1300, item B) require, but which is no longer prepared.

3.2 Completed Studies

The following studies have been completed since November 2011. Previously completed studies are identified in earlier Biennial Reports and are not repeated here. In some cases studies have been commenced and completed between November 2011 and November 2013 and were not identified in the 2011 Biennial Report. 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

OTP High Voltage Study

2012

OTP

This study investigated the capability of the OTP high voltage transmission system for both near term and out year study assumptions. When limitations were identified, mitigation was recommended and tested to select the best fit plan. MPC helped perform this study and an ad hoc group of GRE, MRES, BEPC, MPC, MP, WAPA, NSP, EREPC, CPEC and MISO, was formed to help facilitate optimal solutions. This study was also presented at numerous West Technical Studies Task Force meetings within MISO for an open and transparent planning process.

Winger Thief River Falls Timing Study

2012

OTP

The analysis performed for this study focused on the optimal timing or implementation of a new Winger to Thief River Falls 230 kV line which was recommended from the OTP High Voltage Study. This study incorporated the best available load assumptions. The tracking number for related projects is 2007-NW-N3.

Clearbook Loop Study

2012

OTP

Clearbrook is an OTP substation that is expected to have a large amount of load growth within the next few years. This study focused on the best mitigation to most reliably serve the new and existing load.

Bemidji Study

2012

OTP

Bemidji is one of the most rapidly growing areas of the OTP service territory. To accommodate the predicted load growth, a new delivery system for the city was developed from this study.

Otter Tail Power/Minnkota Power Long Range Transmission Study

2012

OTP

OTP has worked extensively with MPC 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/MPC 41.6 kV and 69 kV systems has identified some transmission projects needed for the upcoming 10 year time horizon that will be coordinated between OTP and MPC. Refined timing of these studies will be completed in the OTP Ten Year Plan which is expected to be completed in 2014.

Keetac Expansion System Impact Study

2011

MP

System impact of proposed expansion at Keetac mine; identified a need for improved reliability and voltage support in the area; Mesabi 115 kV Project (2013-NE-N4)

39 Line Reconfiguration

2012

MP

Evaluation of alternatives for removal/reconfiguration of Laskin - Virginia 115 kV Line; 39 Line Reconfiguration (2013-NE-N1)

Deer River Area Reliability 230 kV Substation

2012

MP

Evaluation of impact of new 230 kV substation and retirement of existing 115 kV line in Deer River area; Deer River 230 kV Project (2009-NE-N2)

NERC Facility Ratings Alert "Minimum Required Ratings" Analysis

2012

MP

Historical data and load flow analysis to evaluate the potential for transmission line derates to address the Facility Ratings Alert; NERC Facility Ratings Alert Medium Priority (2013-NE-N14) & NERC Facility Ratings Alert Low Priority (2013-NE-N15)

North Shore Unit Retirements

2012

MP

Preliminary Analysis of steady state and dynamic impact of various combinations of small coal unit retirements on MP's system

Dorsey - Iron Range 500 kV Project Preliminary Stability Analysis

2012

MP

Preliminary stability analysis on new 500 kV tie line configurations; Great Northern Transmission Line (2013-NE-N13)

Manitoba - United States Transmission Development Wind Injection Study

2013

MP

Identify and evaluate incremental Western Minnesota wind injection capability in conjunction with 1100 MW of new Manitoba to United States transmission service requests and their associated facilities; Great Northern Transmission Line (2013-NE-N13)

BSSE Reactive Study

2013

OTP

OTP is an owner of a new Multi-Value Project (MVP)_ line which runs from Ellendale ND to Big Stone, SD. Because of the long length of this new 345 kV line and the operational challenges that come with such a long line, a study was performed to determine the appropriate reactive compensation to install with the line.

Minnesota Transmission Assessment and Compliance Team 2013 Transmission Assessment (2013 - 2023)

2011

MTO

This report is an annual transmission assessment investigating near-term, mid-term, and long-term transmission conditions. The 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.

Oakes Area Optimization

2013

OTP

These studies investigated the optimal conductor size and cap bank size/location to most efficiently and reliably serve the load in the Oakes Area with the new Oakes 41.6 kV line.

Otter Tail Power Company / Great River Energy/Missouri River Energy Systems Long Range Plan

2013

OTP

OTP has worked extensively with GRE and MRES 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/MRES/GRE 41.6 kV system has identified some transmission projects needed for the upcoming 10 year time horizon that will be coordinated between OTP, GRE and MRES. Refined timing of these studies will be completed in the OTP Ten Year Plan which is expected to be completed in 2014.

