STATE OF INDIANA
INDIANA UTILITY REGULATORY COMMISSION
VERIFIED PETITION OF NORTHERN ) INDIANA PUBLIC SERVICE COMPANY LLC ) FOR (1) APPROVAL OF AN ADJUSTMENT ) TO ITS ELECTRIC SERVICE RATES ) THROUGH ITS TRANSMISSION, ) DISTRIBUTION, AND STORAGE SYSTEM ) IMPROVEMENT CHARGE (“TDSIC”) RATE ) SCHEDULE; (2) AUTHORITY TO DEFER 20% ) CAUSE NO. 44733‐TDSIC‐4 OF THE APPROVED CAPITAL ) EXPENDITURES AND TDSIC COSTS FOR ) RECOVERY IN PETITIONER’S NEXT ) GENERAL RATE CASE; (3) APPROVAL OF ) PETITIONER’S UPDATED 7‐YEAR ) ELECTRIC PLAN, INCLUDING ACTUAL ) AND PROPOSED ESTIMATED CAPITAL ) EXPENDITURES AND TDSIC COSTS THAT ) EXCEED THE APPROVED AMOUNTS IN ) CAUSE NO. 44733‐TDSIC‐3, ALL PURSUANT ) TO IND. CODE § 8‐1‐39‐9; AND (4) ) APPROVAL OF PETITIONER’S RETURN OF ) EXCESS INCOME TAX REVENUE ) RECOVERED THROUGH ITS BASE RATES ) BETWEEN JANUARY 1 AND APRIL 30, 2018 ) THROUGH ITS TDSIC FACTOR. )
PETITIONER’S NOTICE OF SUBSTITUTION OF WITNESS
Northern Indiana Public Service Company LLC, by counsel, hereby gives notice that Charles A. Vamos is being substituted for and is adopting the direct testimony and attachments previously prefiled by James E. Zucal. For purposes of convenience, attached hereto are (1) a redline version of
the Introduction section of Mr. Vamos’ direct testimony showing the changes from the previously prefiled version of Mr. Zucal’s direct testimony, and (2) a clean copy of Mr. Vamos’ direct testimony. At the evidentiary hearing in this
Cause, the clean version of Mr. Vamos’ direct testimony (along with the attachments) will be offered into evidence.
Respectfully submitted,
______Claudia J. Earls (No. 8468‐49) Bryan M. Likins (No. 29996‐49) NiSource Corporate Services ‐ Legal 150 West Market Street, Suite 600 Indianapolis, Indiana 46204 Phone: (317) 684‐4923 (Earls) Phone: (317) 684‐4922 (Likins) Fax: (317) 684‐4918 Email: cjearls@nisource.com Email: [email protected]
Attorneys for Northern Indiana Public Service Company LLC
-2- CERTIFICATE OF SERVICE
The undersigned hereby certifies that the foregoing was served by email transmission upon the following:
Jeffrey M. Reed Bette Dodd Randall C. Helmen Todd A. Richardson Tiffany Murray Lewis & Kappes, P.C. Office of Utility Consumer Counselor One American Square, Suite 2500 115 W. Washington Street, Indianapolis, Indiana 46282 Suite 1500 South bdodd@lewis‐kappes.com Indianapolis, Indiana 46204 trichardson@lewis‐kappes.com [email protected] [email protected] [email protected] [email protected]
Dated this 9th day of October, 2018.
______Bryan M. Likins
-3- Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 1
VERIFIED DIRECT TESTIMONY OF CHARLES A. VAMOSJAMES E. ZUCAL
Page No.
Introduction ...... 2
Executing the 7‐Year Plan ...... 65
Updates to the 7‐Year Plan ...... 1615
Plan Update Process ...... 2322
Distinction Between Cap Moves and Cost Variances ...... 2423
Actual Costs Incurred ...... 2726
Plan Update‐4 ...... 2928
2017 Projects ...... 4241
2018 Projects ...... 4645
2019 Projects ...... 5251
2020 Projects ...... 7574
2021 Projects ...... 7877
2022 Projects ...... 7978
44733 Order Compliance ...... 8281
Statutory Compliance ...... 8382
Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 2
1 INTRODUCTION
2 Q1. Please state your name, business address and title.
3 A1. My name is Charles A. VamosJames E. Zucal. My business address is 801
4 E. 86th Avenue, Merrillville, Eastport Tower, 3001 Leonard Drive,
5 Valparaiso, Indiana 4641046383. I am Director, Electric T&D Engineering
6 the Vice President, Projects and Construction Electric for Northern Indiana
7 Public Service Company LLC (“NIPSCO”).
8 Q2. Please briefly describe your educational and business experience.
9 A2. I received a Bachelor of Science degree in Electric Electronic Engineering
10 Technology from Purdue University Franklin University in Hammond,
11 Indiana Columbus, Ohio in 19923. I received an M.B.A. from Indiana
12 University in Gary, Indiana in 1996 and an M.S. in Electricity Markets from
13 the Illinois Institute of Technology in Chicago, Illinois in 2010. I am a
14 Registered Professional Engineer in the State of Indiana (2000) and a
15 certified Project Management Professional (2012). I began my employment
16 with NIPSCO in 1993 and have more than 25 years’ experience in electric
17 generation, transmission, and distribution as follows: Electrical Engineer
18 (1993‐2000), Asset Manager (2000‐2003), Manager Electric Substations
Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 3
1 (2003‐2011), Manager Electric Engineering (2011‐2014), Manager Electric
2 Asset Management (2014‐2018) and Director, Electric T&D Engineering
3 (2018 to present). Prior to joining NIPSCO as Vice President, Projects and
4 Construction Electric in September, 2017, I was Director of Regional
5 Engineering & Compliance Programs for American Electric Power, Inc.
6 (“AEP”). In that position I was responsible for providing leadership and
7 technical direction for a multi‐discipline engineering department of 130
8 full‐time employees in support of AEP generation facilities and
9 coordinating and overseeing the NERC reliability and cyber security
10 regulatory compliance requirements for AEP generating facilities. I worked
11 for AEP for 27 years in various positions, including Electrical Engineer
12 Technician (1989‐1993), Construction Coordinator (1993‐1995), Senior
13 Engineer Technologist (1996‐2005), Project Manager (2005‐2011), Manager
14 Startup & Commissioning (2011‐2013), and Director of Construction
15 Services (2013‐2017). In 2007, I also earned my Project Management
16 Professional (PMP) certification from the Project Management Institute and
17 have continuously maintained my certification.
18 Q3. What are your current responsibilities as Director of Electric T&D
Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 4
1 EngineeringVice President of Electric Engineering of NIPSCO?
2 A3. As Director of Electric T&D Engineering, Vice President of Projects and
3 Construction Electric, I am responsible for directing the Transmission and
4 Distribution Engineering functions for NIPSCO’s line, substation,
5 communications, standards, and protective relaying groups. I currently
6 oversee NIPSCO engineering departments to ensure the safe, reliable, and
7 constructible designs for over $200 million in transmission and distribution
8 projects yearly beginning in 2019. management of electric capital projects
9 throughout NIPSCO, including the Environmental Compliance Project,
10 Generation, Electric Transmission, Distribution, and Storage System
11 Improvement Charge (“TDSIC”) projects, and the Multi‐Value Projects
12 (“MVP”), which consist of 765 kV and 345 kV transmission lines. These
13 responsibilities include all aspects of project management and construction.
14 Q4. Please provide an overview of your role with respect to the 7‐Year Electric
15 TDSIC Plan (also referred to herein as the “7‐Year Plan” or “Plan”).
16 A4. I am responsible for development of the NIPSCO 7‐Year Electric TDSIC
17 Plan taking into consideration safety, reliability, age, condition and overall
18 system performance. This includes development of detailed asset registers
Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 5
1 defining the projects included in the Plan. This responsibility also includes
2 maintaining the risk model and updates to the condition‐based assessment
3 of assets in the Plan and making future updates to the Plan as appropriate.
4 Additional responsibilities include development of the project cost
5 estimates and supporting the financial performance of the projects included
6 in the 7‐Year Electric TDSIC Plan.
7 Q5. Have you previously testified before this or any other regulatory
8 commission?
9 A5. No. Yes. I previously submitted testimony before the Indiana Utility
10 Regulatory Commission in Cause No. 44340‐FMCA‐9.
11 Q6. What is the purpose of your direct testimony in this proceeding?
12 A6. The primary purpose of my testimony is to support and explain NIPSCO’s
13 Updated 7‐Year Electric Plan (“Plan Update‐4”), including supporting the
14 actual capital expenditures incurred through May 31, 2018 as shown on
15 Petitioner’s Exhibit No. 1, Attachment 1‐A, Attachment 1, Schedule 1. I also
16 describe how NIPSCO is managing the portfolio of projects included in the
17 Plan.
18 Q7. Are you sponsoring any attachments to your direct testimony?
VERIFICATION
I, Charles A. Vamos, Director, Electric T&D Engineering James E. Zucal, Vice
President, Projects and Construction Electric for Northern Indiana Public Service
Company LLC, affirm under penalties of perjury that the foregoing representations are true and correct to the best of my knowledge, information and belief.
______Charles A. VamosJames E. Zucal
Date: October 9, July 31, 2018
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 1
VERIFIED DIRECT TESTIMONY OF CHARLES A. VAMOS
Page No.
Introduction ...... 2
Executing the 7‐Year Plan ...... 5
Updates to the 7‐Year Plan ...... 15
Plan Update Process ...... 22
Distinction Between Cap Moves and Cost Variances ...... 23
Actual Costs Incurred ...... 26
Plan Update‐4 ...... 28
2017 Projects ...... 41
2018 Projects ...... 45
2019 Projects ...... 51
2020 Projects ...... 74
2021 Projects ...... 77
2022 Projects ...... 78
44733 Order Compliance ...... 81
Statutory Compliance ...... 82 REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 2
1 INTRODUCTION
2 Q1. Please state your name, business address and title.
3 A1. My name is Charles A. Vamos. My business address is 801 E. 86th Avenue,
4 Merrillville, Indiana 46410. I am Director, Electric T&D Engineering for
5 Northern Indiana Public Service Company LLC (“NIPSCO”).
6 Q2. Please briefly describe your educational and business experience.
7 A2. I received a Bachelor of Science degree in Electric Engineering Technology
8 from Purdue University in Hammond, Indiana in 1992. I received an
9 M.B.A. from Indiana University in Gary, Indiana in 1996 and an M.S. in
10 Electricity Markets from the Illinois Institute of Technology in Chicago,
11 Illinois in 2010. I am a Registered Professional Engineer in the State of
12 Indiana (2000) and a certified Project Management Professional (2012). I
13 began my employment with NIPSCO in 1993 and have more than 25 years’
14 experience in electric generation, transmission, and distribution as follows:
15 Electrical Engineer (1993‐2000), Asset Manager (2000‐2003), Manager
16 Electric Substations (2003‐2011), Manager Electric Engineering (2011‐2014),
17 Manager Electric Asset Management (2014‐2018) and Director, Electric
18 T&D Engineering (2018 to present).
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 3
1 Q3. What are your current responsibilities as Director of Electric T&D
2 Engineering of NIPSCO?
3 A3. As Director of Electric T&D Engineering, I am responsible for directing the
4 Transmission and Distribution Engineering functions for NIPSCO’s line,
5 substation, communications, standards, and protective relaying groups. I
6 currently oversee NIPSCO engineering departments to ensure the safe,
7 reliable, and constructible designs for over $200 million in transmission and
8 distribution projects yearly beginning in 2019.
9 Q4. Please provide an overview of your role with respect to the 7‐Year Electric
10 TDSIC Plan (also referred to herein as the “7‐Year Plan” or “Plan”).
11 A4. I am responsible for development of the NIPSCO 7‐Year Electric TDSIC
12 Plan taking into consideration safety, reliability, age, condition and overall
13 system performance. This includes development of detailed asset registers
14 defining the projects included in the Plan. This responsibility also includes
15 maintaining the risk model and updates to the condition‐based assessment
16 of assets in the Plan and making future updates to the Plan as appropriate.
17 Additional responsibilities include development of the project cost REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 4
1 estimates and supporting the financial performance of the projects included
2 in the 7‐Year Electric TDSIC Plan.
3 Q5. Have you previously testified before this or any other regulatory
4 commission?
5 A5. No.
6 Q6. What is the purpose of your direct testimony in this proceeding?
7 A6. The primary purpose of my testimony is to support and explain NIPSCO’s
8 Updated 7‐Year Electric Plan (“Plan Update‐4”), including supporting the
9 actual capital expenditures incurred through May 31, 2018 as shown on
10 Petitioner’s Exhibit No. 1, Attachment 1‐A, Attachment 1, Schedule 1. I also
11 describe how NIPSCO is managing the portfolio of projects included in the
12 Plan.
13 Q7. Are you sponsoring any attachments to your direct testimony?
14 A7. Yes. NIPSCO’s Verified Petition initiating this Cause is designated as
15 Attachment 1‐A sponsored by NIPSCO Witness Becker. I am sponsoring
16 the following attachments, all of which were prepared by me or under my
17 direction and supervision: (1) Plan Update‐4, which is attached to the
18 Verified Petition initiating this Cause as Confidential Exhibit Electric Plan
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 5
1 Update‐4, (2) Plan Update‐3 approved in Cause No. 44733‐TDSIC‐3, which
2 is attached to the Verified Petition initiating this Cause as Confidential
3 Exhibit Electric Plan Update‐3, and (3) Attachment 1, Schedule 1, which is
4 attached to the Verified Petition initiating this Cause, which shows the
5 actual capital expenditures incurred through May 31, 2018 relating to the
6 eligible transmission, distribution, and storage system improvements. I
7 also sponsor Confidential Attachment 3‐A showing changes made to
8 Appendices 1 and 2 to the Plan.
9 EXECUTING THE 7‐YEAR PLAN
10 Q8. What project management principles does NIPSCO use to execute the 7‐
11 Year Plan?
12 A8. NIPSCO’s Project Managers have been trained and most have been certified
13 as Project Management Professionals. NIPSCO’s procedures require
14 Project Managers to follow the Project Management Institute’s Project
15 Management Body of Knowledge principles. The project life cycle is of
16 significant importance to NIPSCO’s senior leadership, and the status of
17 each project is reviewed twice a month, at a minimum. The project reviews
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 6
1 focus on safety, quality, cost, scope and schedule and any risks that are
2 associated with the projects.
3 Q9. Please describe how NIPSCO manages the portfolio of projects included
4 in the 7‐Year Plan.
5 A9. All projects included in the 7‐year Plan follow a controlled management
6 structure through the life of the project. Asset Management, within the
7 engineering organization, is responsible for development of the 7‐Year
8 Plan, updating the Plan with the most recent condition information and
9 prioritizing projects based on likelihood of failure and consequence of
10 failure. The project management organization is solely responsible for
11 ensuring all projects are executed on time and within budget. Project
12 Management provides project oversight, working with construction and
13 engineering organizations to make sure all projects are ready for
14 construction, and also ensures that the project stays on schedule and
15 manages costs associated with the project. This group is also responsible
16 for project change requests (“PCRs”) throughout the project life cycle. The
17 Project Controls organization is an independent work group responsible for
18 providing associated reporting metrics. Project Controls develops the
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 7
1 annual resource plan and reports on cost performance and schedule
2 adherence. These groups work in harmony to develop and define each year
3 of the 7‐Year Plan, to provide clear and robust project management, and to
4 provide independent reporting of project metrics.
5 Q10. Please explain NIPSCO’s cost management process as it relates to the
6 projects included in the 7‐Year Plan.
