This section documents the ATC Energy Collaborative – Michigan (U.P. Collaborative) study results. It summarizes current projects and then elaborates on the Collaborative process including use of the Strategic Flexibility approach to planning, identified needs and core solutions, and remaining work.

We have completed or are currently constructing a series of significant upgrades across Michigan’s Upper Peninsula. The most notable projects are:

• The Eastern Upper Peninsula Reliability and Operating Enhancement Phase 1 (EUROPE) projects completed in 2006.
• The Northern Umbrella Projects (NUP) scheduled for completion in 2010.
• Three urgent projects in the Eastern Upper Peninsula completed at the start of the winter of 2007-08. These projects provided a hedge for the risk of low water availability for hydroelectric generation

Even with these significant upgrades, operational challenges remain in this region due to the delicate balance among generation, load, market flows and transmission facilities that currently exists. There are also continuing asset renewal needs.

Strategic Flexibility Planning

Planning for the Upper Peninsula transmission system has been a unique challenge. For example, small changes in existing or planned load or generation can push the system beyond reasonable limits. Therefore, ATC decided to apply strategic flexibility planning principals to better understand the core and contingent needs and solutions in this specific area of our system. To develop our strategic flexibility assumptions for the intermediate (3-5 year) and long term (10-15 year) periods, during 2008 and 2009 we have engaged Upper Peninsula stakeholders in the Collaborative process to examine the bounds of six plausible futures. Similar to ATC’s past economic benefits studies, the futures include: Robust Economy, High Retirements, High Environmental, Slow Growth, DOE 20% Wind, and Fuel & Investment Limitations. These futures were developed from specific Upper Peninsula drivers using stakeholder input. Figures UP-1 and UP-2 illustrate the initial plan for Collaborative activities which has slipped about one to two months from the milestones shown. Table UP-1 delineates the specific studies conducted to establish the operational needs for the study area.

Developing drivers and futures for the geographically vast west-east expanse in the Upper Peninsula required breaking the region into three zones: Western, Central, and Eastern. Figure UP-3 summarizes the load and generation bounds used in the six futures developed in the U.P. Collaborative. Tables UP-2 and UP-3 provide specific details about the futures assumptions.

Using the assumptions for the six U.P. futures we modified the MISO 2018 Joint Coordinated System Plan (JCSP) study model, which was used for the ATC economic benefits studies performed in 2009, to create the 2018 and 2024 PSS/E planning models for each of the six U.P. futures.

Needs Analysis and Solutions Development

A cross-functional team was formed at ATC to identify needs and develop solutions. This allowed integration of multiple need drivers into the solution development process, including NERC transmission planning standards, generation and distribution interconnections, asset renewal, and system operating driven needs. To establish NERC transmission planning driven needs, we analyzed the 12 power flow future models, gathered information on ATC asset renewal needs, and reviewed loop flow impacts and operating outage coordination concerns. This allowed us to establish sets of core and contingent transmission system needs across the Upper Peninsula. Core needs occurred in most futures. Contingent needs occurred only in a few futures.

The planning needs from the 12 peak study models for 2018 and 2024 are summarized in overload and low voltage tables for each of the three U.P. study zones. These needs were determined by performing single contingency analysis on the 12 peak study models, and identifying overloaded facilities or low post-contingency voltages. The tables include:

              Western U.P. zone                     Tables UP-4-W and UP-4A-W

              Central U.P. zone                       Tables UP-4-C and UP-4A-C

              Eastern U.P. zone                      Tables UP-4-E and UP-4A-E

These planning needs are also depicted graphically in the following figures:

              Western U.P. zone                     Figures UP-4-W and UP-4A-W

              Central U.P. zone                       Figures UP-4-C and UP-4A-C

              Eastern U.P. zone                      Figures UP-4-E and UP-4A-E

Solution development on each of the 12 peak study models was completed by testing numerous individual solutions and combinations of solutions that would mitigate the overload and voltage violations in each futures case. For each future, two or three solution sets were identified whose solutions addressed the issues in both 2018 and 2024 for that future.

The solution sets developed for each planning future are summarized in the following tables and depicted graphically in the following diagrams:

In addition to the planning needs from the futures study, there are a significant number of asset renewal concerns regarding condition and performance of transmission lines throughout the U.P. The Asset Planning and Engineering department identified twelve U.P. transmission lines that either exhibit poor reliability performance or are expected to have condition issues (rotting poles, insulator replacement, etc.) in the next 10-15 years. These lines are shown on Figure UP-6.

The System Operations department identified several areas in the U.P. with significant operating issues. These issues can be caused by high bias flows through the U.P. that create reliability concerns, maintenance outages that are very difficult or expensive to perform due to weak transmission or lack of available generation in specific areas, and high steady-state voltages and voltage excursions. Figure UP-7 depicts the most significant operating issues in the U.P. Note that these issues often occur during off-peak and light system loading periods, meaning they can occur a significant number of hours per year.