Audubon Area Load Serving Study

2012

MRES

This study is complete and has verified the need for more voltage/reactive support in the Audubon/Detroit Lakes area. The required improvements are in the MISO MTEP 13 Report.


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 Midcontinent Independent 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. Earlier MTEP Reports were summarized in past Biennial Reports. For convenience, the following brief description of the latest MTEP reports is presented here. The MISO Expansion Plans are available on the MISO webpage. Visit http://www.misoenergy.org and click on "Planning."

MTEP11 Report

The 2011 MISO Transmission Expansion Plan was approved by the MISO Board of Directors on December 8, 2011. MTEP 11 recommended $6.5 billion in new transmission expansion through the year 2012 in the region.

MTEP12 Report

The 2012 MISO Transmission Expansion Plan was approved by the MISO Board of Directors on December 13, 2012. The subtitle of the report continues from 2009 - "Energizing the Heartland." On the first page of the Executive Summary, the Report states:

MTEP 12 recommends $1.5 billion in new transmission expansion through 2022 for inclusion in Appendix A and eventual construction. This is part of a continuing effort to ensure a reliable and efficient electric grid that keeps pace with energy and policy demands.

The MTEP12 Report identifies those projects required to maintain reliability for the ten year period through the year 2022 and recommends 242 new projects for inclusion in Appendix A.

MTEP13 Report

The 2013 MISO Transmission Expansion is presently in draft form. The report will be completed and approved by the MISO Board of Directors in December of 2013. On the first page of the Executive Summary of the September 30, 2013 draft the Report states:

As part of MTEP13, MISO staff recommends $1.58 billion of new transmission expansion through 2023, as described in Appendix A to the MISO Board of Directors for review, approval and subsequent construction.

The MTEP13 Draft Report identifies 317 new projects required to maintain reliability for the ten year period through the year 2023.

3.3.2 Manitoba Hydro-Electric Board Transmission Service Request

MISO continues to process generation interconnection requests and transmission service requests (TSRs) on the transmission system that they operate. One group of these TSRs involves an increase in the ability to transfer power from Manitoba into the United States. The original Manitoba Hydro TSRs requested delivery totaling 1,100 MW from Manitoba Hydro to four TSR customers in the United States (north to south), and 1,100 MW from utilities in the United States to Manitoba Hydro (south to north). An initial System Impact Study was completed in June 2009 for Firm Point-to-Point Transmission Service between Manitoba Hydro and the TSR customers. The initial study considered several 500 kV transmission options for increasing the capability of the Manitoba - United States interface by 1100 MW flowing north or south. The study was conducted by Siemens PTI and an ad hoc study group consisting of Manitoba Hydro, MISO, and several utilities in the Upper Midwest. Several transmission options extending from the Winnipeg area into the United States via northeastern Minnesota or the Red River Valley were considered in the initial study. A follow-up System Impact Study completed in April 2010 evaluated the impact of a new 500 kV interconnection from the Winnipeg area to the planned CapX2020 Bison Substation near Fargo, North Dakota.

Recently, MISO has conducted a series of sensitivities on the Bison option to evaluate alternative transmission scenarios for achieving 250 MW, 750 MW, or 1100 MW of increased transfer capability from Manitoba to the United States. The MISO TSR Sensitivity Studies have included a "Western Option" extending new 500 kV transmission to the Fargo-Moorhead area in western Minnesota, an "Eastern Option" extending new 500 kV transmission to the Iron Range in northeastern Minnesota, and a "230 kV Option" extending new 230 kV transmission to the Iron Range. While the two 500 kV options could facilitate increased transfers of 750 MW, 1100 MW or more, the 230 kV Option would facilitate only Minnesota Power's 250 MW power purchase agreement (PPA) with Manitoba Hydro. The MISO TSR Sensitivity Studies have demonstrated that the alternative transmission options at their associated transfer levels do not result in negative impacts to the bulk electric system.

