Responses to Questions Related to the October 10, 2012, Partners in Business Meeting

Transcription

1 Responses to Questions Related to the October 10, 2012, Partners in Business Meeting Question 1: Regarding the update on the ITC-Entergy transaction, what is the expected impact to ITC Midwest rates and allocation of ITC corporate costs resulting from the transaction? Response 1: Expenses associated with the ITC-Entergy transaction will not be charged to ITC Midwest customers so they will not have any impact on ITC Midwest s rates. In addition, ITC has filed in the FERC application associated with the transaction that it will continue to use the Modified Massachusetts Formula for the allocation of A&G expenses. As such, it is expected that ITC Midwest s share of allocable A&G expenses will likely go down as a result of the transaction. ITC also expects its customers, including those within the ITC Midwest footprint, to benefit from ITC s increased scale and sharing of best practices, in particular the expertise that ITC employees coming over from Entergy have in the area of storm restoration. Question 2: What specifically can IPL expect from ITC Midwest as next steps following the results of the most recent Stakeholder Satisfaction Survey? (The general next steps were discussed on pages of the presentation at Planning%20 and %20Attachment%20O%20Presentation%20FINAL% pdf). IPL looks forward to continued work with ITC Midwest to improve the planning and communication of outages, as well as the process efficiency of switching for our customers. Response 2: ITC Midwest s Stakeholder Relations plan is to meet with several field operations and account management personnel at IPL, Rural Electric Cooperatives, Municipals and Independent Power Producers to review past performance and future expectations and collect input for improvements on key survey points: process efficiency, communications, flexibility and accommodating customer needs. The plan is to schedule these meetings within the next two to three months. ITC Midwest then plans to review Stakeholder input internally with ITC Management to evaluate process improvements, communications and points for implementation consideration. This evaluation should take place within 30 days of the conclusion of the Stakeholder meetings. As recommended process improvements are developed, communications will be made with ITC Midwest Stakeholders during face to face or Partners in Business meetings before midyear Question 3: As we requested at the meeting, please elaborate on the details of how the weather event comparison was made for the reliability analysis. (Pages of the presentation.) What types of weather events were included and what portions of Iowa were selected in the analysis? Response 3: Explanations for referenced slides 48 and 49 of the presentation are provided below:

2 Slide 48: The Iowa Storm Events by Zone line graph was created using information from the Storm Events Database found at (National Climatic Data Center, National Oceanic and Atmospheric Administration). The database contains various types of storms recorded from October 2006 to present as entered by NOAA s National Weather Service (NWS). The database allows the user to select a state or area of interest. After selecting the desired state (Iowa), the user can then select the parameters, begin date, end date, event type, county and zone. An event search was conducted for each year, 01/01/yyyy 12/31/yyyy. All events were selected for inclusion but categorized by the NWS Forecast Zone. Please note that Storm Data are geographically categorized by County or by NWS Forecast Zone. Smaller (areal coverage) are collected by county (Tornado, Thunderstorm Winds, Flash Floods and Hail) while larger scale events are collected by forecast zone (Heat, Cold, Drought, Flood, Tropical & Winter Weather). For Slide 48, Zone was selected (versus county) due to the limitations of the database when selecting all events for all counties for an entire year. Query results are limited to 1000 records; making the county records too granular. The shape of the event graph was compared to the Weather: Proportion of Outages line graph. The Weather: Proportion of Outages line graph is compiled based on the percentages of outages coded as weather and submitted to the SGS study. The purpose of the slide was to show that the number of weather events fluctuates from year to year but the percentage of outages attributed to weather is leveling, if not declining. Slide 49 contains the same information as slide 48 but was expanded to include weather events through 9/21/2012. The 2012 percentage of weather related outage projections included in the Weather: Proportion of Outages line graph was hand calculated based on outage information recorded by ITC. The outages included in this graph are the same outages that will be submitted to SGS at the beginning of Question 4. How does the identification and criteria for poor performing circuits (page 51) relate to the identification of projects proposed in the MTEP queue? Response 4: When a line is identified as a poor performing circuit, projects are identified to improve the reliability of the line. This may include additional maintenance, relaying updates or rebuilding the line. If it is decided that the line needs to be rebuilt, an EI Sketch is submitted for internal review with a proposed in-service date. The project is also submitted to MISO, through the MTEP process, for review and approval at that time. The poor performing circuit process is only one of many processes that are in place to identify MTEP projects. There are also regional long- and short-term studies, customer interconnects, generator interconnects, and several other processes that identify projects that are submitted to MISO through the MTEP process. Question 5. As we noted at the meeting, recently, ITC and Entergy submitted a filing to FERC for approval to acquire Entergy s transmission assets. ( In the prepared testimony of Jon Jipping, a summary of an analysis for the ITC companies operating in Michigan was given showing the $ value of improved system reliability

