SPP - SOUTH SUB-REGION

Transcription

1 Southwest Power Pool October 2014 SPP RESPONSES TO SUB-REGIONAL NET TELECONFERENCES AND RMS REQUESTS Following the Engineering Planning Summit on October 8, 2014, SPP staff held four (4) separate sub-regional net conferences for the South, Integrated Systems (IS), Nebraska and Kansas/Missouri regions to provide an open forum for stakeholder question and feedback related to the 2015 ITP10 study and preliminary consolidated portfolio. Action items were captured and SPP staff performed follow-up review and analysis incorporating the feedback received, and responses are provided below. In addition, SPP staff advised that questions and comments could be submitted through the SPP Request Management System (RMS), and requested that all feedback be submitted by Tuesday, October 14, 2014, to avoid causing risk to the 2015 ITP10 project schedule. The RMS responses are also provided below. SPP - SOUTH SUB-REGION Action Item 1: SPP staff to follow-up and review generation at Wilkes related to GOF and if additional transformer still required for similar GOF candidates and review methodology. SPP Response: Wilkes is now considered as a GOF. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. Action Item 2: SPP staff to review the Lone Oak-Broken Bow 138kV line project and related results to verify if additional project is needed. SPP Response: Staff reviewed this and agrees that the segment from Broken Bow Bethel should be included in the Consolidated Portfolio. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. Action Item 3: SPP staff to review the Elk City substation voltage needs for possible project need related to moving the 69kv load to 138kv section. SPP Response: Staff reviewed the work associated with this submission. In a submission package of this project a model correction was provided. However, staff did estimate a cost for the work and evaluated it as a project for the 2015 ITP10. Based on the needs the upgrade solved and its estimated cost, it was not selected as a project in any of the groupings. Action Item 4: SPP staff to add a column to include the conceptual cost estimate amount for each of the final projects in the preliminary consolidated portfolio, post an updated version of the project list, and send out notice. SPP Response: SPP staff included the conceptual cost amounts for the preliminary consolidated portfolio. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting.

2 Action Item 5: SPP staff to review Beaver County-East Liberal 345 line project(s) to confirm mileage and reevaluate cost calculation and possible change in project portfolio, if needed. (Note: ITC staff provided it was approximately 39 miles.) SPP Response: SPP staff replaced the Beaver County East Liberal 345kV line with the following project: Tap Hitchland to Finney 345kV line at NewSub1; add a new 345/115kV transformer at NewSub; add a new NewSub substation, and a new NewSub2 substation to Walkemeyer to West Liberal 115kV line. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. Action Item 6: SPP staff to follow-up with Legal and Regulatory departments to see if posting of all projects submitted by need can be publicly posted. SPP Response: Projects have been posted with their associated needs on SPP.org in the October Summit Meeting Materials. Document title is ITP10 Project List v3.xlsx. Action Item 7: SPP staff to add in-service dates for project listing once determined. SPP Response: Pursuant to the 2015 ITP10 project schedule, project in-service dates will be determined in November Action Item 8: For maps, SPP Staff to make identification corrections (i.e., China Draw), and to number all projects on map to identify against project listing. SPP Response: Map corrections are in progress and will be posted on Thursday, 10/23/14. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. SPP - IS SUB-REGION Action Item 9: SPP staff to confirm IS DC tie information utilized and what analysis was performed. SPP Response: In PROMOD, the Stegall DC Tie follows an hourly profile, which is based on a three (3) year historical average for each hour of the year. Based on the hourly profile, Stegall will have hours where it is a purchase (import) and others a sale (export). These hourly imports and exports are capped at long-term firm transmission service levels in either direction. SPP staff did not have historical data for Rapid City or Mile City to develop an hourly profile. With that, Rapid City tie was modeled as a fixed purchase and Mile City as a fixed sale for all hours based on the 2013 Series MRO power flow 2024 Summer Peak model. Action Item 10: SPP staff to receive and review any updated information from WAPA/IS and review possible impacts to preliminary consolidated portfolio. SPP Response: SPP staff received and reviewed updated information from WAPA/IS for impacts to the preliminary consolidated portfolio, and based upon further review, have removed most IS projects based 2 P a g e