7 A10. The process for initiating a new TDSIC work order begins with the Project
8 Manager/Engineer submitting a Capital Initiative Form (“CIF”) to the
9 TDSIC Support Budget Analyst. The Budget Analyst does a preliminary
10 check of the asset register to verify the work is a valid TDSIC project. The
11 Budget Analyst initiates the work order and routes the CIF to the Plan
12 Owner (Asset Management) and the Project Execution/Engineering Team
13 for two levels of approval. The purpose of the first level of approval,
14 termed “TDSIC Verification,” is to verify that the project and costs are
15 TDSIC eligible. This ensures that only eligible project costs are included in
16 the TDSIC tracker. The Plan Owner approves projects for TDSIC eligibility
17 by referring to NIPSCO’s currently approved 7‐Year Electric TDSIC Plan.
18 The Plan Owner is responsible for understanding the intent and purpose of
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 8
1 the overall Plan, and reviews all requests to determine if the work is
2 approved within the Plan. This is a critical piece of the TDSIC Plan as it
3 allows the most flexibility for NIPSCO as the system continues to change.
4 The purpose of the second level of approval, termed “Work Order
5 Approval,” is to approve the scope and cost of the project work for all
6 projects coming out of the TDSIC Verification process. The work order is
7 approved by the Project Execution or Engineering Leaders depending on
8 who submits the work order request, either the Project Manager or
9 Engineer. Both TDSIC Verification and Work Order Approval are required
10 before work is performed and project costs are incurred. The only
11 exception to this process is when a work order is needed for an emergency,
12 where approvals are obtained after the work order is provided to the Project
13 Manager/Engineer. If the work order is determined not to be an eligible
14 TDSIC project after it has been routed through for formal approval, the
15 work order is cancelled and removed from the TDSIC work order list. The
16 emergency work order process is not a common occurrence, but may
17 occasionally happen.
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 9
1 At the time of request and during the review and approval process, TDSIC
2 work orders are identified and classified by category and sub‐category.
3 During initiation of the work order, the TDSIC Budget Analyst flags the
4 TDSIC work order in NIPSCO’s Fixed Asset System (PowerPlant) with the
5 specific TDSIC category and sub‐category. These identifiers and
6 classifications in PowerPlant assist in ensuring that only TDSIC work
7 orders are included for recovery.
8 Once a TDSIC work order is initiated, NIPSCO records charges to the work
9 order in accordance with the internal controls discussed below. Capital
10 dollars at NIPSCO are separated into two segments: (1) direct capital and
11 (2) indirect capital. Direct capital represents costs such as the materials and
12 equipment installed and the labor costs of the workers performing the
13 construction. Typically, these are costs that are incurred at the job site.
14 Indirect costs are associated with capital projects and must be capitalized
15 in order to comply with Generally Accepted Accounting Principles.
16 However, these often cannot be charged directly to a specific capital project
17 work order as they cannot be directly linked to one particular project. These
18 capital costs tend to be incurred away from the job site. NIPSCO groups
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 10
1 these indirect capital costs into three categories: (1) overheads, (2) stores,
2 freight and handling, and (3) allowance for funds used during construction
3 (“AFUDC”).
4 Vendor related direct costs are procured through the use of a Material
5 Requisition (“MR”). A purchase order (“PO”) is required to order goods or
6 services. To initiate a PO with a vendor, an MR is initiated and routed for
7 approval. The MRs related to TDSIC projects are labeled with a specific
8 route code to ensure they are first routed to the TDSIC Project Controls
9 Team, who then routes the request for required approvals. The MRs are
10 approved by the Project Execution Leaders depending upon the dollar
11 amount of the request. The Procurement group then generates a PO, which
12 is identified as a TDSIC PO. This TDSIC route code on the PO ensures that
13 TDSIC invoices are routed to the TDSIC Project Controls Team for
14 validation. The TDSIC Project Controls Team routes TDSIC invoices to the
15 TDSIC Project Execution group for two levels of approval.
16 In addition to the controls discussed above, the TDSIC Project Controls
17 Team provides weekly reports to the TDSIC Project Managers that show
18 the year‐to‐date actual costs recorded to each project and the current
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 11
1 month’s estimated weekly actual costs. The TDSIC Project Controls Cost
2 Engineers generally meet monthly one‐on‐one with the TDSIC Project
3 Managers to review actual costs, to estimate accruals, and to forecast the
4 current year estimate at completion and full project estimate at completion
5 for multi‐year projects. TDSIC Project Managers also review all project
6 costs to ensure that costs are properly recorded to the TDSIC work orders.
7 This process includes the review of non‐vendor payments such as internal
8 labor and other direct costs. The TDSIC Project Manager reviews the
9 detailed project cost reports provided by the TDSIC Project Controls Team
10 to ensure that all vendor payments are properly recorded, and internal
11 labor charges are appropriate. Any unusual charges are investigated and
12 corrected if necessary.
13 Q11. Please explain the process for estimating projects and updating the Plan.
14 A11. The Scope Development and Estimating group utilizes proven estimating
15 methods described later in my testimony to update the costs associated
16 with the 7‐Year Plan. Projects more than three tyears ou in the Plan are
17 estimated utilizing a unit cost estimate with limited engineering complete
18 at that time. Projects between two and three years out are scoped. This
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 12
1 process includes a site visit, preliminary engineering, and development of
2 a component list and project map or single line diagram. The scope
3 documents are reviewed by a team of internal stakeholders prior to being
4 approved and moving to the detailed engineering phase. This team
5 includes Engineering, Planning, System Protection, Relay and Control,
6 Communications, Construction Planning, Operations, Environmental, Real
7 Estate, Forestry and other departments as necessary.
8 Projects that are planned for construction within the next two years of the
9 Plan utilize a more detailed estimating process. These projects have
10 detailed engineering complete or nearly complete and a detailed estimate
11 review occurs which includes the internal stakeholders listed above as well
12 as Project Management and Construction. Detailed engineering includes a
13 bill of materials and technical drawings to be utilized by the construction
14 team. The process of estimate refinement is a continuous process as the 7‐
15 Year Plan progresses. These estimating techniques are utilized at NIPSCO
16 to best leverage resources while providing the best estimate based on lead
17 time for construction improving overall project continuity and efficiency.
18 Q12. Please describe the different techniques used to develop a cost estimate
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 13
1 for a project.
2 A12. A cost estimate is developed at a point in time, and it is based on the
3 information known when the estimate is developed. As the project
4 progresses, the information used as inputs into the cost estimation process
5 becomes more accurate. There are different techniques used by project
6 managers to develop a cost estimate for a project.
7 Analogous Class 5 (the estimate is based on expert judgment and 8 overall system factors) – these estimates have very little of the total 9 project defined, 0 – 2%, and require very little engineering in order 10 to estimate.
11 Parametric Class 4 (the estimate is developed using application of 12 similar type estimates and specific equipment factors) – these 13 estimates are done at about 1 – 15% of the total project being defined 14 and usually have an engineering or feasibility study associated with 15 them.
16 Semi‐detailed Class 2 / 3 (the estimate is developed with unit costs 17 and with assembly level line items) – these estimates are performed 18 at 10 – 70% project definition, have detailed engineering nearly 19 complete, and use bids tendered as development for the estimate.
20 Detailed Class 1 (the estimate is developed with unit costs and with 21 detailed bill of materials) – these estimates are performed at 50 – 22 100% project definition with eth detailed engineering complete, bids 23 tendered and verified to develop the estimate.
24 25 These cost estimation methods are only as good as the information that is
26 available at that time to be used as inputs. NIPSCO uses sound estimation
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 14
1 techniques and the most current information available to develop cost
2 estimates for a regulatory filing. However, due to the timing associated
3 with the regulatory proceedings, cost estimates may be prepared well in
4 advance of when the project actually commences.
5 Best practices for project management and program management call for
6 updating and refining cost estimates as the project proceeds. It is a good
7 practice to use the most recent data, both actual costs and other industry
8 benchmarks for estimating projects. In addition, the practice of updating
9 prior to actual work commencing helps NIPSCO manage the portfolio of
10 projects and overall risk. This is because actual costs and the most recent
11 data better reflect the current market conditions relative to the industry and
12 therefore generate the best estimates at that time. Beyond current costs and
13 market conditions, updating also helps to identify changes over time,
14 specifically related to either constructability impacts or environmental
15 conditions. If the program manager knows that one particular project in
16 the portfolio will cost more than the original estimate, the program
17 manager might need to request approval for additional funds. However, if
18 the program manager also knows two projects will likely cost less than the
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 15
1 original estimates, the program manager may be able to balance the
2 portfolio without needing to request additional funds. Furthermore,
3 refining cost estimates as the projects progress helps NIPSCO to identify
4 and mitigate risks.
5 The process of reviewing and updating project cost estimates is done in the
6 normal course of project management and portfolio management, but now
7 the information gleaned through this process is incorporated into
8 NIPSCO’s TDSIC filings. This also helps ensure that in each Plan Update,
9 the cost estimate is based on current information and represents the best
10 estimate of cost for the projects at the time of the filing.
11 UPDATES TO THE 7‐YEAR PLAN
12 Q13. Has NIPSCO included an updated 7‐Year Plan as part of this filing as
13 required by Ind. Code § 8‐1‐39‐9?
14 A13. Yes. NIPSCO’s proposed Updated 7‐Year Plan is attached to the Verified
15 Petition initiating this Cause as Confidential Exhibit Electric Plan Update‐
16 4. Plan Update‐4 is organized as follows:
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 16
Plan by Project Provides a high level summary showing the breakout Category of investment by year for both transmission and distribution. Plan by FERC Provides a high level summary showing the break Account down by Federal Energy Regulatory Commission (“FERC”) Uniform System of Account number by year for both transmission and distribution. Project Detail by Provides project detail separately for each year of the Year Plan (2016‐2022). The Project Detail by Year pages are described in greater detail below. Detailed scope and estimate summaries (project estimates) for the projects included in Year 2 (2017), Year 3 (2018), and Year 4 (2019), including projects that moved into those years, are included in Appendices 3, 4, and 5, respectively. Project Detail Provides an explanation of the moves and variances Variances for each year of the Plan (2017‐2022). Transmission Provides a comparison of the approved Plan Update‐ Capital Projects 3 to Plan Update‐4 organized by Category Summary Transmission Provides a comparison of the approved Plan Update‐ Capital Projects 3 to Plan Update‐4 by organized by FERC Account by FERC Account Distribution Provides a comparison of the approved Plan Update‐ Capital Projects 3 to Plan Update‐4 organized by Category Summary Distribution Provides a comparison of the approved Plan Update‐ Capital Projects 3 to Plan Update‐4 by organized by FERC Account by FERC Account
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 17
Project Detail Matrix showing all of the projects included in Plan Summary by Update‐4 by project category by year showing the Year total investment of the 7‐Year Electric TDSIC Plan. Confidential Asset Register for Risk Based Projects Appendix 1 Confidential Asset Register for Deliverability and Condition Based Appendix 2 Projects Confidential 2017 Project Estimates Appendix 3 Confidential 2017 Revised Project Estimates (supporting Plan Appendix 3.1 Update‐1) Confidential 2017 Project Change Requests and new 2017 Estimate Appendix 3.2 Summaries (supporting Plan Update‐2) Confidential 2017 Project Change Requests (supporting Plan Appendix 3.3 Update‐3) Confidential 2017 Project Change Requests (supporting Plan Appendix 3.4 Update‐4) Confidential 2018 Project Estimates (supporting Plan Update‐2) Appendix 4 Confidential 2018 Project Change Requests (supporting Plan Appendix 4.1 Update‐3) Confidential 2018 Project Change Requests (supporting Plan Appendix 4.2 Update‐4) Confidential 2019 Project Estimates (supporting Plan Update‐3) Appendix 5 Confidential 2019 Project Estimates (supporting Plan Update‐4) Appendix 5.1 Confidential Unit Cost Tables and Methodology, by Project Type Appendix 6 Confidential Updated Unit Cost Tables for 2016, 2017, and 2018 Appendix 6.1 (supporting Plan Update‐2 and Plan Update‐3)
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 18
Confidential Updated Unit Cost Tables for 2019 (supporting Plan Appendix 6.2 Update‐4) Appendix 7 Register of Street Lights by Municipality Confidential 2019 Project Mapping Appendix 8 1
2 Q14. Please describe Confidential Appendix 1.
3 A14. Confidential Appendix 1 identifies and prioritizes the overhead and
4 underground circuit rebuild projects, transformers, and circuit breaker
5 assets. These are major transmission and distribution projects requiring
6 significant lead time and planning to execute.
7 Q15. Please describe Confidential Appendix 2.
8 A15. Confidential Appendix 2 identifies and prioritizes the Aging Infrastructure
9 assets (oil circuit breakers, wood poles, steel tower rehabilitation,
10 underground cable, circuit performance and system deliverability). These
11 are projects that were ranked using factors such as age, condition and
12 capacity.
13 Q16. Please describe Confidential Appendix 3.
14 A16. Confidential Appendix 3 includes the detailed cost estimates for the 2017
15 projects.
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 19
1 Q17. Please describe Confidential Appendix 3.1.
2 A17. Confidential Appendix 3.1 includes the revised Estimate Summaries, along
3 with estimate worksheets, supporting the revisions to individual project
4 costs for Year 2017 filed in support of Plan Update‐1.
5 Q18. Please describe Confidential Appendix 3.2.
6 A18. Confidential Appendix 3.2 includes PCR forms and new cost estimates for
7 projects moved into 2017 from a future year filed in support of Plan Update‐
8 2.
9 Q19. Please describe Confidential Appendix 3.3.
10 A19. Confidential Appendix 3.3 includes PCR forms and new cost estimates for
11 projects moved into 2017 from a future year filed in support of Plan Update‐
12 3.
13 Q20. Please describe Confidential Appendix 3.4.
14 A20. Confidential Appendix 3.4 includes PCR forms for updated cost estimates
15 and for projects moved into 2017 from a future year filed in support of Plan
16 Update‐4.
17 Q21. Please describe Confidential Appendix 4.
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 20
1 A21. Confidential Appendix 4 includes the detailed cost estimates for the 2018
2 projects.
3 Q22. Please describe Confidential Appendix 4.1.
4 A22. Confidential Appendix 4.1 includes PCR forms for the 2018 projects filed in
5 support of Plan Update‐3.
6 Q23. Please describe Confidential Appendix 4.2.
7 A23. Confidential Appendix 4.2 includes PCR forms for the 2018 projects filed in
8 support of Plan Update‐4.
9 Q24. Please describe Confidential Appendix 5.
10 A24. Confidential Appendix 5 includes the detailed cost estimates for the 2019
11 projects filed in support of Plan Update‐3.
12 Q25. Please describe Confidential Appendix 5.1.
13 A25. Confidential Appendix 5.1 includes the detailed cost estimates for the 2019
14 projects filed in support of Plan Update‐4.
15 Q26. Please describe Confidential Appendix 6.
16 A26. Confidential Appendix 6 provides the methodology and initial unit‐cost
17 based estimates developed for the TDSIC Plan (2016 – 2022) broken down
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 21
1 by direct and indirect costs including labor and material for projects with
2 unit‐cost based estimates.
3 Q27. Please describe Confidential Appendix 6.1.
4 A27. Confidential Appendix 6.1 provides updates to the unit‐cost based
5 estimates initially developed in Appendix 6 for the TDSIC Plan for years
6 2016, 2017, and 2018 in support of Plan Update‐2 and Plan Update‐3.