The solution development process in the U.P. therefore included the future planning needs as well as the asset renewal and system operating needs throughout the U.P. to identify the core solutions required in the U.P.

The needs driving these core solutions are related to potential thermal overloads or potential out of range voltages for serving the more likely load and generation forecasts of the future. These needs are aggravated by loop flows crossing the region from either west-to-east or east-to-west. All of these conditions make it extremely difficult or even impossible to coordinate maintenance outages without affecting service to customers. The next section gives more details about specific need drivers and solution options evaluated in the various U.P. areas.

Core U.P. Solutions

As the system needs analysis and solution development proceeded we found it convenient to identify four critical areas within the three original U.P. study zones due to system performance characteristics unique to those areas. These four areas are.

• Eastern area – located within the eastern U.P. study zone, and consists of the far eastern U.P. (St. Ignace and Sault Ste. Marie areas) and the lower half of the eastern U.P. to Manistique.
• Escanaba area – central Delta County in the southern part of the central U.P. study zone.
• Munising/Newberry area – located in the northern half of the central and eastern U.P. study zones from Forsyth east through Newberry to Brimley.
• Western area – defined as the same as the western U.P. study zone.

Eastern Area Core Solutions

Figures UP-8A-E and UP-8B-E summarize the core needs identified in the eastern U.P. area. The planning futures needs are low voltages and overloaded facilities along the north-to-south transmission corridor between St. Ignace and Sault Ste. Marie. The asset renewal concerns are also located along the St.Ignace-Sault Ste. Marie transmission corridor. There are numerous system operations needs throughout the eastern U.P. due to high west-to-east and east-to-west bias flows, high voltages and voltage excursions, and numerous operating outage coordination issues when maintenance work is very difficult or very expensive to perform.

A new transmission-distribution interconnection, referred here to as Kinross Township Unforecasted Load Addition (Kinross Load), was recently proposed for a 25-megawatt load addition in Chippewa county south of Sault Ste. Marie. This load represents a significant addition to the 45 megawatts of existing load in the Sault area, and creates a sudden change in the load, generation, and transmission balance in the eastern U.P. Due to the significance of this proposed load, a seventh eastern U.P. Planning future (Kinross) was created to specifically study the impacts this load would have on the Planning needs and solutions.

The solution development process identified several possible core solutions that could address different levels of the various planning needs as well as the asset renewal and system operations concerns.

Large bias flows through the U.P. in both directions during off-peak system conditions regularly create excessive loadings or low voltages that affect the ability to reliably operate and maintain the eastern U.P. transmission system. The Collaborative effort has identified power flow control in the eastern U.P. at Straits Substation as needed to address the reliability and maintenance concerns.

The eastern U.P. core transmission solutions that were considered are shown in Figure UP-8C-E.

The various projects considered exhibited varying degrees of performance benefit. Performance matrices were developed to summarize how each of the considered core solutions addressed the needs in each planning future, including the asset renewal and system operations needs. Table UP-8A-E shows the performance matrix of the considered core solutions for the six original Planning futures, the Kinross T/D future, and the asset renewal issues. Table UP-8B-E shows the performance matrix of the solutions for the various system operations issues.

The performance matrices can be best interpreted by the color codes in the cells associated with each future or other need. If a cell was black, this means the project or projects listed in the left half of that row did not perform adequately (“Not Adequate”) to address the Planning, Customer Relations/Interconnection Services, or Asset Renewal department need in that column. If a cell was green, the solution(s) was adequate or nearly adequate to address the issues, while a yellow cell indicated the solution(s) was more robust than required to address that need. There were gray cells in the System Operations performance matrix that had varying levels of marginal performance that were identified.

The core projects that ATC identified and are reviewing with stakeholders for input in the eastern U.P. area include:

• Uprate both Straits-McGulpin 138-kV overhead lines (E2)
• Rebuild the Pine River-Straits 69-kV lines as 69 kV double circuit (E4)
• Uprate Pine River-9 Mile 69-kV line 6923 to 167 deg F and minimum asset renewal projects (E6, E-AR2)
• 9 Mile-ESE Hydro Minimum Asset Renewal Projects (E-AR4)
• Power Flow control on the Straits-McGulpin 138-kV Lines (E3 or E31)
• Energize the 2nd Indian Lake-Hiawatha line at 138 kV (E8).