3 on the new information. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. Action Item 11: SPP staff to provide additional information related to reconductors and rebuilds. SPP Response: SPP staff has updated the project description for those in the consolidated portfolio to provide the required rating on the reconductor/rebuild projects. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. SPP NEBRASKA SUB-REGION Action Item 12: SPP staff to follow-up with NPPD on any possible regular rebuild that might be required as part of routine maintenance and to re-check what the amperage increase. SPP staff will consider posting the information stating at which phase in the process projects dropped out (pending Legal/Regulatory review). SPP Response: SPP staff is still reviewing. Action Item 13: SPP staff to review and further analyze projects in the Omaha area based on OPPD s comments. SPP Response: The additional transformer at Sarpy was addressed and moved to S3459. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. Action Item 14: SPP staff to review any existing 69kV needs that could be addressed with 100kV and greater solutions. SPP Response: SPP staff is still reviewing. SPP KANSAS / MISSOURI SUB-REGIONS Action Item 15: SPP staff to verify capacitors (2) in west central Kansas and whether or not included in the consolidated portfolio. SPP Response: Capacitor banks at Russell and Waldo are needed in Future 1 only and are not in the consolidated portfolio. Action Item 16: SPP staff to re-evaluate the Beaver Co. to East Liberal project based on updated mileage and resulting increased cost estimate (action item is also captured in the SPP South sub-regional net conference). SPP Response: See response to Action Item 5 above and updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. 3 P a g e

4 SPP RESPONSES TO RMS REQUESTS RMS Request (Submitter: Quanta) - Iatan-Stranger Switched Reactor DPP A DPP was submitted for a switched reactor in the Iatan-Stranger line. It is recognized that this solution will not address an overload of the NEAST 5 - CHARLOT5 161kV line. However, this line and its continuation to CROSTWN5 is 2.9 miles long and rated ~930A. Although not linked in the Iatan-Stranger DPP it was assumed that a separate, non-competitive, project to reconductor the NEAST 5-CHARLOT5-CROSTWN5 would be a low cost solution to address the outage of the Iatan-Stranger outage thus making the switched reactor (in concert with the reconductoring project) a low cost solution to two binding constraints. That said, how did SPP model the switched reactor solution in the PROMOD event file? The reactor would only be switched into the circuit when the flowgate contingency (or in operation any system condition) caused the Iatan-Stranger line to overload. Although a conventional relaying scheme this would look like an operating guide to PROMOD which cannot model condition based switching events. Therefore, can SPP effectively evaluate this innovative solution using its standard tools and processes? SPP Response: SPP Staff consulted with Ventyx and the PROMOD software cannot evaluate switched reactors. SPP Staff initially studied this project as a fixed reactor. SPP modified the evaluation with the following process: 1. Identified binding hours in the base model. 2. Created transmission outages of the bypass circuit corresponding to the binding hours. 3. Included identified outage hours in all simulations that included the Iatan reactor. Following SPP's modified evaluation, the switched reactor in the Iatan-Stranger project was still not included in the preliminary consolidated portfolio. RMS Request (Submitter: OPPD) - OPPD Comments on Omaha Metro 345/161kV Autotransformer Location The 2015 SPP ITP10 consolidated portfolio of projects included a project to add a 2nd 345/161kV autotransformer in the Omaha, NE metro area at OPPD s Sarpy County Substation (S3456/S1206/S906). OPPD agrees with the general plan to add another 345/161kV autotransformer in the Omaha metro to mitigate the ITP10 reliability and economic needs for the OPPD area, however, OPPD disagrees with the SPP recommended location of that new 345/161kV autotransformer. OPPD performed a comprehensive 345/161kV autotransformer addition analysis for the Omaha metro area to address the SPP 2015 ITP10 needs for the OPPD area. The analysis has been attached in the following file: PUBLIC_OPPD Comments on SPP 2015 ITP10 Project List.pdf. Per the attached document, OPPD recommends that the new Omaha metro area 345/161kV autotransformer addition be placed at OPPD substation S3452/S1262 in Northwest Omaha. SPP Response: See Action Item 13 above. Attachment is included in the meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. 4 P a g e

