ATC has continued to develop and refine the results of our ATC Energy Collaborative – Michigan (U.P.). In the 2009 10-Year Assessment, we identified core solution sets. In the 2010 10-Year Assessment, we are reporting on the progress of solution development as well as the preliminary results of our High Retirements Future Enhancement studies.

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 and geographical 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 north eastern portion of the central and northwestern portion of the eastern U.P. study zones, from Forsyth east through Newberry to Brimley.
• Western area – defined the same as the western U.P. study zone.

Please refer to the 2009 ATC Energy Collaborative – Michigan for the details related to our 2009 studies.

Project development progress

Table UP-1 shows the status of the core Collaborative projects as of September 2, 2010.

Figure UP-MCP-1 is a map showing the major core projects as of June 1, 2011. ATC is continuing to review the need for any additional projects.

Eastern area core solutions

The major efforts to report since our last Assessment are as follows:

1. Straits-Pine River rebuild – This project is being developed as a 138-kV double circuit rebuild of the two existing 69-kV circuits operating at 69 kV until further development of a potential new load in Kinross Township (Kinross). If the Kinross load materializes, additional projects would be put in place. In-service date is expected to be 2014.
2. Pine River-Nine Mile Uprate and Asset Renewal – This will be the project we need to put in service by 2016 if Kinross load does not appear. Kinross Load would require a 138/69-kV double-circuit rebuild of these two 69-kV circuits.
3. Straits Flow Control – ATC, in conjunction with ITC and MISO, is continuing planning activities to choose the appropriate flow control solution for the Eastern U.P. The current goal is to ensure that the project is in the design phase by early 2011. This project and the associated Hiawatha-Indian Lake 69- to 138-kV conversion are crucial to improving critical operating concerns in the eastern Upper Peninsula and extreme northern Lower Peninsula of Michigan. In-service date is expected to be roughly 2014.
4. Straits Reactors – This relatively inexpensive project was added since the 2009 studies as a short-term way to help control high voltages at Straits and McGulpin substations. Flow control is still needed to deal with the concerns caused by relatively large power flow swings for the area’s 69-kV system. In-service date is expected to be late 2010.

The complete list of core projects that we’ve identified and are reviewing with stakeholders are depicted in Figure UP-8C-E:

1. Uprate both Straits-McGulpin 138-kV overhead lines (E2),
2. Rebuild the Pine River-Straits 69-kV lines as 138-kV double circuit, operate at 69 kV (E4),
3. Uprate Pine River-Nine Mile 69-kV line 6923 to 167 deg F and asset renewal projects (E6, E-AR2),
4. Nine Mile-Edison Sault Hydro Asset Renewal Projects (E-AR4),
5. Power Flow Control on the Straits-McGulpin 138-kV Lines (E3 or E31),
6. Energize the second Indian Lake-Hiawatha line at 138 kV (E8), and
7. Add reactors to the tertiary windings of the Straits 138-69 kV transformers (E32).

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

1. Rebuild Pine River-Straits 69-kV lines as 138-kV double circuit, rebuild Pine River-Nine Mile as 138/69-kV double circuit, add a new 138/69-kV transformer each at Pine River and Nine Mile substations (E23), and
2. Other core projects are E2, E-AR4, E3 or E31, and E8.

The earliest the Kinross load could be connected to required transmission projects would be 2014. Please refer to Zone 2 – 2015 study results and our Asset Renewal section for further details related to the above projects

Escanaba area core solutions

Since our 2009 Assessment, we have focused on refining the core solutions in this area particularly to identify short lead-time solutions that could expedite improving service to our customers in this area. The refined list of core projects that ATC and its stakeholders have identified in the Escanaba area is shown in Solution Set D of Figure UP-8C-ESC and includes the following:

Projects in service:

1. Uprate the Escanaba area 69-kV loop lines to 167/200ºF operation (C2a), and
2. Uprate Delta-Escanaba 69-kV lines #1 & #2 to 55 MVA (C25, C26, one line non-ATC).

Near-term projects:

1. Asset Renewal Project on the Chandler 69-kV line (C-AR3),
• Project is scheduled for completion in 2010.
2. Install a second 138/69-kV transformer at the Chandler Substation (C3), and
• Project is in the design phase, includes providing for a 138-kV ring bus, and is scheduled to be in service in 2012.
3. Install 69-kV bus tie breaker and replace five Delta 69-kV breakers (new in 2010 analyses).
   • Breaker projects will provide greater generator stability during system disturbances, greater operating flexibility and will be in service prior to the year 2012.