In order to facilitate delivery of power under Minnesota Power's PPA, which requires new transmission to be in service by June 1, 2020, Minnesota Power and Manitoba Hydro have elected to begin moving forward with an Eastern 500 kV project. This project involves extension of a new 500 kV line from the Dorsey Substation in Manitoba to the Blackberry Substation on the Iron Range. The new 500 kV tie line will facilitate increased transfers of 750 MW, including Minnesota Power's 250 MW plus additional capability for Manitoba Hydro to deliver power to the remaining TSR customers or others. A future 345 kV build from Blackberry to the Arrowhead Substation near Duluth, MN would facilitate a further increase in total transfer capability from Manitoba to the United States of at least the 1100 MW originally required by the TSRs when the additional capability is needed. The project, known in Minnesota as the "Great Northern Transmission Line", is currently in the early stages of permitting in both Manitoba and Minnesota. More information can be found in Section 6 under project 2013-NE-N13 (MTEP ID's #3831 and 3832).

3.3.3 Manitoba Hydro Wind Synergy Study

The variable and non-peak nature of wind creates integration challenges within MISO. Manitoba Hydro, with its large and flexible system, offers potential solutions for meeting these challenges. At the prompting of Manitoba Hydro (MH) and the potential customers of output from their new hydroelectric dams, MISO conducted the Manitoba Hydro Wind Synergy Study to evaluate whether the cost of expanding the transmission capacity between Manitoba and MISO would enable greater wind participation in the MISO market.

MISO used a new study tool (PLEXOS) to model the day-ahead and real-time markets as well as to capture the uncertainties of wind and load between what is forecasted in the day-ahead market and actual conditions in the real time market. A combination of traditional simulation techniques and new ones developed specifically for this study allowed for a diverse set of benefits to be examined. The synergy between wind and hydro was explored in great detail along with the cost savings of increasing energy delivered into MISO. The benefits of these findings are substantial and show that expanded participation of Manitoba Hydro in the MISO market through increased transmission, generation and market changes would benefit all parties involved.

MISO completed its first comprehensive study that looks at the synergy between hydro power and wind power in June 2013. The Manitoba Hydro Wind Synergy Study found significant benefits can be realized from the addition of either an eastern 500 kV line between Dorsey, Manitoba, and Duluth, Minn., or a western 500 kV line between Dorsey, Manitoba, and Fargo, N.D./Moorhead, Minn (Figure E1).

Transmission Options
20 Year Present Value Benefits

($M-2012)

20 Year Present Value Costs, transmission only

($M-2012)

B/C Ratio averaged over all futures
2012 Nominal Cost Estimate ($M-2012)
East 500kV Option
$1,586
$666
2.38
$685
West 500kV Option
$1,588
$582
2.73
$598
Table E1: Weighted Present Value Benefits and costs (averaged across futures)

The benefit metrics used in the Manitoba Hydro Wind Synergy are indicative of savings MISO may experience if either of the transmission plans were constructed, but they cannot be used to justify cost sharing of either project under the current MISO tariff. The benefits found in this study cannot be used in the Market Efficiency Planning Study (MEPS) to justify project eligibility since the studies use different assumptions and different benefit metrics. The main difference between the two studies is the Manitoba Hydro Wind Synergy Study includes the benefits of incremental hydro generation in the benefit metric. A hypothetical Market Efficiency Project eligibility test was conducted and found that MISO would receive no Adjusted Production Cost benefit from the construction of either line under the current MISO tariff and using the current MTEP12 models. Looking at these projects from a market efficiency perspective does not capture the purpose of the transmission plans.

Based on the preliminary analyses from the Wind Synergy Study, MISO recommended both projects for inclusion in MTEP13 Appendix B.

3.3.4 Northern Area Study

The MISO Northern Area Study was complimentary and closely coordinated with the Manitoba Hydro Wind Synergy Study, the Manitoba Hydro TSR Sensitivity Studies and Market Efficiency Planning Study. The Northern Area Study was developed as an exploratory study to understand how the development of new potential Manitoba - MISO tie-lines, changing mining/industrial load levels, and the retirement of generating units dictate transmission investment in MISO's footprint. The Northern Area Study originated because of multiple transmission proposals and reliability issues located in MISO's northern footprint. Developed through a technical review group (TRG) , the objective of the Northern Area Study was to:

  • Identify the economic opportunity for transmission development in the area
  • Evaluate the reliability & economic effects of drivers on a regional, rather than local, perspective
  • Develop indicative transmission proposals to address study results with a regional perspective
  • Identify the most valuable proposal(s) & screen for robustness

The Northern Area Study was a collaborative effort between stakeholders and MISO staff. Meetings were open to all stakeholders and interested parties - study participants included state regulatory agencies, transmission owners, market participants, environmental groups, and industry experts. A stakeholder technical review group (TRG) was involved in all discussions and decisions.

