DIRECT PRE-FILED TESTIMONY OF THE CAPITAL BUDGET PANEL - BEFORE THE LONG ISLAND POWER AUTHORITY IN THE MATTER of a Three-Year Rate Plan
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BEFORE THE
LONG ISLAND POWER AUTHORITY
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IN THE MATTER of a Three-Year Rate Plan Case 15-____________
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DIRECT PRE-FILED TESTIMONY
OF
THE CAPITAL BUDGET PANEL
Date: January 30, 2015DIRECT PRE-FILED TESTIMONY OF
CAPITAL BUDGET PANEL
TABLE OF CONTENTS
I. WITNESS QUALIFICATIONS AND DESCRIPTION OF TESTIMONY 1
II. TRANSMISSION AND DISTRIBUTION CAPITAL BUDGETS 9
A. The Selection Process for Capital Projects 9
1. General Description of the Process 9
2. Drivers of the Process 11
3. Types of Projects 16
4. Need for a Project 17
5. Project Prioritization and Risk Evaluation 18
6. Approval Mechanism 22
B. Major Projects 24
1. Plainview to Ruland Rd – New 69kV Transmission Line 26
2. Kings Highway New 138kV Substation 27
C. Blanket Projects 28
1. Circuit Improvement Program (“CIP”) 28
2. Multiple Customer Outages (“MCO”) 29
3. UG Cable Testing and Replacement Program 29
4. Automatic Sectionalizing Unit (“ASU”) Installation Program 30
5. Transformer Load Management (“TLM”) 30
6. Transmission & Distribution Wood Pole
Inspection/Replacement Programs. 31
D. Utility 2.0 31
E. NERC Bulk Electric System Reliability Projects 32
1. Syosset to Shore Road 138kV circuit 32
2. East Garden City to Valley Stream 138kV circuit 32
F. Storm Hardening Efforts 34
G. Rate Plan Budgets 36
1. T&D 2016 Capital Expenditures. 36
2. T&D 2017 Capital Expenditures 36
3. T&D 2018 Capital Expenditures. 36
H. T&D IT Spending 36
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III. SHARED AND BUSINESS SERVICES CAPITAL BUDGET 39
IV. CUSTOMER SERVICES OPERATIONALAND IT CAPITAL SPENDING 40
A. Customers Services Budget – Description and Background 40
B. Process for Selection of Customer Services Capital Projects 41
C. Customer Services Operational Capital Spending 42
1. Purchase and Install Electric Meters (Residential and Commercial) 43
2. Selective - Residential Meter Test & Retirement Program 43
3 Selective - Commercial Meter Test & Retirement Program 44
4. AMI Policy Expansion 45
5. AMI Saturation Expansion 45
D. Customer Services – IT Project Spending 46
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1 I. WITNESS QUALIFICATIONS AND DESCRIPTION OF TESTIMONY
2 Q. Please state the names of the members of this Capital Budget Panel (the
3 “Panel”).
4 A. We are Nicholas J. Lizanich, David C. Lyons, Richard H. Walden and Nayan I.
5 Parikh.
6 Q. Mr. Lizanich, please state your employer and business address.
7 A. I am employed by PSEG Long Island (“PSEG LI” or “Company”) and my business
8 address is 175 E. Old Country Road, Hicksville, NY 11801.
9 Q. In what capacity are you employed by PSEG LI?
10 A. I am employed by PSEG LI as Director – Asset Management.
11 Q. Please summarize your educational background and professional experience?
12 A. From June 2011 to when I assumed my current position with PSEG LI on December
13 23, 2014, I was Vice President of Transmission and Distribution Operations of the
14 Long Island Power Authority (“LIPA”). In that position, I reported to LIPA’s
15 President and COO and my responsibilities included oversight of the planning, asset
16 management, engineering, design, construction, operation and maintenance of the
17 electric transmission and distribution systems.
18 From May 2009 to May 2011, I was a utility industry consultant providing
19 strategic services to the utility industry. Engagements included the development of
20 business plans and the development of marketing strategies for companies engaged in
21 Smart Grid support applications, and the development of project scopes and execution
22 plans for various utility clients.
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1 From April 2007 to April 2009, I was Vice President, Asset Oversight of First
2 Energy Corporation in Akron, Ohio, an investor owned electric utility serving 4.5
3 million customers in Ohio, Pennsylvania and New Jersey through six separate
4 operating companies. In that position I was responsible for the creation of new asset
5 management and project management organizations and associated capital
6 management processes to meet corporate, customer, regulatory and shareholder
7 needs. I also created new asset management strategies incorporating industry
8 practices and standards, and provided oversight of an $800 million annual capital
9 program of work including project development, prioritization and execution.