7 Q28. Please describe Confidential Appendix 6.2.
8 A28. Confidential Appendix 6.2 provides updates to the unit‐cost based
9 estimates developed in Appendix 6.1 for the TDSIC Plan for year 2019 in
10 support of Plan Update‐4.
11 Q29. Please describe Appendix 7.
12 A29. Appendix 7 includes NIPSCO’s Register of Street Lights by Municipality
13 showing the number of streetlights to be replaced by municipality in each
14 year of the Plan.
15 Q30. Please describe Confidential Appendix 8.
16 A30. Confidential Appendix 8 shows 2019 projects that moved from one Project
17 ID to another.
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 22
1 Q31. Has NIPSCO updated Appendices 1 and 2 in this tracker filing?
2 A31. Yes. Appendices 1 and 2 were both updated to reflect revised timing of
3 when assets will be replaced. A spreadsheet showing the updates is
4 attached hereto as Confidential Attachment 3‐A.
5 PLAN UPDATE PROCESS
6 Q32. Please describe the Plan update process agreed to in Cause No. 44733.
7 A32. Each year in its fall tracker filing, NIPSCO provides a detailed list of projects
8 for the upcoming year, with its best estimate of project costs. However, it
9 is important to note that NIPSCO retains the ability to move projects
10 between years as appropriate. In the event that a given project, in whole or
11 in part, is rescheduled to a different year, the annual cost recovery caps for
12 the affected years will be adjusted by that project’s whole or partial
13 approved cost estimate to reflect the change (e.g., if a $10 million project is
14 moved from 2018 to 2019, the annual cap for 2018 will be reduced by $10
15 million and the annual cap for 2019 will be increased by $10 million).
16 Each year in its spring tracker filing, NIPSCO provides the actual costs of
17 the projects completed in the prior year and updated projected costs of the
18 projects in the current and subsequent years. For projects with actual or REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 23
1 projected costs higher than the costs previously approved, NIPSCO
2 provides justification in the form of written variance explanations. Projects
3 with cost variances greater than $30,000 or 15%, whichever is greater, are
4 be supported by a PCR form. Projects with cost variances greater than
5 $100,000 or 20%, whichever is greater, are also be supported by written
6 testimony.
7 DISTINCTION BETWEEN CAP MOVES AND COST VARIANCES
8 Q33. Please explain the difference between a project move and a project cost
9 variance.
10 A33. When a project moves from one year to another, the original estimate of
11 that project moves out of the year it came from and into the year it moves
12 to, in order to accurately measure against the cap for ratemaking purposes
13 (“Cap Move”). Once the project has moved into a new year, the project
14 estimate may be revised, which may be higher or lower than the Cap Move.
15 The increased or decreased project estimate will result in a project cost
16 variance.
17 Q34. Why are Cap Moves necessary? REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 24
1 A34. In many cases throughout NIPSCO’s 7‐Year Plan the replacement of assets
2 cannot be completed within one calendar year or may not be completed in
3 the originally planned year. This is due to a variety of reasons including
4 labor constraints, system loading limitations, Midcontinent Independent
5 System Operator (“MISO”) clearances, current asset condition or
6 sequencing of asset installations.
7 Q35. Please describe the main reasons that projects move between years in the
8 Plan.
9 A35. There are three main reasons why projects move between years during the
10 execution of the Plan. First, there are equipment failures, or “break/fix”
11 projects, that occur. When an asset is listed on the asset register, but fails
12 earlier than the year listed in the Plan, NIPSCO will replace that asset in the
13 year that it fails. Second, there are “imminent failures.” If, during
14 NIPSCO’s routine maintenance and inspections, an asset is determined to
15 be near failure and the cost of performing maintenance on the asset is not
16 cost effective, the failing asset will be scheduled for immediate replacement.
17 Third, there are “coordination of effort” issues. In this case, when NIPSCO
18 coordinates execution of projects in the Plan, an additional effort is being
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 25
1 made to identify efficiencies by coordinating all the work that can be done
2 under a single clearance (to have the assets being replaced isolated from the
3 electrical transmission or distribution system and de‐energized so the work
4 can be performed safely). As I discuss above, the asset register in the Plan
5 was prioritized based on consequence of failure and probability of failure.
6 Prioritizing assets in this fashion and then replacing assets with the highest
7 scores improves safety and reliability. However, there are times that it
8 makes sense to change the order of replacement either for cost effectiveness
9 or to better meet customer needs. For example, if a substation transformer
10 is to be replaced in 2018 and the arresters in the substation are scheduled
11 for replacement in 2021, NIPSCO will move the replacement of the arresters
12 into 2018 to allow for greater efficiencies.
13 Q36. Are there times when a portion of a project (Cap Move) is split between
14 years?
15 A36. Yes. Engineering, land acquisition, material purchase or other
16 preconstruction activity may take place in a prior year necessitating a
17 partial cap move. Construction or planning related requirements may
18 dictate part of a project be moved to a separate year from main construction.
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 26
1 Premature failure of a component included in a scheduled TDSIC project
2 could also result in a partial cap move. Partial cap moves are used to best
3 represent the calendar year in which the work related to the specific project
4 will take place.
5 Q37. Is there a list of the Cap Moves?
6 A37. Yes. Any project that moves from one year to another, in whole or in part,
7 is tracked and listed in Confidential Attachment 4‐A sponsored by NIPSCO
8 Witness Figg. In her direct testimony, NIPSCO Witness Figg includes a list
9 of all of the moves, including partial moves that are split between years.
10 ACTUAL COSTS INCURRED
11 Q38. What is the total actual capital expenditures associated with NIPSCO’s
12 investment in transmission, distribution, and storage system
13 improvements as of May 31, 2018?
14 A38. As shown in Petitioner’s Exhibit No. 1, Attachment 1‐A, Attachment 1,
15 Schedule 1, the total gross direct capital expenditures associated with
16 NIPSCO’s investment in transmission, distribution, and storage system
17 improvements as of May 31, 2018 is $283,168,213 [Page 3, Line 1 plus Line
18 2, Column D]. The total indirect capital expenditures associated with REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 27
1 NIPSCO’s investment in transmission, distribution, and storage system
2 improvements as of May 31, 2018 is $38,888,050 [Page 3, Line 3, Column D].
3 The total AFUDC for capital expenditures associated with NIPSCO’s
4 investment in transmission, distribution, and storage system improvements
5 as of May 31, 2018 is $8,829,070 [Page 3, Line 4, Column D]. The total gross
6 capital expenditures associated with NIPSCO’s investment in transmission,
7 distribution, and storage system improvements as of May 31, 2018 is
8 $330,885,333 [Page 3, Line 5, Column D].
9 Q39. Referring to Plan Update‐4 and Petitioner’s Exhibit No. 1, Attachment 1‐
10 A, Attachment 1, Schedule 1, please explain why the subtotals for the
11 transmission and distribution project categories differ from the subtotals
12 for transmission and distribution Federal Energy Regulatory
13 Commission (“FERC”) accounts.
14 A39. There are differences in the transmission and distribution subtotals when
15 comparing Project Category to FERC account. Some projects, such as
16 inspect and mitigate projects, incur charges that are booked to both
17 distribution and transmission FERC accounts. However, because a
18 majority of project costs related to specific projects are charged to either REDACTED Petitioner's Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733-TDSIC-4 Page 28
1 distribution or transmission FERC accounts, the project is classified into
2 either a transmission or distribution project category on Plan Update-3 and
3 Petitioner' s Exhibit No. 1. Attaclunent 1-A, Attachment 1, Schedule 1.
4 PLANUPDATE-4
5 Q40. Please explain how the Project Detail pages of Plan Update-4 are
6 organized.
7 A40. The Project Detail pages of Plan Update-4 are organized, by year, as follows:
Column Name Description A Line No. B Project ID Shows the Project ID assigned to the project. c Project Sub-Category Shows the Sub-Category for the project. D Project Driver Shows the project driver. E Project Title Shows the name of the project. F Approved Project Cost This shows the costs (direct dollars) included in NIPSCO' s approved Plan Update-3. G Updated Project Cost This shows the updated project costs (direct dollars) included in NIPSCO' s Plan Update-4. H Variance by Project This shows the difference between the Approved Project Cost (direct dollars) and Updated Project Cost (direct dollars). REDACTED Petitioner's Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733-TDSIC-4 Page 29
Column Name Description I Quantity This shows the quantity included in the project. J Unit of Measure This shows the unit of measure for the project. 1 2 The Project Detail pages for Plan Years 2017 through 2022 also provide an
3 explanation for each of the variances by project.
4 Q41. Please describe Confidential Attachment 3-B and explain how it 1s
5 organized.
6 A41. Confidential Attachment 3-B shows plan variances (moves and costs) by
7 year, by project, specifically showing the an1ount of the project move, the
8 project cost variance, and the percent of project cost variance. The purpose
9 of Confidential Attachment 3-B is to further break down the plan variances
10 into project moves and project cost variances. The "Total Variance"
11 (Column G) from Confidential Attachment 3-B is equal to the "Variance by
12 Project" (Colunm H) from Plan Update-4 on the Project Detail Pages for
13 each year. If a project moves into or out of a year, the move is captured in REDACTED Petitioner's Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733-TDSIC-4 Page 30
1 "Move In" (Colunm H) or "Move Out" (Column 1).1 The sun1 of the "Move
2 In" and "Move Out" columns is included in the "Net Moves" colunm
3 (Colunm J) . The value of the move in or out is equivalent to the previously
4 approved plan. For 2018 to 2022, the projects with unit costs moving from
5 a given year will assume the equivalent unit cost of the year it is moving to.
6 For exan1ple, a 69kV line switch in Line Switch Projects - Transmission
7 [Project ID TLSWl] moves out of 2022 with unit cost of $45,230 and moves
8 into 2019 with unit cost of $42,602. In the case of 2017, the projects with unit
9 costs assumes the average unit cost calculated by taking the approved Plan
10 Update-3 an1ount and dividing by units. If the cost estimate of a project has
11 changed, either up or down, the change in cost is captured in the "Project
12 Cost Variance" colunm (Colunm K). The pages of Confidential Attachment
13 3-B are organized, by year, as follows:
Column Name Description A Line No. B Year Shows the project year. c Project ID Shows the Project ID assigned to the project.
The Move In and Move Out columns are further supported by Confidential Attachment 3- A. REDACTED Petitioner's Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733-TDSIC-4 Page 31
Column Name Description D Title Shows the project title. E Approved Plan Update-3 Provides the project an1ounts for Plan Update-3. F Plan Update-4 Provides the project an1ounts for Plan Update-4. G Total Variance Provides the project detail variance between Plan Update-3 and Plan Update-4. H Move In Provides the amount moved into a given year based on Plan Update- 3 approved estimates. I Move Out Provides the amount moved out of a given year based on Plan Update-3 approved estimates. J Net Moves Provides the net amount moved into and out of a given year based on Plan Update-3 approved estimates. K Project Cost Variance Provides the cost variance from the Plan Update-3 approved estimates; increases greater than $100,000 are detailed below. L % Total Variance Provides the % Total variance from the Plan Update-3 approved estimates; increases greater than 20% are detailed below. 1 2 Q42. Please describe why there are new Project IDs included in Plan Update-
3 4. REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 32
1 A42. NIPSCO’s initial TDSIC Plan included detailed estimates for 2016 and 2017
2 and parametric estimates for 2018‐2022. When a project moves from a
3 parametric estimate to having a detailed scope, NIPSCO establishes a
4 Project ID and Project Name and includes that in the Plan update. In some
5 cases, a project that was previously included in the Plan as a grouped
6 project is broken out into a specific asset or location. In other cases, dollars
7 move from a unit based project to one specific project. Question / Answer
8 63 provides examples of 2019 projects that moved from one Project ID to
9 another.
10 Q43. Has NIPSCO updated any parametric estimates in Plan Update‐4?
11 A43. Yes. The 2019 projects included in this Plan Update‐4 have moved from
12 parametric (Class 4) estimates to detailed engineering (Class 2 or 3)
13 estimates.2 The availability of detailed engineering estimates means that
14 NIPSCO now has more specificity about a particular project, which allows
15 for a refined cost estimate as well. Although 2019 Projects with cost
16 increases greater than $100,000 or 20%, whichever is greater, are supported
2 For the East Chicago Substation project [Project ID TSNRS14], which is a 2019 project, NIPSCO is currently performing but has not yet completed detailed engineering. REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 33
1 by written testimony below, moving from parametric to detailed
2 engineering estimates also led to cost estimate decreases for a number of
3 2019 projects, as would be expected. Because of this,r fo the 2019 projects
4 with cost increases that are discussed below, I have identified when the
5 move from a parametric to detailed engineering estimate was a driver of
6 the cost increase.
7 Q44. Please describe any engineering changes that have taken place relative to
8 the previous plan update.
9 A44. In its original filed 7‐Year Plan, NIPSCO planned to conduct engineering in
10 the year prior to the start date of the project. For unit based projects, the
11 plan was for engineering to take place in the same year that the work was
12 to take place. Subsequent to that filing, NIPSCO determined it needed to
13 accelerate the engineering in the plan for several reasons.
14 First, for single unit projects, where the projects are larger in scope and
15 more complex than unit based projects, NIPSCO found that the time to
16 engineer projects was hindering its ability to successfully plan and execute
17 the work. In this case, these projects take longer to engineer (6‐9 months)
18 and usually have long lead material items that need to be ordered several
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 34
1 months prior to construction (i.e., power transformers, breakers). These
2 projects also take longer to construct and usually require part of the system
3 to be “cleared” or to have the assets being replaced isolated from the
4 electrical transmission or distribution system and de‐energized so the work
5 can be performed safely. Clearances are more difficult to obtain during the
6 summer months due to loading on the system, which drives the need to
7 begin construction in the early part of the year to avoid system constraints
8 during the summer months. The aggregate of these factors limited
9 NIPSCO’s ability to successfully engineer projects in the prior year and be
10 ready to execute the projects in the early part of the following year.
11 Second, for projects such as underground cable, pole replacement and
12 circuit performance, the time required to engineer the projects encumbered
13 NIPSCO’s ability to successfully plan and construct the work in the same
14 year. For example, on underground cable replacement, if engineering took
15 the first 4‐6 months of the year, planning and constructing the work would
16 take place in the remaining 8‐6 months. A good portion of the 8‐6 months
17 could be lost to inclement weather, reducing the probability of completing
18 the work in the calendar year.
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 35
1 Third, NIPSCO found that to be successful during the construction phase
2 of completing the portfolio of work, it needed to have a resource plan that
3 would allow the Company to orchestrate all the activities for each
4 construction year. The resource plan takes time to develop and requires
5 detailed engineering to be completed, a full understanding of construction
6 resources available and the ability to make portions of NIPSCO’s system
7 cleared for construction.
8 For the above reasons, and in an effort to better plan and execute the
9 portfolio of work in the 7‐Year Plan, NIPSCO decided to transition to
10 having engineering complete 24 months in advance of construction, which
11 requires an acceleration of the engineering expenditures relative to the
12 original 7‐Year Plan filing. The benefits of this change include the fact that,
13 in the first two years of the 7‐Year Plan, NIPSCO will have engineered four
14 years of the Plan. From January 1, 2016 until now, NIPSCO has been
15 engineering at a pace to accomplish the goal of 24 months in advance of
16 construction. At the end of 2018 NIPSCO will have completed the
17 engineering for the 2020 portfolio of work, which will allow the Company
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 36
1 to better plan for the construction of the portfolio of projects in each
2 calendar year.
3 In addition, in Plan Update‐3, NIPSCO separated each of the engineering
4 categories into two parts, engineering and pre‐construction. This was done
5 to add clarity around what work was being completed in a prior year before
6 construction began.