The potential for industrial load increases and decreases was the first scenario driver for the Northern Area Study. The driver for studying industrial load levels in Northern Area Study scenarios originated with a request to evaluate transmission potential through the Upper Peninsula of Michigan to accommodate additional mining opportunities. Industrial load change potential was later expanded to the larger Northern Area Study region after the June 7, 2012 TRG meeting. The increased industrial load potential included approximately 300 MW in northern Wisconsin/Michigan's Upper Peninsula, 600 MW in northern Minnesota, and 1,000 MW in western North Dakota. Additionally, there was a similar potential to decrease area industrial load through the closing of mines and industrial plants.

The second scenario driver in the Northern Area Study was a potential for increased generation and imports from Manitoba Hydro. Manitoba Hydro has development plans for adding two additional hydro units, Keeyask (695 MW) and Conawapa (1,485 MW). The Conawapa and Keeyask units would be phased-in from 2019 through 2027. Together, the units would increase import potential into MISO by approximately 1,100 MW, while the remaining capacity would serve Manitoba Hydro load. To deliver 1,100 MW of imports to the MISO footprint three different tie-lines were proposed. Those three tie-line configurations are shown in Figures 1-3 through 1-5 below. The Northern Area Study provides no indication or comparison between Manitoba to MISO tie-line options. Tie-lines and new hydro generation were inputs to the Northern Area Study to determine economic development opportunities after the tie-lines and generating units are built and in-service - essentially answering what if any build-out is required for MISO's entire northern footprint to realize the benefits of new Manitoba imports.

Figure 1-3: Manitoba - Duluth 500 kV Tie-Line
Figure 1-4: Manitoba - Fargo 500 kV Tie-Line
Figure 1-3: Manitoba - Fargo and Duluth "T" 500 kV Tie-Line

The final Northern Area Study driver was unit retirements, specifically the potential retirement of the Presque Isle Power Plant in Marquette, Michigan. Prior to the Northern Area Study kick-off meeting on June 7, 2012, a public announcement was made saying the Presque Isle Power Plant was likely retire by 2017/2018 due to the United States Environmental Protection Agency (EPA) regulations. The retirement of this plant was expected to cause area reliability issues. On November 27, 2012. We Energies and Wolverine Power Cooperative announced an agreement that would keep the Presque Isle Power Plant operational by adding emission controls to the five units. After the Presque Isle public announcement, the Northern Area Study eliminated all scenarios which retired Presque Isle from the analysis.

3.3.5 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 has approved 17 projects in the Upper Midwest for MVP certification, including the CapX2020 Brookings County-Hampton line and the ITCM Minnesota-Iowa 345 kV project that is part of MCP #3. Other Upper Midwestern lines include proposed projects in Iowa, North Dakota, South Dakota and Wisconsin.

The MVP Portfolio received MISO Board of Director approval in December of 2011.

MISO's business analysis demonstrates that 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 approved 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 approved 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 below shows the 17 MVP projects.


3.3.6 Market Efficiency Planning Study

As part of its planning process, the MISO conducts a Market Efficiency Planning Study (MEPS) whose purpose is to determine whether there are transmission projects that could remove transmission constraints and thus more efficiently use available generation resources. The MEPS results are reported as part of the annual MTEP report.

During the MEPS process, projected economic and power flow models are developed which, when analyzed, determine the total production costs that are incurred to provide energy to the MISO load. Transmission constraints, which are the transmission elements that limit the amount of power that can be transferred between the unused, lower-cost generation and the load, are identified.

Through a stakeholder discussion, transmission projects are proposed which could mitigate the constraints. The costs for these proposed transmission projects are determined and compared to the amount of production cost savings that could be realized if those projects were in service. The resultant benefit to cost (B/C) ratio of the projects indicates whether the proposed solutions should be considered for further evaluation for constructability and reliability analysis. Stakeholder review and comments are compiled and a decision on whether to recommend a MEPS project be included in the upcoming MTEP report is made.

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. These are all studies that have been identified since completion of the 2011 Biennial Report.

Study Title

Anticipated Completion

Utility Lead for Study

Description

Otter Tail Power Ten Year Plan

2014

OTP

The Otter Tail Ten Year Plan will summarize the limitations to the OTP system within the next ten years and is intended to be refreshed annually or at least biennially. This study will refresh project need dates and is based from conclusions of the recently completed group of Long Range Plans and the OTP High Voltage study

MPC Overall 69 kV Study

2015

MPC

The MPC Overall 69 kV Study will focus on reviewing the adequacy of the MPC 69 kV system for serving load from both primary feeds and alternate feeds during outages.