10 From 2002 to 2007 I was employed by Patrick Engineering Inc. of Lisle,
11 Illinois, a privately owned mid-sized engineering consulting firm serving clients
12 throughout the U.S. I held positions of increasing responsibility at Patrick, including
13 Executive Vice President, Operations (2006 to March 2007), Senior Vice President,
14 Operations (2005-2006) and Vice President, Utility Services (2002-2005). I directed
15 all business groups of Patrick Engineering including utility, transportation, industrial,
16 environmental and survey/GIS, directed client development and satisfaction, business
17 building, contract negotiation and approval, work planning, project development,
18 work execution, project management, quality control, safety awareness and cost
19 control activities.
20 From 2000 to 2001 I was Vice President, Engineering and Planning of
21 Commonwealth Edison Company in Chicago, Illinois. While at Commonwealth
22 Edison Company, I directed the redesign of the transmission and distribution systems
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1 to improve the reliability of these systems. While there I also directed the
2 consolidation of work groups to create the Exelon Corporation.
3 I was employed by First Energy Corporation and its predecessor companies in
4 Akron, Ohio from 1974 – 1999, where I served in the following positions: Director,
5 Transmission and Distribution Operations Services (1999); Director, Transmission
6 and Substation Engineering (1997-1999); Manager, Customer Engineering and Work
7 Management (1991-1997); Manager, Work Management, Operations Services (1989-
8 1991), and held various positions within Engineering, Planning and Operations
9 (1974-1991).
10 I hold a Bachelor of Electrical Engineering from Cleveland State University
11 (1979) and a Master of Science in Industrial Engineering (Engineering Management)
12 from Cleveland State (1981). I am a Registered Professional Engineer in Ohio and
13 several other states. I am an industry advisor for the Electric Power Research
14 Institute (“EPRI”) in transmission, distribution, asset management and power quality
15 areas including a Member of the Power Delivery Sector Council; a former chairman
16 of the Power Quality business area for EPRI; a current member of the Edison Electric
17 Institute (“EEI”) Distribution and Transmission committees.
18 Q. Mr. Lyons, please state your employer and business address.
19 A. I am employed by PSEG Services Corporation (“PSEG Services”) and my business
20 address is 80 Park Plaza, Newark, New Jersey 07102.
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1 Q. In what capacity are you employed by PSEG Services?
2 A. I am employed as Director Corporate Integration with the responsibility of overseeing
3 the integration of PSEG LI’s back-office operations into the corporate functions of
4 Public Service Enterprise Group (“PSEG”).
5 Q. Please summarize your educational background and professional experience?
6 A. I have over twenty years of experience in Information Technology and senior level
7 management at PSEG. Previously, I served as director of treasury operation at PSEG
8 Services, with the responsibility for PSEG’s headquarters facilities, corporate real
9 estate, and survey and mapping. Since joining PSEG in 1981, I have held a variety of
10 positions, including project director of PSEG Services as a direct report to the
11 President/COO of that corporation. In this position, I was responsible for the
12 implementation of a PSEG-wide shared service business. This included the
13 development of a business services catalogue, pricing, and a sales forecast totaling
14 $400 million with PSEG Operating Companies. I have also served PSEG as the
15 director of medical services, director of workforce planning and development,
16 director IT business solutions, director e-business strategy, and general manager IT
17 Operations and Client Services.
18 I have a Bachelor of Science degree in electrical engineering technology from
19 New Jersey Institute of Technology, and an Executive Master of Business
20 Administration (“EMBA”) from New York University, Stern School of Business.
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1 Q. Mr. Walden, please state your employer and business address.
2 A. I am employed by PSEG LI and my business address is 15 Park Drive, Melville, NY
3 11747.