7 Q45. Please explain why NIPSCO added a Project ID for pre‐construction
8 activities in Plan Update‐3 and continues to do so in Plan Update‐4.
9 A45. It is important to complete site preparation, environmental studies, land
10 and easement purchases, and project management planning for projects
11 planned for the following year. In an effort to provide greater transparency
12 into these activities, NIPSCO has added a Project ID related to the pre‐
13 construction activities. The environmental studies need to be completed
14 the year prior to construction to allow adequate time for the delineations to
15 be completed and all needed permits and/or plans to be developed and
16 submitted. All land and easement purchases need to be completed in the
17 year prior to construction to ensure no scope changes are incurred during
18 construction due to land rights and access. Project Management will begin
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 37
1 developing execution schedules, request quotes and estimates for material
2 and contracted services, complete contracted bid events, and conduct pre‐
3 construction meetings for projects to ensure construction can commence as
4 scheduled. As with engineering 24 months prior to construction start, these
5 expenditures prior to the year of construction allow the projects to begin
6 earlier in the year and be completed timely. In addition, it allows for
7 effective use of labor, which is critical for completion of the 7‐Year Plan.
8 Q46. Please explain how the cost estimates are calculated for engineering
9 projects (i.e., the Substation Engineering – Transmission Project).
10 A46. For each project in the Plan, a portion of the total project cost estimate is
11 placed in the respective Engineering project two years prior to the year the
12 project is to be constructed. The total project cost estimate is developed by
13 applying a parametric value, based on the type of work, historical costs and
14 anticipated level of effort. The technique used to develop a parametric
15 estimate involves utilizing an algorithm to calculate cost or duration of a
16 project, based upon historical data and project parameters. The parametric
17 estimates used as unit costs within NIPSCO’s plan are a Class 4 estimate,
18 which represents a 1‐15% project definition level. To derive the cost
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 38
1 estimate for each of the five engineering category projects in the Plan,
2 NIPSCO aggregated a percentage, from each individual parametric cost
3 estimate for each respective engineering category. The five engineering
4 category project cost estimates have been, and will continue to be, based on
5 a percentage of the parametric cost estimates. For example, the amount
6 included for engineering a 138kV Relay Upgrade is 4% and the amount
7 included for engineering a 138/69kV Transformer is 9%. Actual project
8 engineering may cost more or less than the percentage included in the total
9 project budget as part of the parametric process.
10 Q47. Please identify the engineering categories used for estimating
11 engineering costs.
12 A47. There are five engineering categories used for estimating costs: (1)
13 Substation Engineering – Transmission (Project ID TSE1), (2) Substation
14 Engineering – Distribution (Project ID DSE1), (3) Line Engineering –
15 Transmission (Project ID TLE1), (4) Line Engineering – Distribution (Project
16 ID DLE1), and (5) 4kV Line Engineering (Project ID D4KVLE1). The sum
17 of all five categories capture the engineering related costs for the different
18 types of work in the Plan. NIPSCO utilized these different categories of
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 39
1 parametric estimates due to a level of variability based on the type of work,
2 and in future filings the estimates may need to be reallocated to more
3 accurately represent the level of effort based on each type of engineering
4 being conducted. NIPSCO is constantly assessing all estimates and
5 adjusting cost estimates both up and down based on actual cost and
6 forward looking market fluctuations
7 Q48. Please explain what the impact is for the difference between a parametric
8 engineering estimate and the actual engineering.
9 A48. As NIPSCO’s modernization plan is executed, the actual costs for
10 engineering vary depending on the complexity of the project and resources
11 utilized to complete the work. For example, within the Substation
12 Engineering – Transmission project category, when the Plan was
13 developed, on average, 7% of the total project cost was included from the
14 total parametric project cost estimate, when aggregated from all projects in
15 this category. However, a review of the actual costs for the transmission
16 substation category of projects engineered in 2017 placed the average at
17 approximately 10‐11% of the total project cost. This was driven by the need
18 to outsource portions of engineering that in the past were completed
REDACTED Petitioner's Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733-TDSIC-4 Page 40
1 internally due to labor constraints and due to the complexity of some of the
2 projects.
3 Q49. How do the total projected capital expenditures for Plan Update-4
4 compare to the total projected capital expenditures for Plan Update-3?
5 A49. Table 1 shows the total projected capital expenditures, including indirect
6 capital costs and AFUDC, for Plan Update-4 compared to Plan Update-3.
Table 1 Comparison of Total Capital Dollars (inclnsive of indirect capital c:osts and AFUDC)
Year l Year 2 Year32018 Year4 2019 Years Year 6 Year7 Total 2016 2017 2020 2021 2022
Plan Update-3 $129,450,119 $131,277,544 $172,896,441 $225,110,233 $2U,786,469 $213,924,240 $220,282,838 $1,305,727,884 Plan Update-4 $129,450,119 $129,062,922 $160,594,414 $227,554,896 $203,984,945 $212,840,928 $231,321,274 $1,294,809,498 Variance $0 ($2,214,622) ($12,302,027) $2,444,663 ($8,801,524) ($1,083,312) $11,038,436 ($10,918,386) 7 8 QSO. Please explain how AFUDC in this filing compares to Plan Update-3.
9 A50. In this filing, AFUDC is decreasing by $506,104, which is based on an
10 overall 7-Year Plan AFUDC percentage of 2.3%. NIPSCO updated the
11 AFUDC percentages in this filing using a 3-year historical average. The
12 AFUDC percentage is calculated by dividing AFUDC by total direct capital
13 and plus indirect capital. The in-service timing assumptions follow that
14 70% of the current year capital is assumed to go in service in the current
15 year and 40% of that current year capital is assumed to go in service in the REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 41
1 fourth quarter of that year. In addition, 30% of the previous year capital is
2 assumed to go in service in the following year. For example, 70% of the
3 2018 capital expenditures go into service in 2018 and 30% of the 2017 capital
4 expenditures go into service in 2018. The AFUDC percentage for the overall
5 7‐Year Plan in Plan Update‐4 is 2.3% compared to 2.3% in Plan Update‐3.
6 The actual AFUDC percentage from January 1, 2016 through May 31, 2018
7 was 2.7%.
8 Q51. Does NIPSCO have a process for reviewing and updating system
9 deliverability projects?
10 A51. Yes. As part of NIPSCO’s annual planning cycles, both distribution and
11 transmission projects are reviewed and evaluated. Adjustments are made
12 to the projects to meet the needs of the electric system.
13 Q52. Have any projects reviewed by NIPSCO been determined to be
14 appropriate for inclusion in the System Deliverability category in this
15 filing?
16 A52. No.
17 2017 PROJECTS
18 Q53. Please explain the overall change from Plan Update‐3 to Plan Update‐4 REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 42
1 for 2017.
2 A53. There is an overall decrease in direct costs in 2017 of $2,349,213 (cost
3 efficiencies of $1,953,080 and net moves out of 2017 of $396,133).
4 Q54. Did NIPSCO move any Projects to 2017 that were previously included in
5 a different year in Plan Update‐3?
6 A54. Yes. As shown in Confidential Attachment 3‐B, these are the projects that
7 moved into 2017:
8 Potential Transformer Projects – Transmission [Project ID TSPT1]. 9 Moved $ in direct costs for three potential transformers from 10 2018 to 2017 due to an advanced material purchase.
11 Rebuild Mitchell Substation 138kV Yard [Project ID TSNRS1]. 12 Moved $ in direct costs for one arrester from [Project ID TSA1] 13 2017 to 2017 due to coordination of effort with other TDSIC project 14 work scheduled in 2017.
15 Underground Cable Replacement Projects [Project ID DUG1]. 16 Moved $ in direct costs for one project from 2018 to 2017 due 17 to advanced conduit installation and from 2019 to 2017 due to age 18 and condition.
19 Recloser Replacement Projects – Distribution [Project ID DSBRU1]. 20 Moved $ in direct costs for sixteen reclosers from 2018 to 2017 21 due to an advanced material purchase.
22 Potential Transformer Projects – Distribution [Project ID DSPT1]. 23 Moved $ in direct costs for three potential transformers from 24 2018 to 2017 due to an advanced material purchase.
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 43
1 Dune Acres 34kV Relay Upgrade with Breakers [Project ID DSRU2]. 2 Moved $ in direct costs from [Project ID TSB1] 2017 to 2017 3 due to coordination of effort with other TDSIC project work 4 scheduled in 2017.
5 Q55. Please identify the variances in updated direct costs for the 2017 Projects
6 as compared to the best estimates of the direct costs identified in Plan
7 Update‐3.
8 A55. Plan Update‐4, 2017 Project Detail (Page 7) shows the Approved Project
9 Cost (direct) for the 2017 Projects was $112,676,041 (Column F), the
10 Updated Project Cost (direct) is $110,326,8284 (Column G), for a total
11 decrease of $2,349,213 (Column H).
12 Q56. Please explain what drove the noteworthy cost increases for the 2017
13 Projects.
14 A56. As shown in the Confidential Attachment 3‐B, the following projects show
15 cost increases greater than $100,000 or 20%, whichever is greater, over what
16 was approved in Plan Update‐3:
17 Battery & Charger Equipment Projects – Transmission [Project ID 18 TSB1] [$ (39%)]. Material costs were higher than anticipated. 19 The size of the batteries required to support the equipment at these 20 locations was determined to be larger than what was originally 21 estimated. Based on the amount of equipment being supplied by the 22 batteries there was a need to increase the size of the batteries and 23 charging station for several of the units. This caused the material
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1 costs and installation labor to be higher than what was in the 2 previous estimate. These batteries are used to provide emergency 3 power to station equipment in the event station service is disrupted.
4 Install Fiber Optic Static from St. John to Enbridge‐13834 [Project ID 5 TSRU9] [$ (9%)]. The design of the fiber optic cable run into 6 the substation was changed to eliminate the need for an electrical 7 outage to complete the work. The project was originally designed to 8 bring the fiber optic cable into the A‐frame substation pull‐off 9 structure. This design was changed to include the installation of a 10 new pole and conduit to run the fiber optic cable back to the relay 11 house. This change was necessary to increase physical electric 12 separation associated with the routing the fiber optic conductor from 13 the transition structure to the control house mitigating the electrical 14 outage coordination constraint. This design increased the cost of 15 material and labor, and hydro excavation was required to install the 16 conduit.
17 Install Microwave Path from Flint Lake to Luchtman‐13873 [Project 18 ID TSRU10] [$ (23%)]. During construction, an underground 19 utility conflict was identified associated with the existing foundation 20 layout. Foundations were modified to accommodate the conflict. 21 Soil conditions also impacted the foundation design requiring 22 additional depth than in the original estimate. These changes 23 increased material and labor cost associated with the project. Please 24 note: due to resource availability and the issues that arose while 25 completing the project, the work, including alignment and 26 commissioning was not complete until 2018.
27 Line Switch Projects – Transmission [Project ID TLSW1] [$ 28 (25%)]. This transmission line switch project consisted of seven 29 transmission switch replacements. To complete some of the project, 30 coordination of equipment outages during nights or weekends was 31 required to minimize the impact to customers. The additional work 32 hours and the utilization of contracted electrical workers increased 33 the labor associated with the project.
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1 Line Switch Projects – Distribution [Project ID DLSW2] [$ 2 (35%)]. The distribution line switch project consisted of nine 3 switches to be replaced. The cost increase for this project is 4 associated with coordination of electrical outages to complete the 5 work during nights and weekends to minimize impact to customers, 6 which increased the number of work hours and utilization of 7 contracted electrical workers, which also contributed to the increase 8 in cost.
9 2018 PROJECTS
10 Q57. Please explain the overall change from Plan Update‐3 to Plan Update‐4
11 for 2018.
12 A57. There is an overall decrease in direct costs in 2018 of $10,744,000 (cost
13 decreases of $6,318,250 and net moves out of 2018 of $4,425,750).
14 Q58. Did NIPSCO move any Projects to 2018 that were previously included in
15 a different year in Plan Update‐3?
16 A58. Yes. As shown in Confidential Attachment 3‐B, these were the projects that
17 moved into 2018:
18 Arrester Projects – Transmission [Project ID TSA1]. Moved $ 19 in direct costs for one arrester from 2020 to 2018 due to imminent 20 failure.
21 Battery & Charger Equipment Projects – Transmission [Project ID 22 TSB1]. Moved $ in direct costs for two chargers from 2017 and 23 one battery and charger from 2022 to 2018 due to coordination of 24 effort with other TDSIC project work scheduled in 2018.
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1 Install Microwave Path from Flint Lake to Luchtman‐13873 [Project 2 ID TSRU10]. Moved $ in direct costs from 2017 to 2018 due to 3 the alignment of the equipment on the towers not being completed 4 in 2017.
5 Relay & Breaker Upgrade – Dune Acres to MCGS – 13839 [Project ID 6 TSRU46]. Moved $ in direct costs from 2020 to 2018 due to 7 the bushings failing inspection.
8 Breaker Replacement – Chicago Ave – 13811‐29 [Project ID 9 TSBRU16]. Moved $ in direct costs for one breaker from 2022 10 to 2018 due to imminent failure.
11 Substation Pre‐construction – Transmission [Project ID TSPC1]. 12 Moved $ in direct costs from 2019 transmission substation 13 projects [Project IDs TSRU30, TSRU32, TSRU33, TSRU34, TSRU35, 14 TSRU37, TSRU38, TSRU40, TSRU42, TSNRS7, TSNRS8, TSNRS9, 15 and TSNRS15] to 2018 to accurately represent work required prior to 16 project commencement.
17 Substation Engineering – Transmission [Project ID TSE1]. Moved 18 $ in direct costs for engineering one breaker from 2020 to 2018 19 due to imminent failure.
20 Circuit 3465 Rebuild – 69kV Laporte JCT to Tee Lake [Project ID 21 TLNRL6]. Moved $ in direct costs from 2017 to 2018 due to 22 ground conditions and weather constraints.
23 Line Pre‐construction – Transmission [Project ID TLPC1]. Moved 24 $ in direct costs from 2019 transmission line projects [Project 25 IDs TLNRL13 and TLNRL14] to 2018 to accurately represent work 26 required prior to project commencement.
27 Underground Cable Replacement Projects [Project ID DUG1]. 28 Moved $ in direct costs for one project from 2017 to 2018 due 29 to coordination of effort with other TDSIC project work scheduled in 30 2018.
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1 Potential Transformer Projects – Distribution [Project ID DSPT1]. 2 Moved $ in direct costs for three potential transformers from 3 2019 to 2018 due to imminent failure.
4 Power Transformer Projects – Distribution [Project ID DSTU1]. 5 Moved $ in direct costs for one transformer from 2019 to 6 2018 due to imminent failure.
7 Replace Breaker – Wheeler ‐ #1 XFMR BKR, #2 XFMR BKR [Project 8 ID DSBRU7]. Moved $ in direct costs for two transmission 9 substation switches from 2021 [Project ID TSSW1] to 2018 due to 10 coordination of effort with other TDSIC project work scheduled in 11 2018.
12 Rebuild Substation – Willowdale ‐ #1 Transformer and #1 XFMR 13 BKR [Project ID DSNRS14]. Moved $ in direct costs for one 14 transmission substation switch from 2021 [Project ID TSSW1] to 2018 15 due to coordination of effort with other TDSIC project work 16 scheduled in 2018.
17 New Valparaiso Substation Land [Project ID DSNRS25]. Moved 18 $ in direct costs from 2021 [Project ID DSNRS9] to 2018 to 19 coordinate efforts associated with engineering and construction of 20 the New Valparaiso substation in 2020.