3 measured by SAIDI, and using a tool and database prepared for the US Department of Energy ( Has ITC performed a similar analysis for the ITC Midwest system? If so, what were the results? IPL requests the opportunity to jointly conduct such as analysis cooperatively with ITC Midwest. Response 5: ITC has not conducted a similar analysis for ITC Midwest, because the analysis would not be as meaningful for ITC Midwest due to its system configuration, which is predominantly rural in nature. As Mr. Jipping states in the above referenced testimony: The calculation was made with ITC s Michigan companies in order to allow for a meaningful comparison in this proceeding. ITC Midwest owns and operates transmission at voltage levels of 34.5 kv, 69 kv, 115 kv, 161 kv, and 345 kv. ITC Midwest also has numerous interconnections with electric cooperatives and municipal utilities. Many utilities that participate in the SGS Study own little or no 34.5 kv or 69 kv facilities. Lower voltage systems are inherently less robust than higher voltage systems because the higher voltage systems require higher construction standards, stronger structures (often steel) and larger and heavier wire sizes. When comparing individual voltage levels, the ITCMW 100 kv+ system ranks among the top quartile for overall outages and outage duration in the 2011 SGS Study. However, when lower-voltage facilities are added to the analysis, ITC Midwest ranks in the third quartile for sustained outages. As ITC continues to improve the performance of the lower-voltage system through preventive maintenance and infrastructure improvements, it may become more meaningful to conduct the type of analysis which demonstrates significant and quantifiable reliability benefits for ITC s Michigan customers as a result of ITC s investment and maintenance practices. Question 6. In Jeff Eddy s presentation (pages ), he noted in his verbal remarks that additional system congestion is resulting from increased generation on the western part of the system, line derates from the NERC Alerts (line sag issue), and generation retirements. Please elaborate and quantify these observed congestion metrics and impacts. Response 6: In his verbal remarks, Mr. Eddy was emphasizing the significant challenges to Transmission Planning resulting from changes occurring on the transmission grid. Mr. Eddy s comments were intended to convey a forward looking, big picture assessment of the changing nature of the transmission grid and the challenges these changes present to Transmission Planning. One of these changes results from increased wind generation interconnecting to the grid in western Iowa and southwest Minnesota. In ITC Midwest s first four years of operation, 16 new generator interconnects representing approximately 2,200 MW of wind energy production capacity have been added to ITC Midwest s transmission system. Most of the generation has been connected under MISO Energy Resource service, signifying transmission upgrades necessary to enable the output of those generators to be deliverable as Network Resources have not been added. Several wind farms are connected to the transmission system under Provisional Interconnection Agreements. This type of agreement was developed by MISO to connect generation prior to studies being completed to identify any required transmission upgrades.