4 Q. In what capacity are you employed by PSEG LI?
5 A. I am employed by PSEG LI as Director of Meter Services.
6 Q. Please summarize your educational background and professional experience.
7 A. I was named to my current position at PSEG LI in September 2013 and am
8 responsible for commercial and residential meter reads, move-in/move-out service
9 orders in support of billing operations, execution of field collection and field services
10 activities, field operations dispatch, installation, maintenance and replacement of
11 electric revenue metering equipment, meter engineering, support of meter systems
12 and technology, load research and retail settlement functions and implementation of
13 long term metering strategy. Prior to joining PSEG LI, I was Senior Vice President
14 Utilities Business and Utility Sales Executive at Tendril Networks from March 2012
15 to September 2013, responsible for all aspects of sales and delivery of Tendril
16 solutions to utilities including IOUs, rural electric cooperatives and municipalities in
17 North America. From June 2010 to March 2012 I was–VP Utility Services at
18 Constellation Energy Group, where I led a load response sales effort aimed at helping
19 IOUs, municipals, and cooperatives address regulatory and legislative mandates;
20 control wholesale power supply costs; improve reliability; reduce capital
21 expenditures; and enable retail customers to manage energy more effectively while
22 participating in RTO and/or utility-sponsored load response programs. From 2000 to
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1 May 2010, I held various leadership roles at Dominion Resources, Inc. which
2 included: Director Advanced Metering Infrastructure (2008 – May 2010), Director
3 Delivery Metering Services (2003 – 2008), Director Business Performance (2003)
4 and Director Electric Metering (2000 – 2003). As the Director of Advanced Metering
5 Infrastructure, I was the AMI program director for that company’s electric delivery
6 business where I developed the program to support the next evolution in metering and
7 customer service and provided overall direction and leadership for the
8 implementation and operation of AMI technology including the automatic collection
9 and processing of energy data for markets, customers, and company operations.
10 My other significant experience includes leadership positions for over 12
11 years with Baltimore Gas & Electric Company, as well as manufacturing positions
12 in the consumer products industry.
13 I hold a B.S. in Chemical Engineering from the University of Maryland, an
14 MBA from Loyola College and I have completed the Executive Program at the
15 University of Michigan Business School.
16 Q. Mr. Parihk, please state your employer and business address.
17 A. I am employed by PSEG LI and my business address is 15 Park Drive, Melville, NY
18 11747.
19 Q. In what capacity are you employed by PSEG LI?
20 A. I am employed by PSEG LI as Manager of Systems and Change Implementation.
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1 Q. Please summarize your educational background and professional experience.
2 A. I was named Manager of Systems and Change Implementation in January 2014. In
3 this position, I am responsible for the management and support of Customer Services
4 IT applications and Customer Services IT projects. I have direct interface between
5 the line of business and the IT business unit, with which I work to create and maintain
6 the vision of the overall IT strategy for customer service, technology roadmaps,
7 capital budget and communicate all activities through the executive management
8 channels to meet business goals. I also lead our internal training department for any
9 existing and new systems changes and implementation.
10 Prior to assuming my current role at PSEG LI, I held the position of Project
11 Manager IS/IT, Customer Business Systems and IT Systems Analyst at LIPA from
12 2005 to January 2014. In these roles, I was responsible for the development,
13 implementation and maintenance of both new and on-going customer facing systems
14 and applications to support LIPA’s business processes and management, directing
15 National Grid’s IT project managers in developing and managing project plans,
16 ensuring the delivery of critical projects on a cost-effective and efficient schedule,
17 leading application life cycle development efforts for Billing, Customer Care, CRM,
18 Energy Efficiency portfolio and Storm Center, managing risk analysis, prioritization,
19 and resource selection to ensure the highest quality team is assigned to critical
20 projects (e.g., Siebel, CAS, Data Mart). I also developed relationships with business
21 stakeholders to plan and execute projects that meet pre-defined business objectives
22 and perform business case analysis and managed day-to-day datacenter operation, IT
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1 infrastructure, local area network (“LAN”) located at LIPA’s headquarters and
2 various remote offices.
3 Prior to my role at LIPA, I was an IT consultant at Unique Comp, Inc. where I
4 worked on client projects for private and public sector companies throughout the Tri-
5 State Area. Some of the clients I supported while working at Unique Comp, Inc.
6 included: ABN-AMRO Bank, New York; Amaranth Advisors, Connecticut; JP
7 Morgan Chase, New York; and Mformation Tech, New Jersey.
8 I hold a Bachelors of Engineering in Electronics from BVM Engineering
9 College, S.P University, India and an Executive MBA from Hofstra University. I
10 also hold the following technical certifications: MCSE - Microsoft Certified Systems
11 Engineer and CCNA - Cisco Certified Systems Engineer.
12 Q. What is the overall purpose of the Capital Budget Panel’s testimony in this
13 proceeding?