If the Kinross load is confirmed then projects E4, E6, and E-AR2 will be replaced with project E23, and the core projects will include:

• Uprate both Straits-McGulpin 138-kV overhead lines (E2)
• Rebuild Pine River-Straits 69-kV lines as 138-kV double circuit, rebuild Pine River-9 Mile as 138/69-kV double circuit, add a new 138/69-kV transformer each at Pine River and 9 Mile Substations (E23)
• 9 Mile-ESE Hydro Minimum Asset Renewal Projects (E-AR4)
• Power flow control on the Straits-McGulpin lines (E3 or E31)
• Energize 2nd Indian Lake-Hiawatha line at 138 kV (E8)

The customer associated with the Kinross load initially requested that construction of these transmission facilities be completed in 2012. However, various delays have pushed this date out until at least 2013.

Escanaba Area Core Solutions

Figures UP-8A-ESC and UP-8B-ESC summarize the core needs identified in the Escanaba area. The planning needs are low voltages and overloaded facilities throughout the 69-kV system in central Delta County. The primary asset renewal concerns are a 69-kV transmission line between Powers and Chalk Hills, and a 69-kV transmission circuit northwest from Escanaba to Gwinn. There are numerous system operations needs associated with the Escanaba area, including several outage coordination issues that make maintenance work very difficult or expensive to perform, as well as local issues associated with lack of generation availability or possible network transmission service additions.

The solution development process identified four core solutions groups that could address different levels of the various planning needs as well as the asset renewal and system operations concerns. The Escanaba area core transmission solution sets that were considered are shown in Figure UP-8C-ESC.

Performance matrices were developed to summarize how each of the considered core solution sets addressed the needs in each planning future, including asset renewal and system operations needs. Table UP-8A-ESC shows the performance matrix of the considered core solution sets for the six original planning futures and the asset renewal issues. Table UP-8B-ESC shows the performance matrix of the solution sets for the various system operations issues.

Solution Set D was identified in the Escanaba area, and includes the following projects:

• Uprate the Escanaba area 69-kV loop lines to 167/200º operation (C2a, in progress)
• Increase the capacity of the 138/69-kV transformer or add a 2nd 138/69-kV transformer at the Chandler Substation (C3)
• Add a new 345/138-kV transformation at the Arnold Substation (C21)
• Extend the 138-kV system into the major load areas of Escanaba (C5, C6, C8)
• New Escanaba 69-kV substation (C22, non-ATC)
• Uprate Delta-Escanaba 69-kV lines #1 & #2 to 55 MVA (C25, C26, one line non-ATC)
• Minimum Asset Renewal Projects on the Chandler and 6910 69-kV lines (C-AR3, C-AR4)

These provisional projects have projected in-service dates in the 2014-2015 timeframe.

Munising/Newberry Area Core Solutions

Figures UP-8A-MN and UP-8B-MN summarize the core needs identified in the Munising/Newberry area. This area consists of transmission facilities from Forsyth Substation in Gwinn to Seney Substation, and from Newberry to 9 Mile Substation near Brimley. The planning needs are low voltages and overloaded facilities throughout this area. The asset renewal concerns are the 138/69- kV transmission lines between Forsyth and Seney, and the 69-kV transmission circuit east from Newberry. There are a few system operations needs associated with the transmission lines and transformers in the Forsyth and Munising areas that make maintenance work very difficult or expensive to perform.

The solution development process identified five core solutions groups that could address different levels of the various planning needs as well as the asset renewal and system operations concerns. The Munising/Newberry area core transmission solution sets that were considered are shown in Figure UP-8C-MN.

Performance matrices were developed to summarize how each of the considered core solution sets addressed the needs in each planning future, including asset renewal and system operations needs. Table UP-8A-MN shows the performance matrix of the considered core solution sets for the six original planning futures and the asset renewal issues.

Solution Set B was identified in the Munising/Newberry area, and includes the following projects:

• New Gwinn-Forsyth 69-kV line (C10)
• Close the normally open Seney-Blaney Park 69-kV line and uprate the entire Munising-Seney-Blaney Park 69-kV circuit (Inland line) to 167º F operation (C17)
• Minimum Asset Renewal Projects on the Munising138 138-kV line, AuTrain 69-kV line, Inland 69-kV line, and 69-kV line 6952 (C-AR1, C-AR2, E-AR3)

These projects are provisional in nature, and have projected in-service dates in the 2012-2015 timeframe.

The performance matrix for the Munising/Newberry area shows that the selection of Solution Set B presents a level of risk should certain futures develop. Should additional load development from these futures actually occur, consideration of contingent solutions may be required, perhaps Solution Set C.

