iThe load flow models built for the 10-Year Assessment are specially built models used exclusively for the Assessment. Projects are purposely left out of these models in order to verify system problems exist and which ones get worse over time. After the 10-Year Assessment analysis is completed, models are built that include all planned, proposed, and some provisional projects. These new models are called “All Projects” models and are more indicative of the expected system configurations for 2009, 2013 and 2018 study years. These models are more appropriate for internal planning studies performed throughout the year. As part of the 10-Year Assessment, the zone planners perform a contingency analysis on each of the “All Projects” models. The contingency analysis includes systematically removing each line, generator, transformer, and modeled bus ties individually to determine the affect on the transmission system. The analysis will verify whether all of the planned, proposed, and provisional projects will resolve issues revealed in the Assessment process.     

The zone analysis discussions presented in this Assessment provides a list of reinforcements that are beginning to optimize our reinforcement plans, at least at the one- or maybe two-zone level. Three important questions regarding this plan include the following:

• How do the reinforcements for all the zones perform together?
• Does applying a solution in one zone create a problem that was not seen before in another zone?
• Are some zone solutions redundant when all the solutions are applied to the system?

As we did in the 2006 Assessment, this year we have tried to address the first two questions. We have built year 2013 and year 2018 models that include reinforcements reflecting our best thoughts on all of the most likely planned, proposed, and provisional projects to deal with the identified issues. These projects are those identified in the project tables for this Assessment with specific in-service dates. First contingency analysis was performed on these two new models, including selected outages on neighboring systems. This analysis showed that the reinforcements in total did indeed deal with the issues identified and did not create any new issues to be resolved. Some details for each zone are summarized below.

Zone 1

In the 2009, 2013 and 2018 summer peak “All Projects” models, most of the system overloads or low voltages in Zone 1 are addressed although a few issues still exist under single contingency conditions in our 2013 and 2018 models. The system issues remaining in the 2013 and 2018 “All Projects” models are:

• The Petenwell transformer is overloaded in the 2013 model under system intact conditions.  The transformer is not overloaded in the 2018 All Projects model.
• The issue can be addressed by redispatching the Big Pond generator.
• The Castle Rock – Mckenna 69-kV circuit is overloaded in the 2013 model for the various 69-kV line outages.
• The issue can be addressed by redispatching the Castle Rock generator.
• The system intact voltage for the Council Creek 161-kV bus is nearing the low voltage threshold in the 2013 and 2018 models.
• Voltage can be improved by including the two Xcel Energy proposed capacitor bank projects at Monroe County and La Crosse Substations.
• Low voltages exist at the Sigel and Lakehead Vesper substations for the Arpin–Sigel 138-kV circuit outage in the 2018 model.
• Voltages can be substantially improved by including the recently announced load reductions in the Wisconsin Rapids area.

Zone 2

With all projects in the 2009, 2013 and 2018 summer peak models, most of the system overloads and low voltages in Zone 2 are addressed, although system problems still exist under single contingency conditions in all three study years. The system issues remaining in the 2009, 2013 and 2018 all project models are:

• Low voltages at the Engadine, Newberry, and Roberts 69-kV buses are observed for various 69-kV line outages
• These violations can be mitigated by running the Newberry Village and Dafter diesel generators.

Zone 3

With all projects in the 2009, 2013 and 2018 summer peak models, most of the system overloads and low voltages in Zone 3 are addressed, although several system problems still exist under single contingency conditions in 2009, 2013 and 2018. The system issues remaining in the 2009, 2013 and 2018 all project models are:

• The Verona-Oregon 69-kV line overloads and low voltages for the loss of Stoughton-Aaker Road 69-kV line. (2009)
• Load bridging capability between Stoughton and Aaker Road substations can address this overload. The transmission solution for this problem is to rebuild the Verona-Oregon 69-kV line in 2011.
• The McCue-Lamar 69-kV line overloads for the loss of Kegonsa-North Stoughton 69-kV line or Kegonsa 138/69-kV transformer; the North Stoughton-Stoughton 69-kV line overloads and  low voltages on Y61 McCue-Lamar line for the loss any section of the McCue-Harmony-Lamar-Fulton 69-kV line (2009)
• These violations will be addressed by uprating the McCue-Lamar 69-kV line, rebuilding the Stoughton bus and installing 2-12.45 Mvar capacitor banks at Lamar in 2009.
• Low bus voltage issues under both system intact and single contingency conditions near Jefferson area (2009)
• A 2011 provisional project is created to install 4-49 Mvar 138-kV capacitor banks at Concord substation to address these voltage problems. Before this provisional project gets developed, the interim mitigation measure is to run Concord generation. 
• Low 69-kV voltages on the Bass Creek-Brodhead 69-kV line for the loss of Brodhead-Brodhead South line (2009).
• The long term plan to support the voltage in this area is to install a 138/69-kV transformer at Bass Creek substation in 2013. In the near term, a 2009 distribution cap bank project is developed at the new Union Townline substation and the existing Sheepskin cap bank will also be upgraded.
• The Academy-Columbus 69-kV line overloads for the loss of North Randolph-Fox Lake 138-kV line. (2013)
• Possible operating procedure to avoid this overload is dispatching South Fond du Lac generation. It is still under investigation. The proxy transmission solution for this problem is to construct a Horicon-East Beaver Dam 138-kV line in 2014.
• Dane County intact system voltage violations. (2013)
• Possible operating procedure is to adjust local 138/69-kV transformer LTC tap setting. It is still under investigation. The proxy transmission solution for this problem is to install 2-16.33 MVAR 69-kV capacitor banks and 2-24.5 MVAR 138-kV capacitor banks at Femrite substation in 2014.
• Low 138-kV voltages at Hubbard and Hustisford for the loss of Rubicon-Hustisford. (2013)
• Possible operating procedure is adjusting the 138/69-kV Hubbard transformer LTC tap setting to boost the 138-kV bus voltage. The proxy transmission solution for this problem is to construct a Horicon-East Beaver Dam 138-kV line in 2014.
• The Rio-Pardeeville Tap 69-kV line overloads under single contingency condition. (2013 and 2018)
• The overload is based on a 42 MVA summer emergency in the planning model which should be increased to 69 MVA to match the SELD rating and current EMS rating. The line is not overloaded based on the 69 MVA rating.
• The Shaw-Shirland 69-kV line overloads under single contingency conditions.( 2018)
• The overload is based on an 84 MVA summer emergency in the planning model which will be increased to 100 MVA based on the new ATC jumper rating criteria. The line is not overloaded based on the 100 MVA rating.

Zone 4

In the 2009, 2013 and 2018 summer peak “All Projects” models, most of the system overloads or low voltages in Zone 4 are addressed although a few issues still exist under single contingency conditions in our models. Currently, those issues are under further investigation which includes validating line ratings as well as communicating with our customers to confirm the local area load and to determine the Best Value Plan (BVP) in each situation. The system issues remaining in the 2009, 2013 and 2018 “All Projects” models are:

• Low voltages near Bluestone and Wesmark 69-kV Substations (2009, 2013, and 2018) and Finger Road-Bluestone 69-kV line overload (2018) under single contingency conditions.
• This is primarily due to the temporary load interconnection at the Bluestone 69-kV Substation requested by customer. A detailed study needs to be performed by the customer and ATC to determine a Best Value Plan which will accommodate the new load interconnection while minimizing other concerns such as system impact, construction costs, and public and environmental impact. Constructing a new 138-kV substation along the Highway V-East Krok 138-kV line in the 2011 timeframe is being considered as one of the alternatives. Installing an additional distribution transformer at the existing Mystery Hills 138-kV Substation is also being considered. Until a permanent solution is in place, the existing Bluestone 69-kV Substation will serve the load under normal operating conditions.
• The City Limits-Combined Locks Tap 138-kV line overloads under single contingency conditions in 2018.
• The ratings of the trap at the City Limits 138-kV Substation facing toward Combined Tap are currently under investigation by the ATC SELD group.

Zone 5

A contingency analysis was performed on the 2009, 2013, and 2018 “All Projects” models. With all of the planned, proposed, and some provisional projects modeled, no new Zone 5 facility overloads or voltage problems occurred.  Low bus voltage issues persist in Waukesha and Washington Counties.  The expected addition of capacitors at Summit, Mukwonago, and Bluemound substation is improving the situation.  Running generation at Concord and Germantown rectifies the situation.  Further system improvements are still needed and under investigation.  

Conclusion

We recognize that we need to continue to develop our reinforcement optimization processes. The analyses described are not the only methods we use to optimize our plans and do not begin to address the third question. Also, access-driven reinforcements, (with the exception of the second Paddock-Rockdale 345-kV line) were not included in this analysis as we await more definition of the most likely projects. However, our project development process, including development of the access projects, does look to optimize the projects that are finally built.