21 Substation Pre‐construction – Distribution [Project ID DSPC1]. 22 Moved $ in direct costs from 2019 ($ ) distribution 23 substation projects [Project IDs DSRU5, DSBRU9, DSBRU11, 24 DSBRU12, DSBRU13, DSBRU14, DSTU7, DSTU9, DSTU10, DSTU11, 25 DSNRS18, DSNRS19, and DSNRS20] and from 2020 ($ ) 26 distribution substation project [Project ID DSBRU3] to 2018 to 27 accurately represent work required prior to project commencement.
28 Substation Engineering ‐ Distribution [Project ID DSE1]. Moved 29 $ in direct costs for engineering three breakers from 2020 30 [Project IDs DSE1 and TSE1] to 2018 due to coordination of effort 31 with other TDSIC project work scheduled in 2018.
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1 Line Switch Projects – Distribution [Project ID DLSW2]. Moved 2 $ in direct costs for two line switches from 2017 to 2018 due to 3 customer coordination.
4 Circuit Rebuild – Mississippi – 12‐656 [Project ID DLNRL39]. Moved 5 in direct costs for one feeder cable from 2019 and associated 6 project pre‐construction from 2018 [Project ID DLPC1] to 2018 due 7 to imminent failure.
8 Line Pre‐construction – Distribution [Project ID DLPC1]. Moved 9 in direct costs from 2019 distribution line projects [Project 10 IDs DLNRL33 and DLNRL34] to 2018 to accurately represent work 11 required prior to project commencement.
12 LED Street Lighting [Project ID DLED1]. Moved $ in direct 13 costs from 2019 to 2018 due to an advanced material purchase.
14 Q59. Please identify the variances in updated direct costs for the 2018 Projects
15 as compared to the best estimates of the direct costs identified in Plan
16 Update‐3.
17 A59. Plan Update‐4, 2018 Project Detail (Page 12) shows the Approved Project
18 Cost (direct) for the 2018 Projects was $150,999,405 (Column F), the
19 Updated Project Cost (direct) is $140,255,405 (Column G), for a total
20 decrease of $10,744,000 (Column H).
21 Q60. Please explain what drove the noteworthy cost increases for the 2018
22 Projects.
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1 A60. As shown in Confidential Attachment 3‐B, the following projects show cost
2 increases greater than $100,000 or 20%, whichever is greater, over what was
3 approved in Plan Update‐3:
4 Install Microwave Path from Flint Lake to Luchtman‐13873 [Project 5 ID TSRU10] [$ (200%)]. In 2018, the remainder of the work 6 was completed at Michigan City and Luchtman substations, along 7 with all of the work at the Maple substation. This allowed for the 8 alignment and commissioning to be completed. During the 9 alignment, adjustments were needed to the bracket on the tower to 10 achieve proper alignment, which increased labor and extended the 11 project duration due to the availability of structure crews. In 12 addition, print adjustments required additional labor for the inside 13 wiring. Work was required at Luchtman, Michigan City and Maple 14 Substations.
15 Fiber Optic ‐ Hiple to Goshen Junction – 138103 [Project ID TSRU20] 16 [$ (15%)]. The estimated cost increase for this project is driven 17 by the electric outage constraint reducing the number of work days 18 available to complete the project. The amount of time granted for this 19 line to be out of service for construction was reduced from what was 20 originally planned. For one part of the project, the original clearance 21 of four months was restricted to weekend work only. On another 22 part of the project, the clearance was reduced by approximately four 23 weeks due to coordination with other projects. This reduction in 24 construction time resulted in the need for extended work days, 25 weekends and additional resources to complete the project on 26 schedule. There are also additional costs for project support during 27 the extended work hours and for previously unidentified hydro 28 excavation to expose underground utilities in close proximity to 29 excavation sites.
30 Relay & Breaker Upgrade ‐ Dune Acres to MCGS ‐ 13839 [Project ID 31 TSRU46] [$ (104%)]. Replace Dune Acres substation circuit 32 13839 (138kV, 2000 Amp, oil circuit breaker) with a new circuit
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1 breaker. Recent inspection and testing of the existing breaker 2 indicated imminent failure. This resulted in removal of it from 3 service and expedited replacement.
4 Potential Transformer Projects – Distribution [Project ID DSPT1] 5 [$ (62%)]. The increase in cost is due to an increase in material 6 and labor costs to install steel stand extensions for three of the 7 potential transformers. The new assets are shorter than the existing 8 units requiring the installation of extensions on the steel structures. 9 An increase was also seen in the rental equipment as a crane was 10 needed, which was not part of the original estimate.
11 Court #1 Switch Gear Replacement [Project ID DSNRS8] [$ 12 (428%)]. Project was extended by three months into 2018. At the 13 start of the project, the clearance was returned due to high 14 temperatures causing a delay in the start of construction. During 15 construction, it was determined that an extension was required to be 16 added to the end of the existing switchgear to accommodate 17 termination of the bus tie medium voltage cables. This was required 18 due to the entrance angle of existing cables to facilitate proper 19 working space. During construction of the new equipment 20 foundations, the water table was elevated, increasing the amount of 21 dewatering required. As construction progressed into the winter 22 months, weather caused work delays in the field. During the 23 installation of a feeder cable, the integrity of the existing conduit was 24 unexpectedly found to be compromised. This required a new 6 inch 25 conduit bore from the substation to the terminal pole to complete 26 installation of the feeder cable. This is a multiple year project and 27 the total project increase is $ dollars, or a 21% increase.
28 OʹLeary Substation Associated 12kV Lines [Project ID DLNRL25] 29 [$ (26%)]. After additional review of the O’Leary substation 30 and its location, it was determined the substation would have a 31 negative impact on system reliability if not integrated into adjacent 32 distribution automation systems. It was determined that additional 33 switches, controls and communications equipment would be 34 necessary to integrate the substation and circuits maintaining 35 existing system performance and reliability. This was identified after
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1 additional engineering was performed assessing existing control 2 systems installed on the distribution system. Additional equipment 3 and labor for installation and support were required to integrate the 4 O’Leary substation with the existing systems at Ainsworth and 5 Southlake substations.
6 Line Pre‐construction – Distribution [Project ID DLPC1] [$ 7 (51%)]. Once detailed engineering and constructability reviews were 8 completed, the amount of site preparation work estimated to be 9 required to complete construction in 2019 is higher than previous 10 pre‐construction allocations.
11 2019 PROJECTS
12 Q61. Please explain the overall change from Plan Update‐3 to Plan Update‐4
13 for 2019.
14 A61. There is an overall increase in direct costs in 2019 of $2,158,888 (cost
15 decreases of $3,568,551 and net moves into 2019 of $5,727,439).
16 Q62. Did NIPSCO move any Projects to 2019 that were previously included in
17 a different year in Plan Update‐3?
18 A62. Yes. As shown in Confidential Attachment 3‐B, these were the projects that
19 moved into 2019:
20 Install Fiber Optic Cable [Project ID TSRU17]. Moved three projects 21 and assigned new Project IDs as follows:
22 Fiber Optic – Green Acres to St. John – 13888 [Project ID 23 TSRU29]. Moved $ in direct costs from 2018 to 2019 to
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1 accurately represent work required prior to project 2 commencement.
3 Fiber Optic – Miller to Burns – 13810 [Project ID TSRU30]. 4 Moved $ in direct costs from 2018 to 2019 to accurately 5 represent work required prior to project commencement.
6 Fiber Optic – Munster to Taney – 13895 [Project ID TSRU31]. 7 Moved $ in direct costs from 2018 to 2019 to accurately 8 represent work required prior to project commencement.
9 Breaker Replacement – Burns Ditch – 13810‐37, 13838‐#1, 13810‐#1 10 [Project ID TSBRU7]. Moved $ in direct costs from 2018 to 11 2019 due to clearance constraints.
12 Replace 69kV Breakers [Project ID TSBRU3]. Moved one project and 13 assigned a new Project ID as follows:
14 Breaker Replacement – Lagrange Breaker Upgrades (69kV) 15 [Project ID TSBRU8]. Moved $ in direct costs from 2018 16 to 2019 to accurately represent work required prior to project 17 commencement.
18 Munster 34504‐22 BKR [Project ID TSBRU6]. Moved one project and 19 assigned a new Project ID as follows:
20 New/Rebuild Substation – Munster 345/138kV Transformer 21 Upgrade; 34504‐22 BKR; #2 XFR 138kV & 13894‐#2 XFR 22 [Project ID TSNRS15]. Moved $ in direct costs for one 23 breaker from 2020 to 2019 due to coordination of effort with 24 other TDSIC project work scheduled in 2019.
25 Substation Deliverability Projects – Transmission [Project ID 26 TSNRS4]. Moved one project and assigned a new Project ID as 27 follows:
28 New/Rebuild Substation – Munster 345/138kV Transformer 29 Upgrade; 34504‐22 BKR; #2 XFR 138kV & 13894‐#2 XFR 30 [Project ID TSNRS15]. Moved $ in direct costs for
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1 one transformer upgrade from 2022 to 2019 due to 2 coordination of effort with other TDSIC project work 3 scheduled in 2019.
4 138kV Lagrange Ring Bus; Relay & Breaker Upgrade – Hiple to 5 Lagrange – 13809 [Project ID TSNRS5]. Moved $ in direct 6 costs from 2018 to 2019 due to clearance constraints.
7 Substation Pre‐construction – Transmission [Project ID TSPC1]. 8 Moved $ in direct costs from 2018 ($ ) Substation Pre‐ 9 construction ‐ Transmission [Project ID TSPC1] and 2020 ($ ) 10 transmission substation projects [Project IDs TSRU17, TSRU18, 11 TSRU19, TSBRU1, TSBRU2, TSBRU3, TSTU2, TSTU3, and TSNRS4] 12 to 2019 to accurately represent work required prior to project 13 commencement.
14 Substation Engineering – Transmission [Project ID TSE1]. Moved 15 $ in direct costs for engineering one breaker from 2020 to 2019 16 due to coordination of effort with other TDSIC project work 17 scheduled in 2021.
18 Line Switch Projects – Transmission [Project ID TLSW1]. Moved 19 $ in direct costs for one line switch from 2022 to 2019 due to 20 coordination of effort with other TDSIC project work scheduled in 21 2019.
22 Circuit 3465 Rebuild – 69kV Laporte JCT to Tee Lake [Project ID 23 TLNRL6]. Moved $ in direct costs from 2018 to 2019 due to 24 customer coordination.
25 Circuit 3465 Rebuild – New Carlisle to Olive [Project ID TLNRL9]. 26 Moved $ in direct costs from 2018 to 2019 due to customer 27 coordination.
28 Line Pre‐construction – Transmission [Project ID TLPC1]. Moved 29 $ in direct costs from 2020 transmission line projects [Project 30 IDs TLNRL4 and TLNRL5] to 2019 to accurately represent work 31 required prior to project commencement.
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1 Underground Cable Replacement Projects [Project ID DUG1]. 2 Moved $ in direct costs for one project from 2018 ($ ) 3 to 2019 due to coordination of effort with other TDSIC project work 4 scheduled in 2019, and seven projects from 2020 () to 2019 5 due to imminent failure. The circuits represented by these projects 6 have shown a degrading performance level and needed to be 7 completed sooner than originally anticipated.
8 4kV Conversion – Line Rebuild [Project ID D4KVL8]. Moved four 9 projects and assigned new Project IDs as follows:
10 4kV Conversion – Chase – 18341 [Project ID D4KVL11]. 11 Moved $ in direct costs from 2018 to 2019 to accurately 12 represent work required prior to project commencement.
13 4kV Conversion – Hobart Road ‐ 21242 [Project ID D4KVL12]. 14 Moved $ in direct costs from 2018 to 2019 to accurately 15 represent work required prior to project commencement.
16 4kV Conversion – Gary Heights – 18342 [Project ID 17 D4KVL13]. Moved $ in direct costs from 2018 to 2019 to 18 accurately represent work required prior to project 19 commencement.
20 4kV Conversion – Hobart Road ‐ 21343 [Project ID D4KVL14]. 21 Moved $ in direct costs from 2018 to 2019 to accurately 22 represent work required prior to project commencement.
23 4kV Line Pre‐construction [Project ID D4KVLPC1]. Moved $ 24 in direct costs from 2020 4kV Conversion – Line Rebuild [Project ID 25 D4KVL8] to 2019 to accurately represent work required prior to 26 project commencement.
27 Recloser Replacement Projects – Distribution [Project ID DSBRU1]. 28 Moved $ in direct costs for two reclosers from 2019 [Project 29 ID DSNRS16] due to separating from a larger project that is moving 30 to 2022. Specifically, two oil reclosers, are being completed in 2019, 31 with the remainder of the project taking place in 2022.
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1 Replace 34kV Breakers [Project ID DSBRU2]. Moved one project and 2 assigned a new Project ID as follows:
3 Breaker Upgrade – Columbia Ave 3421 BKR [Project ID 4 DSBRU8]. Moved $ in direct costs from 2018 to 2019 to 5 accurately represent work required prior to project 6 commencement.
7 Replace 12kV Breakers [Project ID DSBRU3] Moved two projects and 8 assigned new Project IDs as follows:
9 Breaker Upgrade – Liberty Park Switch Gear [Project ID 10 DSBRU10]. Moved $ in direct costs from 2018 to 2019 to 11 accurately represent work required prior to project 12 commencement.
13 Breaker Upgrade – McKinley Breaker and Recloser Upgrade 14 (12kV) [Project ID DSBRU11]. Moved $ in direct costs 15 for two distribution LTCs and one battery and charger from 16 [Project IDs DSRU3 and DSB1] 2019 ($ ) and five 17 distribution switches to clear incoming lines from [Project ID 18 DLSW1] 2022 ($ ) to 2019 due to coordination of effort 19 with other TDSIC project work scheduled in 2019.
20 Replace Breaker – Schererville – Switch Gear [Project ID DSBRU6]. 21 Moved $ in direct costs from 2018 to 2019 due to land 22 procurement.
23 Replace 12kV Transformers [Project ID DSTU4]. Moved $ in 24 direct costs from 2018 to 2019 to accurately represent work required 25 prior to project commencement. Moved three projects and assigned 26 new Project IDs as follows:
27 Replace Transformer – Freyer #2 34/12kV [Project ID DSTU8]. 28 Moved in direct costs from 2018 to 2019 to accurately 29 represent work required prior to project commencement.
30 Rebuild Substation – Colfax #2 XFMR and Switchgear [Project 31 ID DSNRS18]. Moved $ in direct costs for one battery
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1 and charger from [Project ID DSB1] 2020 to 2019 due to 2 coordination of effort with other TDSIC project work 3 scheduled in 2019.
4 Rebuild Substation – Warsaw #3 & #4 Transformer and 5 Recloser Upgrade [Project ID DSNRS20]. Moved in 6 direct costs for two breakers from [Project ID TSBRU3] 2022 7 to 2019 due to coordination of effort with other TDSIC project 8 work scheduled in 2019.
9 Substation Deliverability Projects – Distribution [Project ID 10 DSNRS11]. Moved one project and assigned new Project ID as 11 follows:
12 Replace Transformer – Honey Creek #1 and #2 69/12kV 13 [Project ID DSNRS21]. Moved $ in direct costs from 2018 14 to 2019 to accurately represent work required prior to project 15 commencement.
16 Substation Pre‐construction – Distribution [Project ID DSPC1]. 17 Moved $ in direct costs from 2020 distribution substation 18 projects [Project IDs DSRU4, DSBRU2, DSBRU3, DSTU3, DSTU4, 19 and DSNRS10] to 2019 to accurately represent work required prior 20 to project commencement.