5 RMS Request (Submitter: OPPD) - Unaddressed OPPD Needs in 2015ITP10 Project List The 2015ITP10 Needs List contained numerous network 69kV needs for the OPPD area but no projects were included in the approved project list for the ITP10 study. A new >100kV project to add a 161kV substation and 161/69kV autotransformer (S1262 Auto, RMS Request# DPP-2015ITP ) to the OPPD system was submitted as a fix for the 69kV Future 1 Reliability needs listed below. Per the 2015ITP10 Scope, The 2015 ITP 10-Year Assessment (ITP10) is a value-based planning approach that will analyze the 10-year out Transmission System and identify 100 kv and above solutions to needs stemming from multiple sources: (a) needs identified in the reliability analysis of the 69 kv and above system, (b). Given this information, why was this project omitted from the approved 2015ITP10 project list when it corrected 18 needs in Future 1 alone? 2015 ITP10 24SP_F1 Needs Addressed 2015ITP10-RON ITP10-RON ITP10-RON ITP10-RON ITP10- RON ITP10-RON ITP10-RON ITP10-RON ITP10-RON ITP10-RON ITP10-RON ITP10-RON ITP10-RVN ITP10- RVN ITP10-RVN ITP10-RVN ITP10-RVN ITP10-RVN ITP10 24SP_F2 Needs Addressed 2015ITP10-RON ITP10-RON ITP10-RON ITP10-RON ITP10- RON ITP10-RON ITP10-RON ITP10-RVN ITP10-RVN ITP10-RVN ITP10-RVN ITP10-RVN ITP10-RVN0814. SPP Response: SPP staff is still reviewing. RMS Request (Submitter: Quanta) - Iatan-Stranger Switched Reactor DPP Issue: Modeling of switchable reactor to control line loading. Proposed methodology: Make two PROMOD runs 1) without the switched reactor impedance and 2) with the reactor in the line. For those hours in step 1 in which the line with the reactor shorted is binding check those hours in step 2 with the reactor in the circuit. Evaluate the congestion charges in step 2 for the hours in step 1 in which the target line was binding. Replace the congestion charges in step 1 for those hours in which the congestion in step 2 is smaller. This would determine if the reactor addressed the congestion when the line was binding and evaluate whether the switched reactor created any new congestion. This requires post processing but without this additional work a new and innovative approach will not be evaluated to determine its value. SPP Response: See Response to RMS Request above. 5 P a g e

6 RMS Request (Submitter: Westar) ITP10 - Reno County kV Transformer Westar Energy would like to provide additional information for the Reno County kV transformer project that is being evaluated for the 2015 ITP10 Consolidated Portfolio for the following needs: RON1315, RON1474, RON1475. The Reno County substation (see aerial view attached) has 115kV lines along the south side of the sub. To be able to install a third transformer, the south side of the substation will need to be expanded and the existing lines will need to be relocated. The cost of relocating these lines, purchasing additional land, and expanding the sub should be considered in the cost estimate as additional costs. Westar Energy would advise an alternative location for this to be a Moundridge kV transformer. The Moundridge substation (see aerial view attached) is being rebuilt at the moment and Westar Energy has purchased land for potential future expansion. There is already space and no lines will need to be relocated to install the transformer, bus, and terminals. SPP Response: A transformer at Moundridge was added to replace the one selected at Reno. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. RMS Request (Submitter: ITC) - Beaver Co to E. Liberal - ITC Comments Thank you for the opportunity to provide feedback on the projects selected for the 2015 ITP10 consolidated portfolio. ITC would like to comment specifically on the choice of the following project: New Beaver County-East Liberal 345 kv, new 345/115 kv transformer at East Liberal, new East Liberal station It became apparent on the KS/MO sub-regional review call last Friday that SPP underestimated the line length of the subject project and subsequently the project cost. For this reason and others that we will enumerate in this comment, ITC urges SPP to reconsider the inclusion of the Beaver County to East Liberal 345 kv project in the 2015 ITP10 portfolio. Supporting rationale is supplied for the following points: 1. Other, more cost-effective projects available 2. Analysis of needs 3. Constructability considerations 4. Routing considerations Other Cost-Effective Projects Available For SPP s consideration, ITC has copied two projects from SPP s final project list for consideration in lieu of the Beaver County to East Liberal project. Tap Hitchland-Finney 345 kv line at NewSub, new NewSub station, new 345/115 kv transformer at Cimarron, new NewSub-Cimarron 345 kv line Tap Hitchland-Finney 345 kv line at NewSub, new NewSub station, new 345/115 kv transformer at North Liberal, new NewSub-North Liberal 345 kv line 6 P a g e