14 A. The purpose of this Panel’s testimony is to describe the levels of spending and
15 projects that make up the individual capital budgets for the Transmission and
16 Distribution (“T&D”) system, for Shared and Business Services and for Customer
17 Services. These capital budgets support the overall capital budgets for this rate plan
18 filing, covering the years 2016, 2017 and 2018. In our testimony, the Panel will
19 explain how the inputs from those three disciplines were incorporated and aggregated
20 into the overall capital budgets for the years in question.
21 Q. Is the Panel sponsoring any exhibits in support of its testimony?
22 A. Yes, we are sponsoring several exhibits that set forth the capital spending envisioned
23 for T&D, Shared and Business Services and Customer Services.
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1 II. TRANSMISSION AND DISTRIBUTION CAPITAL BUDGETS
2 A. The Selection Process for Capital Projects
3 1. General Description of the Process
4 Q. Please explain the process PSEG LI follows when it prepares its T&D capital
5 spending budgets.
6 A. We prepare a multi-year capital plan using a consistent process that incorporates
7 technical review, economic evaluation, authorization, fiscal review, and project due
8 diligence. The overall intent is a process that supplies information that is needed to
9 successfully prepare PSEG LI’s proposed capital budgets while ensuring that planned
10 projects are prudent and appropriate, and that questions regarding program decisions
11 can be answered. The process of preparing a year’s budget evolves throughout the
12 year as new information becomes available. This information is then communicated
13 to the budget representatives. All capital budgets are ultimately subject to review and
14 approval by the LIPA Board of Trustees.
15 Q. Was the 2014 capital spending plan the first capital plan developed by the PSEG
16 LI T&D team?
17 A. Yes, but the responsibility was not entirely PSEG LI’s. The T&D 2014 capital
18 project costs were budgeted at $255.8 million. National Grid, which was previously
19 responsible for running the LIPA system, provided the initial list of capital projects,
20 including cost estimates. During July and August 2013 the PSEG LI T&D transition
21 team participated in the capital budget process with LIPA and National Grid,
22 including the review of project justification documents. The team prioritized the
23 proposed projects by risk score to arrive at the final list of recommended projects.
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1 Q. Was the 2015 budget the first year’s capital spending plan for which PSEG LI’s
2 T&D management has sole responsibility?
3 A. Yes it was.
4 Q. What is the significance of the 2015 capital budget in this rate process?
5 A. The same processes used to develop that T&D 2015 capital spending plan were also
6 used in the processes that underlie our capital budget plans for the three years of the
7 rate plan.
8 Q. Please describe how the T&D capital budgets were developed.
9 A. We developed separate budgets for 2016, 2017 and 2018 based on the anticipated
10 levels of blanket and specific projects in each of those years.
11 Q. Does the Company employ any specific processes to analyze projects that should
12 be included in the T&D capital budget?
13 A. Yes. The capital process involves multiple layers of analyses, review, approval and
14 monitoring, as follows:
15 • Engineers determine where investment is most needed to keep the electric
16 T&D system functioning at a safe and reliable level. Engineers may also
17 propose projects representing opportunities for economic benefits, such as
18 business growth or cost containment and for customer satisfaction
19 improvement.
20 • Project managers oversee project progress, including spending.
21 • Department Directors and Vice Presidents, working with planning groups,
22 determine that PSEG LI is allocating resources optimally and consistent with
23 strategic objectives, and perform high-level reviews.
24 • PSEG LI Finance and the lines of business coordinate funding requests,
25 ensure proper documentation is prepared and monitor plan versus actual
26 spend.
27 • Senior management at PSEG LI, through its Utility Review Board (“URB”),
28 reviews, approves and monitors the progress of the capital investments of
29 PSEG LI being made on behalf of LIPA.
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1 2. Drivers of the Process
2 Q. Are there any particular factors that drive spending determinations in the
3 process?
4 A. Yes. The drivers of capital projects expenditures on T&D system expenditures that
5 are needed to provide service to customers, in general, can be broken into five
6 categories: 1) customer service and mandated work, 2) regulatory, including federal,
7 regional and state requirements, 3) projects designed to meet and maintain reliability
8 criteria, specifically those established under the OSA, 4) projects driven by load
9 growth, and 5) projects driven by economic factors.