21 Circuit 3433 Rebuild – Grandview to Bendix West Side [Project ID 22 DLNRL24]. Moved $ in direct costs from 2018 to 2019 due to 23 customer coordination.
24 Rebuild 12kV Circuits (Miles) [Project ID DLNRL18]. Moved eleven 25 projects and assigned new Project IDs as follows:
26 Circuit Rebuild – Virginia – 12‐412 [Project ID DLNRL31]. 27 Moved $ in direct costs from 2018 to 2019 to accurately 28 represent work required prior to project commencement.
29 Circuit Rebuild – Freyer – 12‐268 [Project ID DLNRL32]. 30 Moved $ in direct costs from 2018 to 2019 to accurately 31 represent work required prior to project commencement.
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1 Circuit Rebuild – Roxana – 12‐316 [Project ID DLNRL35]. 2 Moved $ in direct costs from 2018 to 2019 to accurately 3 represent work required prior to project commencement.
4 Circuit Rebuild – Waterloo – 1299 [Project ID DLNRL36]. 5 Moved $ in direct costs from 2018 to 2019 to accurately 6 represent work required prior to project commencement.
7 Circuit Rebuild – Wolcottville ‐ 1231 [Project ID DLNRL37]. 8 Moved $ in direct costs from 2018 to 2019 to accurately 9 represent work required prior to project commencement.
10 Circuit Rebuild – Highland – 12‐444 [Project ID DLNRL38]. 11 Moved $ in direct costs from 2018 to 2019 to accurately 12 represent work required prior to project commencement.
13 Circuit Rebuild – Mississippi – 12‐656 [Project ID DLNRL39]. 14 Moved $ in direct costs from 2018 to 2019 to accurately 15 represent work required prior to project commencement.
16 Circuit Rebuild – Hyde Park – 12‐291 [Project ID DLNRL40]. 17 Moved $ in direct costs from 2018 to 2019 to accurately 18 represent work required prior to project commencement.
19 Circuit Rebuild – North Judson – 12‐222 [Project ID 20 DLNRL41]. Moved $ in direct costs from 2018 to 2019 21 to accurately represent work required prior to project 22 commencement.
23 Circuit Rebuild – South Hammond – 12‐720 [Project ID 24 DLNRL42]. Moved $ in direct costs from 2018 to 2019 25 to accurately represent work required prior to project 26 commencement.
27 Circuit Rebuild – Tilden – 12‐650 [Project ID DLNRL43]. 28 Moved $ in direct costs from 2018 to 2019 to accurately 29 represent work required prior to project commencement.
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1 Line Deliverability Projects ‐ Distribution [Project ID DLNRL19]. 2 Moved two projects and assigned new Project IDs as follows:
3 Circuit Rebuild – North Liberty Sub Feeder [Project ID 4 DLNRL44]. Moved $ in direct costs for four distribution 5 switches to clear incoming lines from [Project ID DLSW1] 6 ($ ) and line pre‐construction – distribution [Project ID 7 DLPC1] ($ ) from 2018 to 2019 due to coordination of 8 effort with other TDSIC project work scheduled in 2019 and 9 to accurately represent work required prior to project 10 commencement.
11 Circuit Rebuild – Wakarusa 1291 Tap [Project ID DLNRL45]. 12 Moved in direct costs from 2018 to 2019 to accurately 13 represent work required prior to project commencement.
14 Line Pre‐construction – Distribution [Project ID DLPC1]. Moved 15 $ in direct costs from 2020 distribution line projects [Project 16 IDs DLNRL16, DLNRL18 and DLNRL19] to 2019 to accurately 17 represent work required prior to project commencement.
18 Q63. Please provide some examples of why NIPSCO moved projects from one
19 Project ID to another in 2019?
20 A63. As further explained in Question / Answer 42 above, NIPSCO’s initial
21 TDSIC Plan included detailed estimates for 2016 and 2017 and parametric
22 estimates for 2018 – 2022. Once NIPSCO has a detailed estimate for a
23 project, NIPSCO establishes a Project ID and Project Name and includes
24 that in the Plan update. In some cases, a project that was previously
25 included in the Plan as a grouped project is broken out into a specific asset
26 or location. In other cases, dollars move from multiple projects to one
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1 specific project. In some cases, the total project cost did not change from
2 Plan Update‐3 to Plan Update‐4.
3 The 2019 Project Mapping (Confidential Appendix 8) provides a guide to
4 illustrate where a project was previously included in Plan Update‐3 and
5 where it is now included in Plan Update‐4. 2019 projects from Plan Update‐
6 3 were displayed to show common groupings (for example, Install Fiber
7 Optic Cable [Project ID TSRU17]), and the specific asset or location was
8 included in the Asset Register. Many 2019 projects that previously had an
9 estimate in Plan Update‐3 now show an Updated Project Cost of zero. On
10 the other hand, there are projects that previously had an Approved Project
11 Cost of zero, but now have an Updated Project Cost. In other words, the
12 group has been zeroed out and the dollars moved to the more descriptive
13 project IDs.
14 For an example to illustrate a project move, please refer to Plan Update‐4,
15 page 15, lines 6, 9, 10, and 11. Install Fiber Optic Cable [Project ID TSRU17]
16 is now broken down into three projects (1) Fiber Optic – Green Acres to St.
17 John ‐ 13888 [Project ID TSRU29], (2) Fiber Optic & Relay Upgrade – Miller
18 to Burns Ditch – 13810 [Project ID TSRU30], and (3) Fiber Optic – Munster
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1 to Taney ‐ 13895 [Project ID TSRU31]. This example also has dollars moving
2 from a unit based project to one of the specific projects, Fiber Optic & Relay
3 Upgrade – Miller to Burns Ditch – 13810 [Project ID TSRU30]. The total cost
4 of Install Fiber Optic Cable [Project ID TSRU17] in Plan Update‐3 was
5 $ and is now $0 in Plan Update‐4. Fiber Optic – Green Acres to St.
6 John ‐ 13888 [Project ID TSRU29] cost was previously $0 and is now
7 $ , Fiber Optic & Relay Upgrade – Miller to Burns Ditch – 13810
8 [Project ID TSRU30] was previously $0 and is now and Fiber
9 Optic – Munster to Taney ‐ 13895 [Project ID TSRU31] was previously $0
10 and is now $ . The sum of the parametric estimate for the three
11 Fiber Optic projects is $ , which is the same as the approved Plan
12 Update‐3 estimate for Install Fiber Optic Cable [Project ID TSRU17];
13 however, with updated cost estimates and the combination of a relay
14 project from Upgrade 138kV Circuit Protection Breakers & Relays [Project
15 ID TSRU18] to Fiber Optic & Relay Upgrade – Miller to Burns Ditch – 13810
16 [Project ID TSRU30], the Plan Update‐4 estimate is less then Plan Update‐3
17 estimate by $ . Lines 1 through 5 in Confidential Appendix 8
18 illustrate the move from Install Fiber Optic Cable [Project ID TSRU17] to
19 Fiber Optic – Green Acres to St. John ‐ 13888 [Project ID TSRU29], Fiber
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1 Optic & Relay Upgrade – Miller to Burns Ditch – 13810 [Project ID TSRU30],
2 and Fiber Optic – Munster to Taney ‐ 13895 [Project ID TSRU31].
3 For an example of dollars moving from a unit based project to one specific
4 project, refer to Plan Update‐4, page 11, line 60, page 17, lines 68, 77, and 80,
5 and page 25, line 33. Rebuild Substation – Colfax #2 XFMR and Switchgear
6 [Project ID DSNRS18] consists of assets from Battery & Charger Equipment
7 Projects – Distribution [Project ID DSB1], Replace 12kV Breakers [Project ID
8 DSBRU3], and Replace 12kV Transformers [Project ID DSTU4]. Rebuild
9 Substation – Colfax #2 XFMR and Switchgear [Project ID DSNRS18] was $0
10 in Plan Update‐3 and is estimated to be $ in Plan Update‐4, of
11 which was moved to Substation Pre‐construction – Distribution
12 [Project ID DSPC1] in 2018. $ moved from Battery & Charger
13 Equipment Projects – Distribution [Project ID DSB1] in 2020, $
14 moved from Replace 12kV Breakers [Project ID DSBRU3] in 2019, and
15 $ moved from Replace 12kV Transformers [Project ID DSTU4] in
16 2019 for a total cost of $ in Plan Update‐2, which results in a
17 planned reduction of $ as shown on lines 259 through 264 in
18 Confidential Appendix 8.
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1 Q64. Please identify the variances in updated direct costs for the 2019 Projects
2 as compared to the best estimates of the direct costs identified in Plan
3 Update‐3.
4 A64. Plan Update‐4, 2019 Project Detail (Page 18) shows the Approved Project
5 Cost (direct) for the 2019 Projects was $198,795,190 (Column F), the
6 Updated Project Cost (direct) is $200,954,078 (Column G), for a total
7 increase of $2,158,888 (Column H).
8 Q65. Before you explain cost increases, could you provide an overview and
9 status update on the Northern Indiana Commuter Transportation District
10 (“NICTD”) Project?
11 A65. Yes. Some general information about the project should assist in
12 understanding the 2019 work that is planned on a few projects below. The
13 NICTD Project has been ongoing for a couple years. There are multiple
14 projects associated with NICTD focused on aging assets and system
15 performance. These projects were included in the original TDSIC filing. In
16 the second TDSIC filing these projects were updated based on system
17 review and design optimization resulting in an overall cost reduction of $14
18 million. Each of these projects has since been refined with detailed
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1 engineering resulting in a cost increase to effectively complete the original
2 scope of the project. This updated estimate is still $10 million less than the
3 originally filed number.
4 A few of the 2019 projects with cost increases are part of the broader NICTD
5 Project, including (1) Circuit 3465 Rebuild ‐ 69kV Laporte JCT to Tee Lake
6 [Project ID TLNRL6]; (2) Circuit 3465 Rebuild ‐ New Carlisle to Olive
7 [Project ID TLNRL9] (for 2019 and 2020); and (3) Circuit 3433 Rebuild ‐
8 Grandview to Bendix West Side [Project ID DLNRL24]. While the cost
9 increases associated with each are discussed below, I would note some
10 general information. Several of the projects have had poor reliability and
11 ranked high in the risk model in part because they were radial feed. In
12 addition, because these circuits serve the South Shore Railroad, the
13 easements associated with the railroad, including the overhead catenary
14 lines have difficult access for restoration, which adds to the cost of the
15 upgrades. NIPSCO is working with American Electric Power (“AEP”) on
16 the project as it includes upgrades to its system, which will reduce exposure
17 to the circuits. Ultimately, approximately 28 miles of line will be retired
18 and replaced with 6 miles of new 69 kV or 35kv line. In total, while some
REDACTED Petitioner's Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733-TDSIC-4 Page 64
1 of the portions of the project have cost increases, the upgrades to the system
2 have been reduced by approximately $10 million dollars from the original
3 7-Year Plan estimate filed December 31, 2015, bringing a $22 million project
4 down to approximately $12 million, a reduction of 44%.
Table 2 NI CTD Pro· ects Across Plan U
Pro· ect ID Pro· ect Title DLNRL23 Circuit 3465 Rebuild - Trail Creek to Lakeland TLNRL6 Circuit 3465 Rebuild - 69KV LaPorte JCT to Tee Lake TLNRL9 Circuit 3465 Rebuild New Carlisle to Olive DLNRL24 Circuit 3433 Rebuild - Grandview to Bendix West Side Total Note: Projects reflect current Project ID and Project Title for consistency across plan updates. 5 6 Q66. Please explain what drove the noteworthy cost increases for the 2019
7 Projects.
8 A66. As shown in Confidential Attachment 3-B, the following projects show cost
9 increases greater than $100,000 or 20%, whichever is greater, over what was
10 approved in Plan Update-3:
11 Arrester Projects -Transmission [Project ID TSAI] [sm (62%)]. 12 Total project cost has increased due to larger rental equipment (a 125' 13 lift and a crane, when a 60' lift is generally sufficient) because the 14 arresters were higher on the steel structures than typical 15 replacements. In addition, the height meant additional ground cable 16 was required than in a typical installation. REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 65
1 Substation Switch Projects – Transmission [Project ID TSSW1] 2 [$ (45%)]. Increase cost associated with the redesign of the 3 support steel and foundations to utilize new circuit switcher design 4 as well as the updated escalation factor, which was applied to the 5 unit cost.
6 Annunciator Projects – Transmission [Project ID TSRU2] [$ 7 (21%)]. This project was updated to reflect the updated escalation 8 factor, which was applied to the unit cost. Please note: one 9 annunciator was determined to not need to be replaced.
10 Relay & Breaker Upgrade ‐ Dune Acres to Aetna, Praxair #5 – 13805 11 [Project ID TSRU32] [$ (23%)]. As was discussed in Cause No. 12 44733‐TDSIC‐2, the original plan for this project could not be 13 executed by retrofitting the existing relay houses. The existing 14 configuration consists of several small control houses dating back to 15 the original construction of the station that are located at various 16 points throughout the substation yard. The subsequent field 17 inspections identified that the existing control houses were too small 18 to accommodate the needed relay and control panels and were 19 geographically separated, placing control points for equipment is 20 disparate locations. Modifying the current infrastructure to 21 accommodate the new assets was unfavorable due to the condition 22 of the buildings and due to the lack of ability to consolidate 23 operation and control points for high voltage equipment. Upon 24 further consideration of the project, NIPSCO has elected to replace 25 the current relay houses with a modern drop‐in control house. 26 Originally, NIPSCO’s estimate included costs for retrofitting an 27 existing relay house to accommodate more modern equipment. The 28 end result of a retrofit would be a unique layout of equipment by 29 location, which would result in higher risk of operational error and 30 potential extended outage periods during equipment failures. Using 31 the new control house streamlines the sequencing of projects and 32 reduces equipment clearance durations and the standardized design 33 allows for ease of replacement or repair reducing outage impacts. In 34 addition, utilizing a drop in control house enables more construction 35 tasks to be performed concurrently instead of in sequentially,
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1 allowing projects to be executed in less time. Utilization of one new 2 control house locates operating equipment within one structure, 3 eliminates the need to support multiple aging buildings and 4 provides adequate space for the necessary protective relay and 5 control equipment. Installing a new control house increases material 6 and labor to purchase and install the new building and for 7 integration of all the control points to one physical location. This is 8 a multi‐year project anticipated to be completed in year 2021 and will 9 reflect an increase through its construction lifecycle. 10 11 Relay Upgrade ‐ Tower Road to Babcock – 13898 [Project ID TSRU35] 12 [$ (58%)]. This project has moved to a more detailed estimate. 13 As part of that, it has been determined that Babcock is a half breaker 14 configuration that requires modernization of the transformer 15 protection scheme as well. This is needed since the power 16 transformers are tied directly to the line with integrated zones of 17 protection. This configuration was not accounted for in the 18 parametric estimate. If the electromechanical relays were left, it 19 would negate the value of the modernization. This additional 20 modernization is aligned with NIPSCO’s strategic plan to eliminate 21 electromechanical relays from the system. This improves 22 performance including protection of system assets, allows for event 23 reports, and helps monitor transformer performance.