7 This list is not intended to be comprehensive but is illustrative. Both of the above projects have substantially similar elements from a planning perspective and are substantially similar to the Beaver County to East Liberal project. All three projects involve a new 345 kv switching station to attach to a 345 kv line, a new 345 kv line segment, a new 345/115 kv transformer, and a tie to existing 115 kv facilities. The primary cost difference between the three projects, using SPP s methodology, is line length (There are other considerations as well which will be described later). To illustrate the line-length differential, ITC estimated straight-line distance for each project, using Velocity Suites, from the vicinity of the logical interconnection points with the relevant existing 345 kv lines yielding the following results: 1. Beaver Co E. Liberal, 36 miles from a tap of the Hitchland to Woodward line straight south of Liberal 2. New Sub N. Liberal, 19.5 miles from a tap of the Hitchland to Finney line in the vicinity of the Walkemeyer 115 kv substation (note that right angle distance of this project configuration would be roughly 23.3 miles) 3. New Sub Cimarron River, 28.4 miles from a tap of the Hitchland to Finney line in the vicinity of the Walkemeyer 115 kv substation This clearly illustrates the difference in potential line length for these three projects. Using straight-line distance as the only cost determining factor, project 2 would be approximately $21.5 million (in 2013 dollars) less costly than Beaver Co. to E. Liberal while project 3 would be approximately $9.9 million less costly. Analysis of Needs ITC also checked the performance of the New Sub N. Liberal project against the list of needs addressed by Beaver Co. E. Liberal. Load flow simulations were performed for all of the needs listed. The New Sub N. Liberal project solved each of the needs (see Attachment 1 for more details). See the attached Excel file for results. Also, Table 1 below illustrates the comparison for a selected subset of needs: NEED ID# Table 1 Comparison of Performance Against Needs %LOAD/Volt CONT %LOAD/Volt CONT after Project %LOAD/Volt CONT after Beaver Co to E. Liberal Thermal /Voltage 2015ITP10-RON1087 (future 1) Thermal 2015ITP10-RON0498 (future 1) Thermal 2015ITP10-RVN0553 (future 1) Voltage 2015ITP10-RVN1182 (future 1) Voltage 2015ITP10-RON1084 (future 2) Thermal 2015ITP10-RVN0554 (future 2) Voltage 7 P a g e

8 Constructability Considerations MKEC owns all of the 115 kv facilities that are the subject of this discussion. According to MKEC planning personnel, the East Liberal substation is not a good location for facility additions because of space considerations and the age of the existing facility, dating to a 1965 rebuild from which original equipment remains. Any construction in the existing bus at East Liberal is likely to require extensive re-work of the substation which will add substantial additional cost to the project. The presence of a capacitor bank at E. Liberal was noted on Friday s KS/MO sub-regional review call. It was suggested that this cap bank could be removed in order to minimize re-work in the bus. According to MKEC, this is not feasible due to potential system voltage recovery issues when the new line or transformer may be out for maintenance. The North Liberal substation, by contrast, is a fairly new substation and has ample room for expansion in the immediate vicinity, although limited room exists for expansion with the fenced area. Routing Considerations The corridor from the proposed New Sub on the Hitchland to Finney 345 kv line to both North Liberal and to Cimarron River contains an existing 115 kv line. This provides an already fragmented, logical route for a new transmission line. The Beaver Co. to E. Liberal project does not have this advantage. SPP Response: See response to Action Item 5 above and updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. RMS Request (Submitter: Quanta) - How to model switched reactors in PROMOD event file How to Model a Switched Series Reactor in PROMOD Event File After thinking about this some more I would recommend the following approach to model a conditionally switched series reactor in the monitored element of a contingency limit pair modeled as a flowgate in the PROMOD event file. In the power flow model the switched reactor would be modeled as a series impedance between two nodes/buses inserted into the monitored element. The switched reactor branch would be modeled with a zero impedance branch, circuit 2, in parallel with the switched reactance. The reactor would be switched into the circuit by opening the parallel zero impedance branch. Modify the power flow base case so as to drive the loading of the uncompensated monitored branch up to its emergency (RATEB) rating. Open the reactor bypass and calculate the change in MW flow caused by the reactor switching. Calculate a flowgate rating equal to the power flow RATEB plus the change in MW loading resulting from placing the series reactance into the circuit. Modify the PROMOD event file to utilize this modified rating for the flowgate containing the monitored element with the proposed switched series reactor. PROMOD uses a flowgate approach. The flowgate methodology only considers the impact of the contingent outage on the monitored element. PROMOD limits the pre-contingent flows so as to avoid post-contingent 8 P a g e