10 Q. Please describe the customer service and mandated projects.
11 A. Customer service capital projects are directly related to the obligation to serve
12 customers. These include new customer additions and upgrades to service
13 connections. These costs are offset to some extent based on customer
14 reimbursements when the expenditures exceed the tariff provisions which provides
15 for allowances based on distances and size of customer load additions. The capital
16 budget includes funds for these investments with projected levels based on historic
17 expenditures and reimbursements. Mandated work projects included in our budget
18 are projects that are required to be performed due to mandates or work necessitated
19 by other public work projects, e.g., modification to roads and railroads that may
20 require relocation of our facilities.
21 Q. You also mentioned a regulatory driver that affects capital spending. Please
22 describe how regulations affect spending.
23 A. The second major category focuses on compliance with all regulatory standards and
24 mandates as well as achievement of reliability performance measures. These
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1 objectives are met by reviewing current operations, projecting forecasted loads,
2 evaluating reliability standards and reviewing reliability performance across the T&D
3 system. Mandatory reliability standards and requirements include those required by
4 North American Electric Reliability Corporation (“NERC”), Northeast Power
5 Coordinating Council (“NPCC”), New York State Reliability Council (“NYSRC”)
6 and New York Independent System Operator (“NYISO”). In addition, LIPA has its
7 own T&D Planning Criteria & Guidelines document that PSEG LI is currently using,
8 and that enhances those requirements. 1 NERC’s recent approval of the revised
9 definition of the term Bulk Electric System (“BES”) is also having a significant
10 impact on the transmission system because the Long Island system had not been
11 subject to a majority of those reliability standards under the previous definition.
12 Q. Please explain the additional requirements regarding BES.
13 A. Section 215 of the US Energy Policy Act of 2005 amended the Federal Power Act to
14 require that FERC approve mandatory and enforceable reliability standards for the
15 bulk power system and to create an electric reliability organization with FERC
16 oversight within the United States. FERC gave NERC the responsibility for
17 developing and enforcing these standards governing the reliability of the BES.
18 On March 20, 2014, FERC approved the revised NERC definition of BES, as
19 envisioned in FERC Order Nos. 743, 773, and 773-A. The definition includes bright-
20 line core criteria with various enumerated inclusions and exclusions. As a result of
21 the application of these BES definition provisions, all elements and facilities
1
See http://www.lipower.org/pdfs/company/projects/energyplan10/energyplan10-e6.pdf.
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1 necessary for the reliable operation and planning of the interconnected bulk power
2 system will be included as BES elements. FERC found that the modified definition
3 of “bulk electric system” improves upon the previous definition by establishing a
4 bright-line threshold and removing language that allows for broad regional discretion.
5 Q. Please describe the revisions to the definition of the BES.
6 A. The BES is generally defined as the electric generation resources, transmission lines,
7 interconnections with neighboring systems and associated equipment operated at
8 voltages of 100kV or higher. Radial transmission facilities serving only load with one
9 transmission source are not included in this definition. Facilities used in the local
10 distribution of electric energy are also not included.
11 The effective date of the revised BES definition was July 1, 2014. Newly
12 included BES elements will only become subject to relevant NERC reliability
13 standards 24 months after the effective date of the revised BES definition. As such,
14 the compliance enforcement date for newly included BES elements will be July 1,
15 2016. The new definition has a significant impact on LIPA, as essentially the entire
16 LIPA 138kV system and associated elements will now be subject to applicable NERC
17 Reliability Standards. Consequently, it is expected that LIPA will register with
18 NERC as a Transmission Planner (“TP”) and a Transmission Operator (“TOP”)
19 sometime in year 2016. Presently, there are over 100 approved NERC Reliability
20 Standards (113 to be exact), each with multiple requirements. These Standards cover
21 all aspects of utility planning and operations, including real time operations, critical
22 infrastructure protection, planning, vegetation management and control and
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1 protection. LIPA will be an applicable entity for many of the Standards. In general,
2 NERC does provide implementation periods to allow for compliance with new and
3 newly applicable NERC Reliability Standards. Such implementation periods vary by
4 individual Standard and require corrective action plans to be in place. Nevertheless,
5 there will be additional capital spending requirements associated with meeting these
6 new, more rigid requirements.
7 Q. Another driver you mentioned as affecting capital expenditures was compliance
8 with the reliability metrics in the OSA. Please describe that process.
9 A. Reliability driven projects are undertaken to achieve or maintain reliability standards
10 to Long Island customers. Example of this type of project includes replacement of
11 underground cables that have reached the end of their useful or have experienced
12 repeated failure.