24 Relay Upgrade ‐ St. John to Kreitzburg – 138101 [Project ID TSRU37] 25 [$ (62%)]. This project has moved to a more detailed estimate. 26 As part of that, it has been determined that Kreitzburg is a bus 27 configuration that requires modernization of the transformer 28 protection scheme as well. This is needed since the power 29 transformers are tied directly to the line with integrated zones of 30 protection. This configuration was not accounted for in the 31 parametric estimate. If the electromechanical relays were left, it 32 would negate the value of the modernization. This additional 33 modernization is aligned with NIPSCO’s strategic plan to eliminate 34 electromechanical relays from the system. This improves 35 performance including protection of system assets, allows for event 36 reports, and helps monitor transformer performance. If the 69kV bus
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1 differential relaying is not modernized at this time, another clearance 2 of the entire 69kV yard will be needed, at a later date to perform this 3 upgrade, which will add additional expense.
4 Relay Upgrade ‐ Kenwood to Highland – 13899 [Project ID TSRU40] 5 [$ (134%)]. This project has moved to a more detailed 6 estimate. As part of that, it has been determined that both Kenwood 7 and Highland are half breaker configurations that require 8 modernization of the transformer protection scheme as well. This is 9 needed since the power transformers are tied directly to the line with 10 integrated zones of protection. This configuration was not 11 accounted for in the parametric estimate. If the electromechanical 12 relays were left, it would negate the value of the modernization. 13 This additional modernization is aligned with NIPSCO’s strategic 14 plan to eliminate electromechanical relays from the system. This 15 improves performance including protection of system assets, allows 16 for event reports, and helps monitor transformer performance. Also, 17 Switches are to be replaced, which were installed in 1975. 18 Replacement is necessary due to age and condition, as well as not 19 having the ampacity rating required
20 Relay & Breaker Upgrade ‐ Goodland 69kV [Project ID TSRU42] 21 [$ (35%)]. A few studies have been conducted on the 22 Goodland project. The first study was conducted to confirm the 23 need of the temporary switch between the transformers and 24 analyzing the Hoosier wind farm. A second study was completed as 25 an ad‐hoc study, which focused on the clearances themselves and 26 their timing with other internal or external projects.
27 The first study concluded a mitigation measure of adding a 28 temporary switch between the two transformers was necessary. This 29 is required because the two 69kV buses at Goodland are used to back 30 up each other. With one down, it is very hard, if not impossible, to 31 supply all of the load from Goodland due to a lack of 69kV source as 32 this is the edge of the NIPSCO system.
33 The second study concluded a mitigation measure for Hoosier 34 Windfarm was needed to meet contractual requirements. The
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1 Hoosier Windfarm has an agreement with NIPSCO to accept all of 2 its available generation capacity. Therefore, NIPSCO built the 69kV 3 line from Goodland to the windfarm. Since the windfarm still needs 4 to be supplied while work is being conducted at Goodland and all 5 generation must be able to flow, NIPSCO will need to ensure the 6 conductor from the substation to Hoosier Windfarm is available.
7 In addition to these upgrades, the duration of the project and the 8 need for additional external resources are contributing factors to the 9 increased cost of this project. In addition, there were certain design 10 changes, including replacement of both station service transformers, 11 and new breakers designed to use vacuum, which was not in the 12 parametric estimate. And finally, a new cable trench is needed to 13 meet current standards, rather than directly burying cable, as was 14 previously done.
15 Circuit 3465 Rebuild ‐ 69kV Laporte JCT to Tee Lake [Project ID 16 TLNRL6] [$ (1363%)]. The increase in this project is due to 17 final determination of project scope to achieve the original outcome 18 and further refinement of the estimate. As part of this refinement, it 19 was determined that it would be necessary to construct a substation 20 bay addition with a breaker as well as associated relays in order to 21 create a permanent feed from the substation. In addition, funds are 22 required for matting due to site conditions. Finally, there were 23 higher than anticipated engineering costs associated with the 24 project. In comparison to Plan Update‐3, the total increase for this 25 project is 63%. The reason for the large variance in 2019 is that this 26 is a multi‐year project and a larger portion of work is being 27 completed in 2019 while most of the funding was apportioned to 28 2018. (This is part of the broader NICTD Project discussed in Q/A 65 29 above as shown in Table 2, which as a total project is projected to 30 decrease by approximately 44% from the original 7‐Year Plan 31 estimate.)
32 Circuit 3465 Rebuild ‐ New Carlisle to Olive [Project ID TLNRL9] 33 [$ (58%)]. The increase in this project is due to final 34 determination of project scope to achieve the original outcome and 35 further refinement of the estimate. As part of the engineering
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1 process, it was determined that an additional breaker bay was 2 required at the Olive station in order to feed the supply line to New 3 Carlisle. A temporary bay will be constructed in 2019, with a 4 permanent bay constructed in 2020. (This is part of the broader 5 NICTD Project discussed in Q/A 65 above as shown in Table 2.)
6 4kV Conversion ‐ Chase – 18341 [Project ID D4KVL11] [$ 7 (192%)]. The parametric estimate was based on the 3 phase length 8 and it was assumed there would be fewer single phase taps to be 9 addressed. However, this particular project has over three times the 10 amount of single phase to 3 phase work. Because of this, the total 11 project cost has increased due to a large portion being single phase 12 (versus what was included in the parametric estimate) and 13 congestion due to 100% easement work. In addition, this estimate 14 has been updated based on experience gained from previous 4kV 15 conversion projects including the amount of poles expected to be 16 replaced, several deteriorated conductors on single phase taps, 17 anticipated volume of hydro excavation to eliminate underground 18 hazards, poor soil conditions requiring additional excavation and 19 shoring costs for pole replacement and factoring in that the project 20 will be completed using contract labor, which increases the project 21 support costs to allow for additional oversight and quality control. 22 The number of hours of labor, including project support costs, has 23 also increased given the expected site conditions.
24 Substation Switch Projects – Distribution [Project ID DSSW1] 25 [$ (45%)]. Updated to reflect the 2018 escalation factor to the 26 unit cost as well as the updated parametric estimate based on historic 27 performance.
28 Breaker Upgrade ‐ Fisher Switchgear #1 and #2 [Project ID DSBRU9] 29 [$ (13%)]. Total project cost has increased due to substation 30 expansion for mobile substation and anticipated environmental 31 costs. This substation has a high water table, which will likely 32 require more matting and dewatering than was originally 33 anticipated. In addition, a mobile substation will be required as well 34 as additional room at the substation for the installation of the 35 switchgear, which will add costs for site preparation work.
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1 Breaker Upgrade ‐ Liberty Park Switch Gear [Project ID DSBRU10] 2 [$ (15%)]. Total project cost has increased due to increased 3 material and labor associated with the project. The detailed design 4 estimate required installation of new transrupters to adequately 5 protect both transformers. The transformer concrete pads require 6 replacement, and additional steel and foundation work is required 7 for the transrupter installation.
8 Breaker Upgrade ‐ McKinley Breaker and Recloser Upgrade (12kV) 9 [Project ID DSBRU11] [$ (22%)]. Total project cost has 10 increased due to enhanced design using a switchgear, a new layout 11 of the substation, and anticipated environmental costs. The existing 12 layout of the substation creates challenges for replacement of the 13 breakers and reclosers. Physical constraints resulted in increased risk 14 for safe construction. Given the existing physical constraints the 15 project has been designed to use a switchgear adjacent to the existing 16 substation. Installation of a switchgear increased costs associated 17 with additional foundations and structures as well as environmental 18 costs associated with expanding the substation footprint.
19 Breaker Upgrade ‐ Model Switchgear [Project ID DSBRU13] 20 [$ (17%)]. Total project cost has increased due to the addition 21 of multiple foundations for the circuit switchers, a mobile substation 22 (necessary to provide a back‐up feed at certain times of the year) and 23 a substation fence expansion to allow for safe execution of the 24 project. These items were not included in the parametric estimate, 25 but were determined to be necessary as more detailed engineering 26 has been completed.
27 Breaker Upgrade ‐Township Switchgear [Project ID DSBRU14] 28 [$ (27%)]. Total project cost has increased due to fencing 29 required to fence off the existing gas regulator station from the rest 30 of the substation to enhance safety and bring the facility up to 31 current standards. In addition, an additional entrance was added for 32 safety and accessibility. Circuit switchers were added as well as 33 additional foundations. Finally, it was determined that a road bore 34 would be required since one of the circuits is underground. This will 35 also require new conduit. None of these items was anticipated in the
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1 parametric estimate, but was determined to be required as more 2 detailed engineering work has been completed.
3 Replace Transformer ‐ Maple #3 69/12kV [Project ID DSTU11] 4 [$ (51%)]. During engineering of the Maple #3 transformer 5 the need to increase the size of the transformer to adequately supply 6 expanding load in the area was identified. The cost increase includes 7 the larger transformer, secondary breaker and relay protection 8 required for the larger transformer.
9 Rebuild Substation ‐ Warsaw #3 & #4 Transformer and Recloser 10 Upgrade [Project ID DSNRS20] [$ (12%)]. Total project cost 11 has increased once detailed design was complete. The existing 12 substation was originally constructed with a very small footprint 13 that places construction constraints on the project. Lack of room in 14 the existing substation and safe working space will make 15 replacement of the new, larger transformers unfeasible with the 16 current substation design. Using a switchgear design and moving 17 the new substation to the south edge of the property will allow 18 NIPSCO to complete this work, eliminate the existing safety and 19 spacing design issues, and provide a modern substation in place of 20 the existing substation. In addition, there are unanticipated 21 environmental costs associated with dewatering and the 22 municipality has requested additional restoration that was 23 unanticipated in the parametric estimate.
24 Circuit 3433 Rebuild ‐ Grandview to Bendix West Side [Project ID 25 DLNRL24] [$ (465%)]. The increase in this project is due to 26 final determination of project scope to achieve the original outcome 27 and further refinement of the estimate. The project requires 28 installation of phase over phase line switches for protection and 29 isolation. Additional substation protection and control equipment is 30 required for the increased load on the circuit and the estimate 31 includes construction of the 35kv line to the Grandview substation. 32 (This is part of the broader NICTD Project discussed in Q/A 65 above 33 as shown in Table 2, which as a total project is projected to decrease 34 by approximately 44% from the Original 7‐Year Plan estimate.)
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1 Circuit Rebuild ‐ Waterloo ‐ 12‐120 [Project ID DLNRL33] [$ 2 (21%)]. Total project cost has increased due to a high percentage of 3 easement work and double circuits which was determined when 4 going from a parametric to a detailed estimate. The project is being 5 completed in an easement and will separate the two circuits. This is 6 more difficult to build than originally anticipated. Similar to the 4kV 7 rebuilds, Circuit 12‐120 is predominately comprised of older poles in 8 back alleys, and has easements that are difficult to access. The 9 project is further complicated by the presence of a second 12 kV 10 circuit on the same poles.
11 Circuit Rebuild ‐ North Liberty Sub Feeder [Project ID DLNRL44] 12 [$ (24%)]. Total project cost has increased due to complex 13 poles near the substation with deadends, corners, and terminations. 14 The North Liberty Substation project is not a traditional 12kV circuit 15 rebuild. The project involves reconductoring all four 12kV circuits 16 within close proximity to the substation. As such, the project is 17 denser with more poles, switches, and deadends per mile, than a 18 traditional circuit rebuild. Additionally, more than 50% of the 19 project contains transmission overbuild. The complexity of the 20 project was determined as detailed engineering has been completed.
21 Pole Replacement Projects – Distribution [Project ID DLWP1] 22 [$ (62%)]. Planned number of poles to be replaced has 23 increased to 1,777 poles from 1,274 due to an increase in the rate of 24 inspected poles that require replacement.
25 Q67. With respect to the Pole Replacement Project, what is driving the cost
26 increase?
27 A67. When the original 7‐Year Plan was developed, an estimated pole rejection
28 rate of 5% was used to estimate the volume of units requiring replacement.
29 In 2016, the actual rejection rate for inspected poles was 7.2%, and in 2017,
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1 the actual rejection rate for inspected poles was 10.8%.3 In the Plan, all
2 NIPSCO poles are inspected on a 10‐year cycle and are inspected based on
3 pre‐identified geographical grids. The reject rate for each grid will vary
4 based on the average age of poles in the selected grid, environmental
5 condition or other factors impacting the life cycle of a wood pole. Once
6 inspected, each pole is categorized based on current condition as compared
7 to the inspection criteria and will be categorized as one of the following: (1)
8 emergency pole – replace immediately; (2) priority reject – replacement
9 within one year; (3) regular reject – replace within three years; or (4) pass
10 inspection.
11 The increased rejection rate for 2016 and 2017 generated a greater number
12 of poles to be replaced in 2018–2020, depending on reject classification, and
13 is one of the primary drivers of cost increase for the overall pole
14 replacement program. Because of the higher volume of work, NIPSCO has
15 also had to increase the number of poles being replaced by contractors and
3 A reject pole is determined through a detailed inspection that includes excavation around the pole, core drilling to identify pole shell depth, pole sounding for signs of decay and visual inspection for identification of other defects.
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1 its oversight and quality control efforts, which also contributes to the
2 increase in the estimate for 2019 project costs.
3 As noted above, in 2018, NIPSCO plans to replace approximately 1,777
4 instead of the planned 1,274 poles. In addition, engineering and
5 construction standard updates will increase material costs and provide a
6 more reliable design. Identification and replacement of reject poles
7 improves overall safety and integrity of the electric delivery system by
8 removing poles with identified defects and improving overall system
9 performance. Replaced poles are of greater strength and meet current
10 design standards, resulting in a more resilient system that will better
11 withstand severe weather events. The pole replacement will continue to be
12 monitored closely due to the increased reject rate and the influence it will
13 have on future construction years.
14 2020 PROJECTS
15 Q68. Please explain the overall change from Plan Update‐3 to Plan Update‐4
16 for 2020.
17 A68. There is an overall decrease in 2020 of $7,479,667 (cost increases of
18 $1,155,000 and net moves out of 2020 of $8,634,667).
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1 Q69. Did NIPSCO move any projects to 2020 that were previously included in
2 a different year in Plan Update‐3?
3 A69. Yes. As shown in Confidential Attachment 3‐B, these were the projects that
4 moved into 2020:
5 Arrester Projects – Transmission [Project ID TSA1]. Moved $ 6 in direct costs for one arrester from 2019 to 2020 due to coordination 7 of effort with other TDSIC project work scheduled in 2020.
8 Potential Transformer Projects – Transmission [Project ID TSPT1]. 9 Moved $ in direct costs for three potential transformers from 10 2017 to 2020 due to customer coordination.
11 Upgrade 138kV Circuit Protection Breakers & Relays [Project ID 12 TSRU18]. Moved $ in direct costs from 2019 to 2020 due to 13 coordination of effort with other TDSIC project work scheduled in 14 2020.
15 Replace 345kV Breakers [Project ID TSBRU1]. Moved $ in 16 direct costs from 2020 [Project ID TSBRU6] to 2020 to correct for 17 engineering funds that were inadvertently removed from TSBRU1 18 in Plan Update 3 that should have been removed from TSBRU6.
19 Substation Engineering – Transmission [Project ID TSE1]. Moved 20 $ in direct costs for engineering two breakers from 2018 to 2020 21 due to coordination of effort with other TDSIC project work 22 scheduled in 2020.
23 Substation Feeder Cable Projects – Distribution [Project ID DSFC1]. 24 Moved $ in direct costs for one feeder cable from 2019 to 2020 25 due to customer coordination.
26 Replace 34kV Breakers [Project ID DSBRU2]. Moved $ in 27 direct costs for one breaker from 2022 to 2020 due to coordination of 28 effort with other TDSIC project work scheduled in 2020.