Magnetation Plant 4 System Impact

2013

MP

System impact of Magnetation Plant 4; Canisteo Project (2013-NE-N5)

Polymet System Impact

2013

MP

System impact of new Polymet loads; NorthMet (f/k/a "Dunka Road") Substation (2011-NE-N5) & Hoyt Lakes Substation Modernization (2013-NE-19)

Boswell - Zemple 230 kV Line Outage Study

2013

MP

Evaluate the performance of MP 115 kV system and GRE 69 kV system during Boswell - Zemple 230 kV line outage; Deer River 230 kV Project (2009-NE-N2)

Duluth/Superior Area Study

2013

MP

10-year outlook for Duluth/Superior area to re-evaluate the need for Duluth 230 kV Project (2007-NE-N1), Haines Road Capacitor Bank (2013-NE-20), and/or other projects in the area.

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:

3.5 National Studies

3.5.1 Eastern Interconnection Planning Collaborative

In mid-2009 the Department of Energy (DOE) issued a funding opportunity announcement DE-FOA-0000068 "Resource Assessment and Interconnection-level Transmission Analysis and Planning," directed to the Eastern, Western, and Texas interconnections. PJM Interconnection, LLC (PJM) bid for and won the Topic A portion of this FOA for the Eastern Interconnection, award DE-OE0000343, supported by nine members1 of the Eastern Interconnection Planning Collaborative (EIPC). EIPC had been formed earlier in 2009 by 25 of the larger Planning Authorities in the Eastern Interconnection.

The work under this funding opportunity was divided into two phases. Phase 1 began with the creation of a combined grid model for the Eastern Interconnection (the "roll-up" case) and the formation of a diverse Stakeholder Steering Committee (SSC) with interests in public policy "futures". Work continued with macroeconomic and generation resource allocation studies of eight futures chosen by the SSC, and the modification of the roll-up case into a Stakeholder Specified Infrastructure (SSI). Finally the SSC chose three future scenarios as the basis for Phase 2 of the project:

1. A Nationally Implemented Federal Carbon Constraint with Increased Energy Efficiency/Demand Response, (Scenario 1: Combined Policies)

2. A Regionally Implemented National Renewable Portfolio Standard (Scenario 2: National Renewable Portfolio Standard/Implemented Regionally), and

3. Business as Usual (Scenario 3: Business as Usual).

An interim report describing Phase 1 studies and results was released in December 2011 (http://www.eipconline.com/uploads/Phase_1_Report_Final_12-23-2011.pdf). Phase 2 included transmission studies and production cost analyses of the three future scenarios chosen by the stakeholders. This included developing transmission options, studying grid reliability and production costs, and estimating generation, transmission, and selected "other" costs. A number of sensitivities were studied for the three scenarios. The sensitivities included four sensitivities to investigate the amount of wind curtailment in Scenario 1 which was 15% in the base run. They also included analyzing high loads and high gas prices in Scenario 3.

This Topic A work was carried out in close interaction with the Eastern Interconnection Topic B recipient of DOE-FOA-0000068, the National Association of Regulatory Utility Commissions (NARUC), and the state representative's group formed through their award, the Eastern Interconnection States Planning Council (EISPC). EISPC members include regulatory representatives from the 39 states of the Eastern Interconnection, the District of Columbia, and the City of New Orleans. While the EISPC report on this work will be published separately, this report includes input from the EISPC. DOE is additionally supporting the Interconnection-Level Transmission Planning Analysis through work at selected national laboratories on grid frequency response and on fault induced delayed voltage recovery. A Phase I report was filed with the Department of Energy in December of 2011. A Phase II report was completed on December 22, 2012 and submitted to the Department of Energy. The Phase II Report is linked here: http://www.eipconline.com/Phase_II_Documents.html

With the completion of the majority of the Phase 2 work by EIPC, the Eastern Interconnection Topic A work scope has now met the goals initially defined in the Statement of Project Objectives. One aspect highlighted in Phase 1 of the project but not studied in detail is the interrelationships of various energy related infrastructures. These interrelationships are being considered further to better understand how these relationships might impact the broad range of alternative futures. One example is the relationship between the natural gas supply and delivery infrastructure and the electric transmission system. This topic is currently being studied as an extension of the Phase 2 EIPC work and insights from this additional work will be added to the Phase 2 study report.