13 PSEG LI currently provides safe and best in state reliable service amongst the
14 overhead serving utilities as measured through its achievement of established
15 Customer Average Interruption Duration Index (“CAIDI”), System Average
16 Interruption Frequency Index (“SAIFI”), and System Average Interruption Duration
17 Index (“SAIDI”). Although the T&D system is performing at high levels of
18 reliability, the system is facing challenges as it ages and additional expenditures to
19 maintain and improve reliability are required.
20 Q. The next driver of capital expenditures you mentioned was load growth. Please
21 explain how load growth factors in as a driver of capital expenditures.
22 A. Most of the capital planning projects are dependent on the growth and character of
23 load on Long Island. Load growth occurs from generic system growth, (e.g., general
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1 increases in customer use throughout the system) and major load additions, (e.g., new
2 commercial and residential developments). These additions also result in upgrading
3 T&D lines and substations (e.g., reconductoring of existing lines, new construction,
4 and new and/or addition to substation capacity). As shown in Exhibit____ (CBP-1),
5 PSEG LI’s most recent forecast (completed November 2014) shows peak load
6 growth, prior to energy efficiency and renewables, to be about 1.8% per year from
7 2015 – 2018. With existing programs in place to encourage energy efficiency, peak
8 load growth is about 0.1% per year.
9 Q. What is the primary driver for PSEG LI’s summer peak demand?
10 A. The peak demand is driven primarily by residential air conditioning loads, as Long
11 Island is a summer peaking system and residential customers represent the majority of
12 the summer sales base. As shown in Exhibit ___, (CBP-1), the record Zone K peak
13 of 5,935 MW occurred in 2011. On Long Island approximately 1000 MW of
14 incremental peak load occurs for less than 100 hours per year, but the system must be
15 built to reliably meet peak demand at any time. A peak load forecast is derived from
16 the sales forecast (developed as explained in the testimony of the Sales and Revenue
17 Forecasting Panel) using factors obtained from load research analysis. In addition, an
18 Area Load Pocket load forecast is prepared in a procedure that distributes the
19 projected system peak load increase into each area, coincident with the system peak
20 and predicting each area’s own peak. Individual substation load is forecasted for the
21 next ten years based on historical trends for the individual substation/circuit service
22 area plus known major load additions planned for future years.
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1 Q. Another factor you mentioned was economic drivers. What is an economic
2 driver and how does it influence capital spending?
3 A. Projects that increase the financial efficiency of the system and provide economic
4 payback are also studied and recommended as part of the capital budget process.
5 These include, for example, transmission system modifications that avoid the need to
6 dispatch uneconomic generation.
7 Q. Does PSEG LI forecast the need for capital for periods longer than just one
8 year?
9 A. Yes, of course. The Company has numerous T&D projects underway to meet the
10 various categories we just discussed and, of course, some on-going projects were
11 underway before January 1, 2014. Capital projects often take several years to
12 complete and the Company typically utilizes a multi-year approach to capital
13 planning. The PSEG LI T&D capital investment plan for electric capital projects that
14 are expected to be pursued during the Rate Plan period is shown on Exhibit ___
15 (CBP-2).
16 3. Types of Projects
17 Q. Are capital projects differentiated?
18 A. Yes, they are. In general, the different categories of capital projects expenditures are
19 further classified into blankets and specifics. Blanket projects are an aggregate of
20 small, routine, repetitive scopes of work that cost less than $1 million each to
21 complete (e.g., pole replacement, customer connections). Specific projects are those
22 for which the total anticipated capital expenditure is $1 million or more. Each is
23 discussed in the following sections.
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1 Q. What sort of projects qualify as specific projects?
2 A. As noted, specific projects are defined as projects with an estimated cost of greater
3 than $1 million. These specific projects comprise approximately 50% of the capital
4 budget, and are primarily associated with load growth (e.g., new transmission and
5 substations; upgrade or expansion of existing substations; additional distribution
6 system feeders and reconductoring projects) or reliability (e.g., substation
7 reconfigurations; condition-based transformer or switchgear replacements).