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1 Replace 12kV Breakers [Project ID DSBRU3]. Moved $ in 2 direct costs for one project from 2019 to 2020 due to coordination of 3 effort with other TDSIC project work scheduled in 2020.
4 New Distribution Substation [Project ID DSNRS10]. Moved 5 $ in direct costs for one project from 2022 to 2020 due to 6 coordination of effort with other TDSIC project work scheduled in 7 2020.
8 Substation Engineering – Distribution [Project ID DSE1]. Moved 9 $ in direct costs for engineering two transformers from 2017 10 to 2020 to allow additional time to determine the best engineering 11 solution.
12 Install Line to Support New Substation (Miles) [Project ID 13 DLNRL16]. Moved $ in direct costs for one project from 2022 14 to 2020 due to coordination of effort with other TDSIC project work 15 scheduled in 2020.
16
17 Q70. Please identify the variances in updated direct costs for the 2020 Projects
18 as compared to the best estimates of the direct costs identified in Plan
19 Update‐3.
20 A70. Plan Update‐4, 2020 Project Detail (Page 25) shows the Approved Project
21 Cost (direct) for the 2020 Projects was $185,801,456 (Column F), the
22 Updated Project Cost (direct) is $178,321,789 (Column G), for a total
23 decrease of $7,479,667 (Column H).
24 Q71. Please explain what drove the noteworthy cost increases for the 2020
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1 Projects.
2 A71. As shown in Confidential Attachment 3‐B, the following project shows a
3 cost increase greater than $100,000 or 20%, whichever is greater, over what
4 was approved in Plan Update‐3.
5 Circuit 3465 Rebuild ‐ New Carlisle to Olive [Project ID TLNRL9] 6 [$ (100%)]. Increase is due to a refined estimate. As part of 7 the engineering process, it was determined that an additional 8 breaker bay was required at the Olive station in order to feed the 9 supply line to New Carlisle. This is the permanent bay which will be 10 constructed in 2020. (This is part of the broader NICTD Project 11 discussed in Q/A 65 above as shown in Table 2.)
12 2021 PROJECTS
13 Q72. Please explain the overall change from Plan Update‐3 to Plan Update‐4
14 for 2021.
15 A72. There is an overall decrease in 2021 of $618,411 (a cost decrease of $275,634
16 and net moves out of 2021 of $342,777).
17 Q73. Did NIPSCO move any Projects to 2021 that were previously included in
18 a different year in Plan Update‐3?
19 A73. Yes. As shown in Confidential Attachment 3‐B, this was the project that
20 moved into 2021:
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1 Replace 69kV Breakers [Project ID TSBRU3]. Moved $ in 2 direct costs for one breaker from 2022 to 2021 due to coordination of 3 effort with other TDSIC project work scheduled in 2021.
4 Q74. Please identify the variances in updated direct costs for the 2021 Projects
5 as compared to the best estimates of the direct costs identified in Plan
6 Update‐3.
7 A74. Plan Update‐4, 2021 Project Detail (Page 28) shows the Approved Project
8 Cost (direct) for the 2021 Projects was $186,257,331 (Column F), the
9 Updated Project Cost (direct) is $185,638,920(Column G), for a total
10 decrease of $618,411 (Column H).
11 Q75. Please explain what drove the noteworthy cost increases for the 2021
12 Projects.
13 A75. As shown in Confidential Attachment 3‐B, there are no projects with a cost
14 increase greater than $100,000 or 20%, whichever is greater, over what was
15 approved in Plan Update‐3.
16 2022 PROJECTS
17 Q76. Please explain the overall change from Plan Update‐3 to Plan Update‐4
18 for 2022.
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1 A76. There is an overall increase in 2022 of $8,783,087 (a cost increase of $0 and
2 net moves into 2022 of $8,783,087).
3 Q77. Did NIPSCO move any Projects to 2022 that were previously included in
4 a different year in Plan Update‐3?
5 A77. Yes. As shown in Confidential Attachment 3‐B, these were the projects that
6 moved into 2022.
7 Upgrade 69kV Circuit Protection Breakers & Relays [Project ID 8 TSRU19]. Moved $ in direct costs for one breaker and relay 9 project from 2020 to 2022 due to project coordination.
10 Replace 69kV Breakers [Project ID TSBRU3]. Moved $ in 11 direct costs for one breaker from 2019 to 2022 due to coordination of 12 effort with other TDSIC project work scheduled in 2022.
13 Line Switch Projects – Transmission [Project ID TLSW1]. Moved 14 $ for one line switch from 2017 to 2022 due to project 15 coordination. .
16 Underground Cable Replacement Projects [Project ID DUG1]. 17 Moved $ in direct costs for two projects from 2018 18 ($ ), ten from 2019 ($ ), and four from 2020 19 ($ ) to 2022 due to a field review of the condition of these 20 cable sections indicating immediate replacement is not needed. 21 NIPSCO may replace the identified sections if future inspections 22 reveal that immediate replacements are needed. In the meantime, 23 NIPSCO will execute the replacement of higher priority cable first.
24 Power Transformer Projects – Distribution [Project ID DSTU1]. 25 Moved $ in direct costs for one transformer from 2019 to
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1 2022 due to coordination of effort with other TDSIC project work 2 scheduled in 2022.
3 New Distribution Substation [Project ID DSNRS10]. Moved 4 $ in direct costs for one project from 2020 to 2022 due to 5 coordination of effort with other TDSIC project work scheduled in 6 2022.
7 Syracuse Substation Upgrade #1 & #2 Transformers [Project ID 8 DSNRS16]. Moved $ in direct costs for pre‐construction 9 from 2018 ($ ) and for two transformers from 2019 ($ ) 10 to 2022 to allow additional time to determine the best engineering 11 solution.
12 Install Line to Support New Substation (Miles) [Project ID 13 DLNRL16]. Moved $ in direct costs for one project from 2020 14 to 2022 due to coordination of effort with other TDSIC project work 15 scheduled in 2022.
16 Q78. Please identify the variances in updated direct costs for the 2022 Projects
17 as compared to the best estimates of the direct costs identified in Plan
18 Update‐3.
19 A78. Plan Update‐4, 2022 Project Detail (Page 31) shows the Approved Project
20 Cost (direct) for the 2022 Projects was $191,125,874 (Column F), the
21 Updated Project Cost (direct) is $199,908,961 (Column G), for a total
22 increase of $8,783,087 (Column H).
23 Q79. Please explain what drove the noteworthy cost increases for the 2022
24 Projects.
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1 A79. As shown in Confidential Attachment 3-B, there are no projects with a cost
2 increase greater than $100,000 or 20%, whichever is greater, over what was
3 approved in Plan Update-3.
4 44733 ORDER COMPLIANCE
5 Q80. In accordance with the 44733 Order, the overall composition of the
6 projects included in the Plan will be maintained at sixty-one percent
7 (61%) distribution projects and thirty-nine percent (39%) transmission
8 projects, plus or minus one percent (+/-1%). Has NIPSCO adhered to that
9 composition requirement in its Plan Update-4?
10 ABO. Yes. The overall composition of the projects included in the Plan will be
11 maintained by project category at sixty-one percent (61%) distribution
12 projects and thirty-nine percent (39%) transmission projects, plus or minus
13 one percent (+/-1 %) as follows:
2016 2017 2018 2019 2020 2021 2022 Total Total $36,588,670 $40,735,060 $50,643,515 $83,365,379 $78,764,190 $83,114,881 $74,618,959 $447,830,654 Transmission Total $72,960,290 $69,591,768 $89,611,890 $117,588,699 $99,557,599 $102,524,039 $125,290,002 $677,124,287 Distribution Total Direct $109,548,960 $110,326,828 $140,255,405 $200,954,078 $178,321,789 $185,638,920 $199,908,961 $1,124,954,941 Transmission 33.4% 36.9% 36.1% 41.5% 44.2% 44.8% 37.3% 39.8% Ratio Distribution 66.6% 63.1% 63.9% 58.5% 55.8% 55.2% 62.7% 60.2% Ratio 14 REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 82
1 Q81. The 44733 Order included up to $3.5 million for an Economic
2 Development project for the LaPorte County Kingsbury Industrial Park
3 (“Kingsbury Projects”) including a $2.5 million project for substation
4 upgrades as provided for in the Commission’s July 18, 2016 Order in
5 Cause No. 44688 and up to $1.0 million for other distribution
6 infrastructure upgrades. Has NIPSCO included the Kingsbury Projects
7 in Plan Update‐4?
8 A81. No. Any capital expenditures for the Kingsbury Project will be presented
9 in a future tracker filing by NIPSCO and LaPorte County.
10 STATUTORY COMPLIANCE
11 Q82. Does Plan Update‐4 provide the best estimate of the cost of the
12 investments included in the Plan?
13 A82. Yes. Plan Update‐4 shows actual or updated cost estimates for the 2016‐
14 2022 Projects. Plan Update‐4 provides information to support NIPSCO’s
15 best estimate of the cost of investments included in the Plan. Plan Update‐
16 4 includes the type of work that is core to NIPSCO’s transmission &
17 distribution business. The various appendices to the Plan provide cost
18 estimates for the projects included in the Plan. Appendices 1 and 2 of the
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 83
1 Plan provide the asset registers for Risk Based and Deliverability and
2 Condition Based Projects, respectively. This was the starting point for
3 determining the annual list of projects and the estimated cost for
4 completion of those projects. Appendices 3, 3.1, 3.2, 3.3, and 3.4 of the Plan
5 provide detailed cost estimates and PCRs for the 2017 projects. Appendices
6 4, 4.1, and 4.2 of the Plan provide detailed cost estimates and PCRs for the
7 2018 projects. Appendix 5 and 5.1 of the Plan provides detailed cost
8 estimates for the 2019 projects. For projects with unit based estimates for
9 2016, 2017, 2018, and 2019, and for all projects to be completed in the out
10 years of the Plan (2020‐2022), NIPSCO has provided unit‐cost based
11 estimates broken down by direct and indirect costs including labor and
12 material in Appendices 6, 6.1, and 6.2 of the Plan.
13 Q83. Does the public convenience and necessity require or will it require the
14 transmission, distribution, and storage system improvements included in
15 Plan Update‐4?
16 A83. Yes. The eligible improvements included in Plan Update‐4 will serve the
17 public convenience and necessity in various ways. First, Plan Update‐4 is
18 largely a replacement plan. The equipment that is in service today is used
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 84
1 and useful in safely and reliably serving our customers with electric service.
2 However, in order to continue serving NIPSCO’s customers safely and
3 reliably, the public convenience and necessity require that the assets
4 identified in Plan Update‐4 be replaced. The public’s reliance on electricity
5 is linked directly with quality of life, economic enhancement and overall
6 public safety. NIPSCO takes its role seriously in serving its customers
7 safely and reliably, and this includes protecting customers and employees
8 from potential injury, property damage and sustained electrical outages.
9 Second, NIPSCO’s Plan Update‐4 follows the requirements of the statute
10 and achieves the legislative intent of making new and replacement
11 transmission and distribution investments for the purposes of safety,
12 reliability, system modernization and economic development. This is
13 consistent with public practice and serves the public interest.
14 Third, the eligible investments are essential in protecting the integrity,
15 safety, and reliable operation of the system—not only for NIPSCO’s
16 customers, but also for the bulk electric system as a whole. These
17 investments provide for the public convenience and necessity at a much
18 broader level than just NIPSCO’s service territory by reaching not only
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 85
1 NIPSCO customers but also all utilities and customers in the MISO
2 footprint. NIPSCO must do its part to help secure its portion of the bulk
3 electric system. Customers also benefit through improved functionality
4 and modernization of the grid. For all these reasons, approval of Plan
5 Update‐4 is appropriate and in the interest of public convenience and
6 necessity.
7 Q84. Are the estimated costs of the eligible improvements included in Plan
8 Update‐4 justified by incremental benefits attributable to the Plan?
9 A84. Yes. NIPSCO has a large number of aging assets on its electric transmission
10 and distribution system. The assets have aged naturally as a function of
11 NIPSCO’s service territory development over time and the natural life of
12 the assets. These assets need to be replaced. Plan Update‐4 is a plan to
13 address these replacements.
14 Plan Update‐4 is targeted at reducing system risk by considering both the
15 likelihood of failure and the impact to the system through consequence of
16 failure. Plan Update‐4 is optimized to reduce overall risk by focusing on
17 the highest risk assets across all asset classes while also starting to group
18 projects by geography and through system outages to take advantage of
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 86
1 efficiencies and reduce system impact. Plan Update‐4 contains solutions
2 that will enhance customer and employee safety, avoid outages, preserve
3 operational and planning contingencies, provide superior equipment
4 protection, and meet evolving customer demands. By virtue of achieving
5 all of these benefits in a thoughtful, planned and cost efficient manner, Plan
6 Update‐4 provides incremental benefit for our customers.
7 Plan Update‐4 focuses on maintaining safe, reliable service for our
8 customers in a cost effective manner. While Plan Update‐4 addresses all
9 four types of eligible investment (safety, reliability, system modernization
10 or economic development) in the TDSIC statute, most of the Plan’s
11 investments positively impact electric reliability. Reliability drivers include
12 the avoidance of direct customer outages, the continuity of service when
13 experiencing loss of system elements, compliance with North American
14 Electric Reliability Corporation planning requirements for the Bulk Electric
15 System, the ability to meet customer needs through deliverability during
16 periods of high system stress, and the mitigation of potentially very long
17 outages due to loss of system sources for extended periods of time.
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 87
1 Plan Update‐4 allows for planned replacement of electric assets, realizing
2 construction efficiencies versus replacement in unplanned (emergent)
3 conditions. Premium labor rates for emergent replacements are mitigated.
4 Premiums that are sometimes required to expedite the manufacture of long
5 lead time items, such as transmission transformers and breakers, are also
6 mitigated. Also, more modern system protection devices which are
7 included in Plan Update‐4 provide for faster clearing of system faults that
8 will protect the asset lives of expensive system equipment and minimize
9 outage scales.
10 The continued safety of employees and customers is enhanced, and
11 potential damage to other electric system components is avoided when the
12 risks of violent failures (i.e., explosions, fires, downed power lines) are
13 mitigated. Lastly, the extension of new facilities or the rebuilding of older
14 facilities almost always provide for a more robust system to meet system
15 delivery or interconnection requirements.
16 Plan Update‐4 cost effectively addresses safety, reliability, system
17 modernization, and economic development concerns, and provides
18 incremental benefits to NIPSCO’s customers.
REDACTED Petitioner’s Confidential Exhibit No. 3 Northern Indiana Public Service Company LLC Cause No. 44733‐TDSIC‐4 Page 88
1 Q85. Please summarize the relief NIPSCO is requesting with respect to Plan
2 Update‐4.
3 A85. NIPSCO requests the Commission to approve its Plan Update‐4 as set forth
4 in Confidential Exhibit Electric Plan Update‐4 attached to its Verified
5 Petition initiating this Cause, including the updated project lists and project
6 cost estimates for each year of the Plan. NIPSCO requests the Commission
7 to approve the projects included in Plan Update‐4 as eligible transmission,
8 distribution, and storage system improvements under Ind. Code § 8‐1‐39‐2.
9 NIPSCO also requests approval to recover the costs of the eligible
10 investments included in Plan Update‐4 through the TDSIC mechanism.
11 Q86. Does this conclude your prepared direct testimony?
12 A86. Yes.
VERIFICATION
I, Charles A. Vamos, Director, Electric T&D Engineering for Northern Indiana
Public Service Company LLC, affirm under penalties of perjury that the foregoing representations are true and correct to the best of my knowledge, information and belief.
Charles A. Vamos
Date: October 9, 2018