Next priorities:

1. Extend the 138-kV system into the major load areas of Escanaba (C5, C6, C8), and
• Provisional projects are moving forward with 2014 in-service dates.
2. Asset Renewal project on the 6910 69-kV line (C-AR4).
   • Provisional project is moving forward with a 2018 in-service date.

Remaining priorities:

1. Construct a new Escanaba D-T Substation (C22, non-ATC), and
• Provisional project is moving forward with a 2014 in-service date pending D-T interconnection request analyses.
2. Add a new 345/138-kV transformation at the Arnold Substation (C21).
   • We are currently considering whether to install the Arnold transformer or an alternative, the Chalk Hills – Chandler 138-kV line project. The answer is dependent on determining generation availability in the area.

Please refer to Zone 2 – 2011 study results and our Asset Renewal section for further details related to the above projects.

Munising/Newberry area core solutions

The list of core projects that ATC and its stakeholders identified in the Munising area is shown in Solution Set B of Figure UP-8C-MN and includes the following:

1. Construct a second Gwinn-Forsyth 69-kV line (C10),
   1. This project is provisional in nature with a tentative 2016 in-service date. Further studies will be conducted in 2010-2011 to determine the scope and in-service date of this project.
2. Close the normally open Seney-Blaney Park 69-kV line and uprate the entire Munising-Seney-Blaney Park 69-kV (Inland) line to 167º F operation (C17),
• This project is provisional in nature and moving forward with a 2014 in-service date.
3. Asset Renewal projects on the Munising138 138-kV line (C-AR1), and
• This project is proposed in nature and is scheduled for a 2012 in-service date.
4. Asset Renewal projects on the AuTrain, Inland, and 6952 69-kV lines (C-AR1, C-AR2, C-AR3).
   • These 69-kV projects are proposed in nature and have projected in-service dates in the 2011-2014 timeframe.

Please refer to Zone 2 – 2011 study results and our Asset Renewal section for further details related to the above projects.

Western area core solutions

ATC intends to implement more detailed project development later this year or early 2011 for the western area. The refined list of core projects that ATC and its stakeholders identified in the Western area is shown in Figure UP-8C-W includes the following:

1. Uprate the M38-Atlantic 69-kV overhead line to 167º F and Minimum Asset Renewal (W13, W-AR1), and
• This project is provisional in nature. The scope is being developed and is moving forward in the 2014 timeframe.
2. Asset Renewal of Conover – Mass 69-kV line 6530 (W-AR2).
   • This project is provisional in nature and is scheduled to be in-service in the 2018 timeframe.

Please refer to Zone 2 – 2011 study results and our Asset Renewal section for further details related to the above projects.

High Retirements Future Enhancement

In 2010, we kicked off the High Retirements #2 Future to respond to stakeholder feedback given during the Collaborative process. As part of this effort, we initiated an update to the previous High Retirements future, working with stakeholders to develop and revise our modeling assumptions to create a new 2024 model. The feedback that our stakeholders identified the following adjustments to our 2024 summer peak model:

• Increase load levels to 1.0 - 1.5% growth per year, and
• Assume very low U.P. generation.
  • Scenario 2A – 350 MW of area generation assumed retired, and
  • Scenario 2B – 500 MW of area generation assumed retired.

Our preliminary analyses indicate that our models will not solve under six critical contingencies in scenarios 2A and 2B. Therefore significant transmission and/or generation upgrades would likely be required to address either scenario. Please refer to the UP Collaborative - HR2 Needs presentation for details.

The results of our preliminary needs analyses under one non-convergent 345-kV contingency are shown in Figure UP-HR1. As shown, if 350 MW of U.P. area generation are assumed retired, the potential for widespread voltage collapse could exist under contingency conditions in the U.P. including the northern portion of Wisconsin.

We recently determined preliminary solutions to the issues identified in scenarios 2A and 2B. To address the potential issues, a series of studies was recently completed to determine the most efficient way to resolve the prospective situation(s), using several strategies:

• New 345-kV transmission lines from Northern Wisconsin into the U.P.,
• New 138-kV transmission lines traversing portions of the U.P. and northern Wisconsin,
• Synchronous condensers at various sites in the area,
• Static VAR Compensators (SVCs) at various sites in the area,
• Generation at various sites in the area, and/or
• Any combination of the above.

Please refer to the UP Collaborative - HR2 Results Summary presentation for the results of our initial screening analyses.

Conclusion

ATC will continue to develop and refine core projects identified as part of the U.P. Energy Collaborative. Results from our High Retirements #2 study may add projects for further consideration.