8 Q. What sort of projects fall under the blanket project category?
9 A. Blanket projects are broadly composed of Inside Plant and Outside Plant work. Inside
10 Plant work is performed within a substation and consists of work such as transmission
11 and distribution breaker replacements; capacitor banks; control and protection
12 replacements/upgrades; and substation equipment life extension or
13 replacement/upgrades. Outside Plant blanket projects are associated with work on the
14 transmission and distribution system external to substations, such as pole
15 replacements (transmission & distribution); distribution cable replacements; New
16 Business; and Public Works.
17 4. Need for a Project
18 Q. How is project need identified?
19 A. The Company builds its annual capital plans from proposed projects that were
20 identified to satisfy a specific need. With the need identified, project justification
21 documents (“PJDs”) are created. These documents include:
22 • Description: Brief statement of the proposed project
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1 • Problem Definition: Particular condition that needs to be addressed, e.g.,
2 overloaded equipment, amount of unserved load, and regulatory requirement.
3 • Alternative: These alternatives can either solve the issue or defer the need
4 date using interim steps. Typical information included on the alternatives are
5 costs, feasibility, impact on rates (net present value of revenue requirements),
6 as well as any specific advantages or disadvantages of the alternative.
7 • Recommendation: Summary of the recommended solution as well as the
8 basis. This also can highlight other benefits of the proposed solution, e.g.,
9 meeting longer term needs or solving/deferring other problems in another
10 area.
11 Other information contained in the PJD may include benefit to cost ratios
12 (e.g., value of MW capacity divided by project cost), economic benefit/payback (e.g.,
13 projects undertaken to reduce must run or uneconomic generation), as well as
14 customer load that would otherwise be unserved without the project. Also included
15 are supporting documents relative to the projects. For example, this can consist of
16 sample reports and presentations to management and others as the project was
17 developed, and economic evaluations of the alternatives and options supporting the
18 decision. The balance of the PJD includes a scope of work (which will be more
19 detailed for near term projects as more information and engineering assessment is
20 available) and information on the risk scoring which is discussed in the following
21 section.
22 5. Project Prioritization and Risk Evaluation
23 Q. With the project’s need identified, what process does the Company follow to
24 establish a priority or queue for selecting one project over another?
25 A. PSEG LI follows a Project Prioritization and Risk Evaluation protocol that is based
26 on industry-wide accepted risk assessment methodology that considers consequences
27 and likelihood of adverse events in a case of not funding specific projects. Basic
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1 concepts currently used at Public Service Electric and Gas Company (“PSE&G”) and
2 PSEG LI are the same and full consolidation of tools and processes is planned in
3 2015. Under this protocol a project’s selection is a two-step process. The first step is
4 an evaluation of the risk of not funding specific projects, through the “Project Level
5 Risk Analysis” described below. In this process all individual projects are scored
6 from 1 to 100 based on risk determined by multiplying probability of occurrence and
7 the level of adverse impact in case the specific project is not funded.
8 The second step is selection of the portfolio of projects for funding within the
9 specific budgeting cycle, through the “Portfolio/Budget Level Risk Analysis and
10 Management” process discussed below. Projects with the highest risk score are
11 prioritized for funding. Cut-off funding level by risk score is determined based on
12 risk tolerance for system and company performance levels relative to targets (e.g.,
13 CAIDI, SAIFI and other reliability measures, cost, customer satisfaction, regulatory
14 compliance) and availability of funding.
15 Q. Please describe the Project Level Risk Analysis.
16 A. Individual projects are evaluated via use of the PSEG LI Risk Scoring model, an
17 Intranet based tool. This tool considers four strategic areas: Regulatory Compliance
18 (environmental and system reliability, for example), Customer Satisfaction (power
19 quality, number of outages experienced by customers, level of service, for example),
20 Financial Performance (potential impact on rates of investments to reduce
21 uneconomical generation, for example), and Technical Performance (impact of the
22 project on reliability metrics, number and duration of outages, aging assets and
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1 probabilities of failures, for example). Each of these areas is evaluated based on
2 consideration of 30 risk drivers using individual scales (1 – 10) to determine level of
3 adverse impact. For example, an event/project impacting 25,000 customers will be
4 scored higher than event/project impacting 10,000 customers. The score is then
5 adjusted for likelihood, that is, the probability of event (e.g., an event with a 30%
6 probability will be scored higher than an event with only 1% probability), as well as
7 the time period that the system is exposed to the risk and, finally, the opportunity to
8 identify an asset “mis-operation” prior to its failure.