4 Another change occurring on the transmission system relates to the retirement or planned retirement of several generating units in eastern Iowa. ITC Midwest has transmission upgrades planned and approved by MISO in eastern Iowa due to these retirements. In addition, MISO studies are in progress to determine transmission upgrades needed for other planned generation retirements. The third change referenced by Mr. Eddy was the derate of several transmission lines as a result of the NERC Alert projects. ITC Midwest is aware that some of these lines have been binding in the Midwest market. ITC Midwest s system has historically been a location of congestion on the transmission system, as evidenced by the SE Minnesota/N Iowa/SW Wisconsin Narrow Constrained Area designation. Question 7. A question was raised at the meeting regarding the details of the SMART GRID Blanket Project - $4.8 million/year listed on page 102. Please explain what this project entails. Response 7: The overall objective of the SmartGrid project is to: Provide a clean separation of assets from an operations perspective between ITCMW and Alliant Energy IP&L. This is a major project driver and is especially necessary where the Supervisory Control and Data Acquisition (SCADA) Remote Terminal Unit (RTU) is a shared asset between ITC Midwest and Alliant Energy- IPL. The separation allows for better management of the specific owned assets from both an operations and maintenance responsibility. This project also allows for the delineation of these shared substations. Separating the assets improves efficiency by eliminating multiple call outs for the same alarm. Set consistent monitored points across ITC Holdings (ITC) operating platform. This portion of the project provides the system operators with consistent monitoring and controls of the field devices since these operators are responsible for operational control across all of the ITC Holdings Company assets. By providing more efficient communications between the control center and field staff, this project should improve response times when addressing operational issues. The project also helps to reduce the number of off-hour callouts based on more consistent prioritization of alarms. Move to a common communications platform from the field-end devices (substations) to the central operations control centers in Novi and Ann Arbor Michigan. Enhance engineering remote access support. This portion of the project supports system reliability and outage response by providing relay engineers with a more direct access path to protective relays for operations analysis. This more direct dial-up access allows the engineer to identify fault location information quicker, thus aiding the field staff in responding to and restoring unplanned outages. Question 8a. Regarding the 2013 Attachment O rate discussion beginning on page 105 of the presentation, please explain further the following: For the timeline shown on page 110 of the presentation, IPL raised a question regarding the nature MISO review and ITC Midwest response to the proposed Attachment O rate. It was in

5 part answered by ITC Midwest indicating the questions raised by MISO involved a >20% increase in gross plant in service and a property tax change threshold in ITC Midwest s submitted Attachment O rate for Please elaborate on these questions raised by MISO and ITC Midwest s response to MISO. Response to 8a: Following is an exact quote of the questions raised by MISO during its review of Attachment O projected rates for 2013 and ITC s responses: 1) Attachment O, Page 2, Line 2 - Amount is 22% higher than the 2012 Projection ($1,749,173,000 vs. $1,432,119,000). Please provide a high level summary of the drivers for this material increase. ITC Midwest Response: Transmission Gross Plant In-Service represents a cumulative balance that increases as additions are made to gross plant in-service each year. The 2012 Projected balance reflected a 13-month average balance for The 2013 Projected balance is higher as a result of a full year weighting in the 13-month average for the 2012 balances as well as the 2013 projected additions to gross plant in-service. On the last page of this response we have shown a list of projected capital project additions, from the ITCMW 2013 Partners in Business presentation on the Projected 2013 Projected Attachment O rate, showing that the new projected total is more than the increase in the 13 month gross plant balance. Please be advised that the most accurate information on planned capital project additions is found in the MISO MTEP database. 2) Attachment O, Page 2, Line 10 - Amount is 29% higher than the 2012 Projection ($52,541,000 vs. $39,663,000). Please provide a high level summary of the drivers for this material increase. ITC Midwest Response: General and Intangible Accumulated Depreciation represents a cumulative balance that increases as depreciation expense is incurred each year. The 2012 Projected balance reflected a 13-month average balance for The 2013 Projected balance is higher as a result of a full year weighting in the 13-month average for the 2012 balances as well as the 2013 projected depreciation expense. 3) Attachment O, Page 3, Line 16 - Amount is 29% higher than the 2012 Projection ($9,550,000 vs. $7,425,000). Please provide a high level summary of the drivers for this material increase. ITC Midwest Response: Property Taxes represent the annual projected expense associated with the gross plant in-service balance of the prior year. The 2013 projected amount is higher because it reflects plant additions through 2012 whereas the 2012 projected amount only reflected plant additions through Questions 8b. Regarding the 2013 Attachment O rate discussion beginning on page 105 of the presentation, please explain further the following: b. IPL notes some apparent inconsistencies in some projects costs when viewed on a $/line mile basis. For example:

