Studies and Reports > 2011
MN Biennial Report > Transmission Studies
Projects Report 2011
Chapter 3: Transmission Studies
3.0 Transmission Studies
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.
|LaCrosse to Madison 345 kV Transmission Line
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)
||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”.
||Electric Transmission America, LLC
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)
||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
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
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
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
||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
|Cass Lake Capacitor Bank Study
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.
load-serving need for tracking #2003-NE-N2, MTEP Project ID 2634
|Duluth Area 230 kV & 15 Line Upgrade
Transmission Reliability Study tracking #2007-NE-N1 & 2011-NE-N2, MTEP
Project ID 2548 & 2549
|9 Line Upgrade
capacity requirements & upgrade requirements, tracking # 2011-NE-N1, MTEP
||Transmission to serve Mining Resources LCC Tracking #
2011-NE-N7, MTEP 3532
|Transmission Service Related Upgrades
||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
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
||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
The Bemidji – Grand
Rapids project is also listed in MTEP Appendix A under projects 279 and 3156.
– Cass Lake 230 kV line
Lake – Wilton 230 kV line
Lake 230/115 kV transformer
- New breakered 115 kV substation at Nary
– Helga – Nary 115 kV line uprate
– Cass Lake 115 kV line uprate
operating guide to protect Nary – Laporte 115 kV line prior to other planned transmission improvements
|Minnesota Transmission Assessment and Compliance Team 2011
Transmission Assessment (2011 – 2021)
||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
||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
|Otter Tail Power Company / Central Power Electric
Cooperative Long Range Transmission Study
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
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
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
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.
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
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.
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.
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
- 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
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
- 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
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
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
3.3.3 Manitoba Hydro Wind Synergy
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.
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
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).
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
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.
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.
proposed MVP portfolio enables the delivery of 41 million megawatt hours of
renewable energy annually.
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
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
Utility lead for Study
|Otter Tail Power/Minnkota Power Cooperative Long Range Transmission Study
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
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
||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
|Deer River Area
||Load serving study of Deer River area 2009-NE-N2,
MTEP 3531 and 2551
||MP 23L upgrade alternatives 2011-NE-N12,
area load serving needs
|Austin Area Load Serving Study
||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
|Xcel Energy 10-Year Plan Load Serving Study
||2010, updated annually
||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
|Audubon Area Load Serving Study
||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
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.
3.6.2 NERC Facility
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
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:
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.
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
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
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.