Western Area Core Solutions

Figures UP-8A-W and UP-8B-W summarize the core and contingent needs identified in the Western area of the U.P. The planning futures needs are low voltages and overloaded facilities throughout this area. Note that the core needs are associated with the transfer of power to the Houghton area and north, and occur in 5 of the six planning futures. The contingent needs are more region-wide in the western U.P., occurred in 3 or the 6 planning futures, and are associated with the much higher imports into the entire northwestern U.P. due to either higher load forecasts or drastically reduced western U.P. generation. The asset renewal concerns are the 69-kV transmission lines between Baraga and Houghton and between Conover and Mass. There are system operations needs associated with the maintenance outage of either 138-kV line southeast of Baraga, either Baraga-Houghton line, or the 138/69-kV transformer at Atlantic or M38.

It should be noted that the M38 138-kV capacitor bank project to be completed in 2009 will add a new 138-kV bus and capacitor bank at M38 that will greatly improve the availability of maintenance outages at M38.

The solution development process identified several possible core solutions that could address different levels of the various planning needs as well as the asset renewal and system operations concerns. The western U.P. core transmission solutions that were considered are shown in Figure UP-8C-W.

Performance matrices were developed to summarize how each of the considered core solutions in the western U.P. addressed the needs in each planning future, including asset renewal and system operations needs. Table UP-8A-W shows the performance matrix of the considered core solutions for the six original planning futures and the asset renewal issues.

The core projects that were identified in the western U.P. area include:

• Uprate the M38-Atlantic 69-kV overhead line (Atlantic69) to 167º F (W13)
• Minimum Asset Renewal Projects on the Atlantic69 line and 69-kV line 6530 (W-AR1, W-AR2)

These projects are provisional in nature, and have projected in-service dates in the 2013-2014 timeframe.

One contingent project was identified that was determined only to be needed in three planning futures:

• Rebuild the Lakota Road-Mass-Winona 69-kV overhead lines at 138-kV operation (W1)

Note that this contingent project was not selected to be implemented due to the contingent nature of the needs driving this project. Should load and generation profiles in the northwestern U.P. change enough to result in large imports of power to that area, this project will be revisited.

Conclusions

In 2009, we continue to work with stakeholders, including commission staff, to develop plans that will provide continued reliability and additional operational flexibility for the eastern, central and western U.P. areas. We will post our meeting results to allow for input from all interested stakeholders. We are currently in the process of reviewing our identified projects with stakeholders and seeking their input towards a goal of developing a collaborative set of solutions in the U.P. Please refer to Table UP-2 and Table UP-3 for the strategic flexibility decision matrix utilized in the U.P. Collaborative analyses.

Other area concerns

It should be noted that our area plans may impact the Lower Peninsula of Michigan, northern Wisconsin, or Canada as well as the U.P. of Michigan.

Remaining Work

At the time of writing this document there is still additional work remaining to complete the U.P. collaborative study effort and begin project development:

• Stakeholder review – Complete the process of reviewing our identified projects with stakeholders to seek their comments.
• Economic benefits analysis – It is undecided at this point if an economic benefits analysis will be performed in the U.P., specifically to identify the impact that the selected core projects from the U.P. Collaborative will provide with regard to U.P. access to the energy market.
• Final report – Develop a final summary document for the entire ATC Energy Collaborative – Michigan study effort. This report would include all steps completed so far as well as any studies listed above. It is not known when this document will be completed due to the uncertain nature of the studies above, although it is possible that multiple versions of the summary document could be developed as various study initiatives are completed.
• Core Project Development – Significant work remains with regard to the development of the core projects from their current provisional status through project completion.

Key to Sources referred to:

1 – “ATC Energy Collaborative – Michigan Update,” February 13, 2009, filename: 01 ATC_Energy_Collaborative_Michigan_Update_021309.doc

2 – “ATC Energy Collaborative – MI Scope of Work to Present…,” June 26, 2009, filename: 02 July 17th Concise presentation for Dale and Carol.doc

3 – “ATC Energy Collaborative – Michigan detailed analysis plan – DRAFT,” June 12, 2009, filename: ATC_Energy_Collaborative-Michigan_Detailed_Analysis_Plan_061209 Update.doc

4a – “ATC Energy Collaborative – Michigan Core Solutions Discussion and Feedback,” June 22-23, 2009, filename: 04a Core Solutions Stakholder Feedback 06-22-2009.ppt

4b – “U.P. Collaborative Core Solutions,” 6/22/2009, filename: 04b U P _Collaborative_Core_Solutions_Stakeholders_062209.doc {Probably don’t need this one because it is included in the 7-22-09 AIM Governance package}

5 – “ATC Energy Collaborative – MI Update for AIM Governance Team,” July 22, 2009, filename: 05 AIM_072209_UP_Collaborative_Core_Solutions_071709_final.doc

6 – “UP Collaborative Strategic Options,” May 14, 2009, filename: 06 UP Collaborative Strategic Projects (Rev 2).ppt

7 – “UP Needs projects,” July 30, 2009, filename: 07 UP_needs_projects_073009.doc