9 overloads.therefore it would be inconsistent to include the impact of the initial outage plus the change in flows due to switching the reactor. If power flow analysis indicates that the contingent outage plus switching the reactor results in an overload then we would need to define an additional flowgate for which the contingency was defined as the original outage event plus the outage (opening) of the bypass breaker and the potential overloaded branch would be monitored. Any flowgates for which the monitored branch with the switched reactor is the contingency would thus not be affected. The non-contingent loading of the monitored branch would be limited by its normal (RATEA) rating. The LODF for the outage of this branch with the reactor bypassed would not change. SPP Response: See Response to RMS Request above. RMS Request (Submitter: Transource Energy, LLC) - Transource comments for ITP The 2014 SPP STEP transmission map (created in April, 2014) incorrectly shows the future Hitchland Woodward 345kV double-circuit crossing the existing Beaver Co. 115kV substation. The incorrect line mileage associated with the Beaver Co. East Liberal 345kV project was based on the line route shown on the STEP map. Please correct this line in future maps. SPP Response: Map has been corrected and will be posted with the meeting materials for the October 29, 2014 TWG/ESWG Joint Meeting. Please provide the coordinates for the correct location of the new Beaver Co. 345kV substation. SPP Response: SPP cannot provide GIS information as it is considered CEII data. Please provide the location of any known feeds into the new Beaver Co. 345kV substation (other than the Hitchland and Woodward lines) including the location of any generation collection stations that terminate at the Beaver Co. 345kV substation. SPP Response: According to the posted ITP10 models, Beaver Co. 345kV substation is located 28 miles from the Hitchland 345kV substation on the Hitchland Woodward 345kV line and serves as the interconnection point for two (2) wind farms added as a part of the renewable resource plan, the Texas #6 wind farm assigned to Southwestern Public Service (SPS) and the Oklahoma #10 wind farm assigned to American Electric Power West (AEPW). Please provide the updated cost estimate for the Beaver Co. East Liberal 345kV project. o SPP Staff stated on the Friday (Kansas region) conference call that the Beaver Co. East Liberal 345kV project cost would increase from $69M to $90M - $100M. What is the basis for the $21M - $31M increase other than the additional 9 miles (from 27 to 36) associated with the correction of the new Beaver Co. 345kV substation location? Please provide a breakdown of the revised cost estimate. o There are several options related to expansion of the existing East Liberal 115kV Substation: Relocate the existing breaker on east end of the station (move in-line with two existing south breakers) and expand station to the east by adding one additional terminal; or cut-in one or both of the existing 115kV lines that terminate at the East Liberal 115kV substation from the northeast (Cimarron Tap) 9 P a g e