6 i. The Heron Lake to Lakefield 161 kv Rebuild project on page 115 shows an in-service cost of approximately $24.7 million. We understand this project to be an approximately 17 mile line rebuild on existing right of way, implying a cost of approximately $1.4 million/mile. ii. The Marshalltown Nuthatch rebuild project on page 115 shows an in-service cost of approximately $31.8 million. We understand this project to be approximately 50 miles of 115kV being rebuilt to 161kV on existing right of way, implying a cost of approximately $636 k/mile. These two projects appear similar enough to compare directly to each other, however, the costs/mile are quite different. Please explain. Response 8b: The projected completed cost of the Marshalltown Nuthatch Project is approximately $52MM or approximately $1MM per mile. The cost estimates shown on page 115 are the calculated amounts that are forecasted to be placed in-service in 2013 only. These numbers do not include in-service amounts from prior years, because those amounts have already gone into service and been added to ratebase in their respective years. For the Marshalltown to Nuthatch Project, $21MM was placed in-service in June The $21MM already in service plus the forecasted $31MM for 2013 totals the $52MM. The Heron Lake Project is projected to go into service in 2013 for $24MM, or approximately $1.4MM per mile. The Heron Lake Lakefield estimated cost is slightly higher because a section of the line must be relocated out of a wetland, requiring a portion of double circuit 161/69 KV. Also, the line is expected to be built in the winter due to line load issues in the summer. Winter construction is more expensive. Question 9. Considering the favorable construction season during 2012, what was ITC Midwest s projected in-service capital previously expected to be for 2012, what is the current projection, and what is the expected impact on any true-up to rates impacting 2014? Response 9: ITC Midwest s projected in-service capital for 2012, reflected in the September 2011 posting, was $248.5MM. The current projected in-service capital for 2012 is expected to be $258.7MM, which is $10.2MM, or 4%, higher than the initial projection. The impact of this projected increase to the current year true-up is de minimus. The $10.2MM increase in inservice capital equates to an increase in the 13-month average rate base of $0.8MM. The total return on this amount, including the tax-gross up, is projected to be approximately $0.1MM. Question 10. Previously, ITC has indicated that capital spend levels in the Michigan operating companies have flattened as system improvements have been made, reaching what might be referred to as maintenance capital levels. When might customers of ITC Midwest expect to see comparable levels of maintenance capital levels be experienced, and what level of spend might that be? What is the expected impact to ITC Midwest rates? Response 10: ITC has no updates to its long-term financial plan since the February 22, 2012, disclosure. As such, projections of capital spend and gross revenue requirements beyond

7 2016 are not available. In addition, ITC Midwest does not forecast Attachment O rates and, as such, cannot provide the expected impact to ITC Midwest rates as requested. From a capital planning perspective, ITC Midwest is on track to meet its commitment to rebuild the 34.5 kv system to 69 kv standards by December 2019 (twelve years from the Transaction closing in December 2007). ITC Midwest s expectation is that capital will be committed to these projects in each of the years 2013 through Information on additional capital commitments during the 2017 through 2019 timeframe will depend on many factors that cannot be projected at this time such as national energy policy, weather, technological advances, customer interconnects, generator interconnects, etc. Question 11. When might we expect to see an updated revenue requirement and capital forecast for the ITC operating companies from what was made available with the February 22, 2012 ITC Holdings Year-End 2011 Investor Call? Response 11: ITC provides updated gross revenue requirement and capital forecasts for its operating companies in conjunction with any public disclosures of updates to our long-term financial plan. There have been no updates to our long-term financial plan since the February 22, 2012 disclosure. At this time, we do not have any formal plans to update our long-term financial plan publicly.