A number of valuable conclusions were drawn from the study work to date. While the results were not intended as a specific plan of action or for use in any state electric facility approval or siting processes, and did not include all mandatory NERC reliability planning requirements, they do provide general information to policy-makers and stakeholders and will serve as guidelines in future activities of EIPC as it focuses on its continuing scope. As the first interconnection-wide study of its kind, the work provided insights to EIPC members regarding how future studies may be performed and how future interconnections may develop.

Other benefits of the study included an interaction and development of experience between Planning Authority participants and state participants. The formation of the Stakeholder Steering Committee (SSC), which represented a wide range of interests, presented challenges but both EIPC and SSC found substantial advantages resulting from the study, as well as identifying opportunities for improvement in the future.

Below are the three transmission options developed for each of the three future scenarios, followed by a summary of the costs estimated for each scenario.

Figure ES-1. Scenario 1: Combined Policies - New/Upgraded Transmission
Approximate 2030 O&M Costs - ($2010 Billions) cost for Scenario 1: $149.6 Billion
Overnight Capital Costs for Capital through 2030 ($2010 Billions) for Scenario 1: $978.2 Billion

Figure ES-2. Scenario 2: NRPS/IR - New/Upgraded Transmission
Approximate 2030 O&M Costs - ($2010 Billions) cost for Scenario 2: $145.9 Billion
Overnight Capital Costs for Capital through 2030 ($2010 Billions) for Scenario 2: $771.9 Billion

Figure ES-3. Scenario 3: Business as Usual - New/Upgraded Transmission
Approximate 2030 O&M Costs - ($2010 Billions) cost for Scenario 3: $154.4 Billion
Overnight Capital Costs for Capital through 2030 ($2010 Billions) for Scenario 3: $284.6 Billion

Scenario 1, with its elimination of virtually all coal plants, inclusion of over 215 GW of wind in Nebraska, the MISO region and the SPP region, and use of 152 GW of Demand Response, needed the largest transmission buildout to meet the policy objectives. Scenario 2 with a National Renewable Portfolio Standard that was implemented within regions needed a more moderate amount of transmission added and Scenario 3, Business as Usual, required the least amount of transmission added of the three scenarios.

The cost estimates in the project are based on a variety of generalized assumptions and are only broadly indicative on a relative basis between the futures. The analysis did not include social benefits and costs that would arise from the different policies modeled. Also not included in the above are costs for:

  1. Lower voltage transmission projects
  2. Stakeholder Specified Infrastructure (SSI) generation and transmission projects (common to all three scenarios)
  3. Generation interconnection costs not included in the overlays, i.e., the generator step-up and the lead lines to the first breaker - the costs for the generator interconnection overlays are included
  4. Generation deactivation/decommissioning
  5. Capital costs for existing units
  6. Transmission O&M.

MTO utilities continue to 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. More information about the EIPC effort can be found at the link below.

http://www.eipconline.com

3.5.2 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 have complied with the December 2011 deadline and will make the 2013 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 Midcontinent Independent System Operator (MISO) 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 MISO would serve 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.

3.5.3 Eastern Renewable Generation Integration Study

The National Renewable Energy Laboratory (NREL) is undertaking the Eastern Renewable Generation Integration Study (ERGIS) which is a follow-up to previous wind integration studies including the Eastern Wind Integration Transmission Study (EWITS). The 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. This study will specifically determine the operational impact of 30% wind and solar penetration on the Eastern Interconnection at a sub-hourly resolution and to evaluate the efficacy of mitigation options in managing variability and uncertainty in the electric power system. The transmission options, developed in earlier studies, including EIPC, will be refined and used in this study assumption. New study tools are being used to better simulate real time system operations. The Technical Review Committee includes a the participation of a cross section of industry stakeholders.

3.6 MAPP Load & Capability Report

Presently, PUC rules require the utilities to include in the Biennial Report a copy of "the most recent regional load and capability report of the Mid-Continent Area Power Pool" (MAPP). Minn. Rules part 7848.1300, item B. MAPP, however, has not prepared a Load & Capability Report since May 2009. There is nothing to report. The Midcontinent Independent Transmission Operator (MISO) is now responsible for most of the planning that occurs in this part of the country, as has been described elsewhere in this report, and the MISO Transmission Expansion Plan (MTEP) report has become the place to find out information about most transmission plans in Minnesota and the region.