10 and the south (Texas County) to the proposed new East Liberal 345/115kV station. These options should not add significant incremental cost to the project (less than 5%) and would be well within the cost estimate bandwidth. Power flow analysis indicates that the proposed Beaver Co. East Liberal 345kV project would not create any loop flow issues on the underlying 115kV system. The Beaver Co. East Liberal 345kV project provides additional flexibility for future expansion that a westeast solution (tapping Finney-Hitchland 345kV) will not provide. By continuing from Liberal to the north (Buckner), a new Beaver Co. East Liberal 345kV line will provide the first leg of a new north-south 345kV path that would parallel the existing Finney Hitchland 345kV line. With the proposed economic upgrades in southern Nebraska and the Mingo area, an additional north-south 345kV path would allow additional north-south power flow during contingency conditions (particularly outage of the Finney-Hitchland 345kV line). A new Buckner-Beaver Co. 345kV line would also provide an additional source to the Dodge City area and allow the connection of existing and future wind farms in the area to mitigate current and potential future congestion issues. SPP Response: SPP staff re-evaluated the project using additional mileage and information provided that significant substation expansion would be necessary for this project. The revised cost estimate used to evaluate this project was developed using the same methodology as all other projects. See response to Action Item 5. Several generation interconnection (GI) studies incorporate the construction of a new Buckner Beaver Co. 345kV line. It may be possible to resolve a number of needs (generation interconnect, reliability, economic) by constructing a new Beaver Co. East Liberal Buckner 345kV line. Does SPP review the GI queue when selecting projects? If so, where can this data be found? SPP Response: The ITP process includes a process for reviewing future generation plans independent of the GI queue. However, if new transmission is approved through the GI or ATSS processes with signed agreements, staff will take that information into account. Did SPP consider the impacts of any new reliability issues that may be created through the implementation of a proposed project? How were the additional costs for mitigation of these new reliability violations treated in the project evaluation? SPP Response: SPP has not run any analysis to determine additional problems that may be caused by the implementation of an individual project. Once the final portfolio has been approved, staff will conduct a final reliability assessment to determine if any new reliability issues are created. Please provide the cost estimate for the Bush Tap Hastings 115kV line. SPP Response: See Action Item 4. As discussed on the Friday (Oklahoma) region conference call, the need for an additional 345/138kV autotransformer at Wilkes appears to be driven by the additional generation added from the resource plan. Would the facilities needed to support this new generation not be a part of the proxy GI facilities instead of showing up as a need in the ITP10? In any event, the need for the new Wilkes autotransformer could likely be displaced if the new generation were split between the 345kV and 138kV busses instead of all the new generation being added at 345kV. 10 P a g e

11 SPP Response: Staff plans to recommend the removal of the 3rd transformer at Wilkes as a project for the 2015 ITP10 and will classify that upgrade as needed for Generator Outlet. As discussed on the Friday (Oklahoma region) conference call, there is an identified need at Elk City due to low voltage; however the selected project was mislabeled as a model correction. The project actually requires a 138 kv breaker and a kv transformer (as shown in the DPP). SPP Response: See Action Item 3. As discussed on the Friday (Oklahoma region) conference call, Broken Bow-Bethel 138 kv was in the original needs list but not in latest project list. The other five segments of this line (Broken Bow Lone Oak) were in the list, and reconductoring them would seem to only make the Broken Bow-Bethel loading higher. SPP Staff stated they had considered including that sixth segment (Broken Bow-Bethel), even though it may have been loaded to slightly less than 100%. Please review the need for reconductoring this final line segment. SPP Response: See Action Item 2. Given the lack of generation and potential wind requests in the GI queue, does SPP have any thoughts on moving to an N-2 analysis for the ITP 10? SPP Response: SPP stakeholders have not included consideration of the N-2 analysis as part of the current ITP10 scope. The SPCTF agreed that cost of interconnection to an incumbent s substation would not be required for the RFP since the incumbent would make the interconnection. The incumbent picked up the line from the last pole. Will SPP provide the line and tower specifications to meet what the incumbent needs to make the interconnection into their substation. Also how is that cost accounted for in the project? SPP Response: SPP staff currently does not provide the cost of interconnection to an incumbent s substation (line and tower specifications), and is not required to do so at this time. The only greenfield new line project in North Dakota is the New Trenton-Strandahl 115 kv line. Who owns the substations for the new line? Has this line been determined to have any economic value? Does the line provide reliability for WAPA energy deliveries which are not subject to the IS Agreement? If so, what portion does SPP estimate is attributable to the WAPA energy deliveries outside the scope of the IS agreement? Are any of the reliability upgrades in the IS area attributable to the WAPA energy deliveries? If so, what portion does SPP estimate is attributable to the WAPA energy deliveries outside the scope of the IS agreement? SPP Response: According to the 2015 ITP10 models, SPP identified the Trenton and Strandahl substations as owned by Basin Electric Power Cooperatives (BEPC). SPP is reviewing ownership accuracy in the models as it relates to this project. This project relieves congestion on the Williston Judson 115 kv line, 2015ITP10-E1N0002. SPP staff does not assess this level of detail in the ITP10 process. See updated 2015 ITP10 project listing (version 4) in the posted meeting materials for October 29, 2014 TWG/ESWG Joint Meeting. 11 P a g e

12 Which projects in the draft consolidated portfolio address the following economic needs: o 2015ITP10E1N0007 B:539688S-DODGE W-DODGE3 1 FLO BASE CASE o 2015ITP10-E1N0014 B:532937NEOSHO RIV FLO LITCH ASB Did SPP receive DPPs addressing the above needs that passed SPP s B/C criteria? If yes, why were these projects not selected? SPP Response: Projects for need 2015ITP10-E1N0007 were evaluated, but through feedback from other SPP Engineering groups, no project was considered for this need. Gray County Wind Farm is modeled at a higher capacity (for 2024) than currently installed today, yet no transmission upgrades that would be necessary to accommodate the capacity increase were considered in the base model. In addition, based on the West Dodge NW Dodge 115 kv line of the Dodge City loop operated normally open, this constraint is effectively seen as a radial generator feed. Projects for need 2015ITP10-E1N0014 were evaluated and met the Phase 1 criteria, but after further analysis, Phase 2 criteria was not met, thus, no project made the Future 1 grouping. RMS Request (Submitter: ITC) - Iatan-Stranger Creek voltage conversion project The IATAN Stranger Creek 345 kv project was selected in the SPP ITP10 consolidated portfolio apparently due to the low cost of converting the existing 161 kv line from IATAN to Stranger Creek to 345 kv. Per KCPL s comments on the SPP calls last Friday, the existing conductor can be used for the higher voltage line. However, the towers will have to be rebuilt. The SPP models showed huge congestion on the existing IATAN Stranger Creek 345 kv line in the base case. ITC believes that taking a parallel line out of service for an extended period will exacerbate the congestion on the existing circuit. The costs incurred due to the additional congestion should be reflected in the cost of the project. The other options may not need an extended outage of existing circuits and may prove to be more cost effective. SPP Response: The ITP process does not currently consider the loss of revenue due to congestion during a long term outage. SPP staff will include this type of analysis in future ITP assessments upon the development and approval of a formal process by the applicable SPP working groups. RMS Request (Submitter: Exelon Generation Company LLC (EXGN)) 2015 ITP10 Project List Question 1: I've been told that the 2015 ITP10 project list is available on TrueShare. How do I get access to this? I have a TrueShare account, but right now I only have access to the TCR network models. Thanks, Jackson King. Question 2: Presumably " ITP10 Project List v3.xlsx" is the most up-to-date list? Where will future versions of the list be posted? SPP Response: Response #1: The 2015 ITP10 project list was included as part of the Planning Summit materials and can be found at the following link, as part of the.zip file: Here is a link for obtaining access to TrueShare models: Instructions to Access SPP Model Information. 12 P a g e

13 Response #2: Yes, version 3 is the most current project list. If additional versions are posted, a notice will be sent out. RMS Request (Submitter: SPS) ITP10 Project Cost Assumptions Can SPP provide the cost calculations (including the total cost) used in the Phase 2 grouping process for B/C and net present value calculations? This was requested in the regional breakout session but as requested submitting in RMS. SPP Response: For Phase 2, one-year benefit and one-year cost were used to compute benefit. The oneyear cost was obtained by starting with the conceptual cost estimate, provided by SPP staff. The total E&C cost was multiplied by 17% to calculate an annual carrying cost - this is the one-year cost was used in the calculations. SPP uses a 2.5% inflation rate to convert both costs and benefits to 2015 dollars before calculating the B/C ratio. RMS Request (Submitter: SPS) Modeling Input for ITP Can SPP identify the groupings for each need so projects can be matched up with what need they were considered? This was requested in the regional breakout sessions but we are submitting via RMS as requested. SPP Response: At a minimum, all projects were considered for all needs relating to the future and type for which they were submitted. All projects were considered for all reliability needs. For those submitted for economic needs, each project was considered for all economic needs relating to the future for which it was submitted. RMS Request (Submitter: SECI) Mingo Capacitors - NTC re-evaluation Attached please find our cost estimates for each option listed. Let me know if you need any more details. SPP Response: SPP staff used conceptual cost estimates in arriving at the preliminary consolidated portfolio. RMS Request (Submitter: SPS) IDEVs for ITP10 Projects Has SPP released the IDEV files for the projects from the recently released list? We asked if you would in the regional breakout sessions but I can't find them on Trueshare. Is there another location where these files would be released? SPP Response: Once the ITP10 study has been approved, SPP will release the PSS/E IDEV files for those projects included in the final portfolios. 13 P a g e