9 The overall project or program risk score is determined as the product of the
10 Impact and Likelihood scores. Projects with higher level of impact and higher level
11 of probability have higher risk score. Starting in 2015, PSEG LI will use an
12 Investment Evaluation System (“IES”) developed by the UMS Utility Consulting
13 Group that is consistent across all PSEG companies. Existing and future systems are
14 designed to quantify the business value and risk associated with each investment,
15 both specific and blanket projects. Evaluation factors used in the project value
16 include impacts of legal mandate, operational requirement and the need to preserve
17 continuity of safe and reliable basic service to customers. Impacts to the balanced
18 scorecard from the portfolio of projects selected are also calculated. Before and after
19 the implementation of IES, all of these elements are considered through computer-
20 aided mathematical calculation, coupled with rigorous management scrutiny and
21 judgment, to determine the optimal portfolio combinations of work to be resourced
22 and performed. Both the existing LIPA risk scoring tool and the new IES model
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1 ensure a consistent and uniform basis for major evaluation and comparison between
2 projects. Projects that are on the budget margin or scored similarly are subject to
3 further review to ensure that they are ranked accordingly.
4 Q. Once projects are scored for risk, what is the next step in the process?
5 A. The next step in the process is a Portfolio/Budget Level Risk Analysis and
6 Management. The selection of a portfolio of projects for funding is the next step after
7 evaluating and risk scoring of all proposed individual projects and programs. The
8 number of proposed projects and cumulative requested funding is typically
9 significantly higher than available funding. Consequently, the process of prioritizing
10 and selecting a portfolio of projects for funding is an exercise in optimizing level of
11 risk for system and company performance with level of investment and capital budget
12 spending.
13 Q. What does that process entail?
14 A. The process of selecting a portfolio of projects for funding is driven by the approach
15 of prioritizing projects with the most significant consequences and the highest
16 likelihood of adverse impact on system and company performance. Projects with
17 higher risk score (scaled from 100 to 0) will have priority over projects with lower
18 risk score. Projects with the lowest risk scores may not be selected, and the “cutoff”
19 line for the funding of projects with higher risks score (e.g., projects addressing
20 situations of higher consequences with higher probability of adverse impact) depends
21 on available funding and/or acceptable system risk.
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1 Based on definitions of risk levels used in the PSEG LI Risk Scoring tool, a
2 risk score cutoff of 81 and above is considered sub-optimal and can result in a “run to
3 failure” mode of operation of the system, with no, or a minimum amount of, proactive
4 and preventive maintenance and replacements of equipment, even in a case of
5 equipment far beyond its life expectancy and/or availability of spare parts and
6 manufacturer support. This will result in accelerated deterioration of system
7 reliability over time, increased asset life cycle cost, and suboptimal system operation
8 with increasing dispatch of uneconomic generation. The project portfolio selection
9 for 2015 is based on risk cut off level of 72 which is considered an acceptable level of
10 risk. Generally the same risk level is used for portfolio selection for the 2016-2018
11 budgets. This Rate Plan does include a limited number of representative projects that
12 are dependent on “real estate development/customer lump load” additions such as
13 development of the Nassau Coliseum, RXR at Cannon, Heartland, and SUNY Stony
14 Brook R&D Park. The timing and impact of these outer year projects remains
15 uncertain, which may imply a slightly reduced risk score. Consistent with recent
16 experience it is our expectation that these several of these type projects will be
17 developed in the 2017-2018 timeframe.
18 6. Approval Mechanism
19 Q. Are there internal controls and reviews applied to the capital budget process?
20 A. Yes. Projects are subject to the approval of our Utility Review Board (“URB”).
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1 Q. Please describe the URB.
2 A. Projects for which funding is required must receive formal URB approval. The URB
3 is chaired by David M. Daly, the President of PSEG LI and includes several other key
4 members of the leadership team at PSEG LI. The URB reviews each new project or
5 existing project that requires funding that exceeds 110% of previously approved
6 levels. The URB reviews the multi-year capital plan and individual project requests
7 at an annual project review meeting held in the Fall. The URB also reviews any
8 emergent capital investment requests that occur during the year as needed.
9 Q. Is there a threshold for projects that must be approved by the URB?
10 A. Projects are submitted either on a total cost basis for approval or in a phased manner
11 to ensure that risks are considered. Projects over $1 million are submitted to the URB
12 as individual projects, while those less than $1 million may be aggregated into a
13 program or blanket for review.
14 Q. Has there been a shift over time in the major areas of capital spending?
15 A. Yes. The graphs below show major areas of spend for the rate plan years (2015 –
16 2018) with a comparison of the adjusted 2006 – 2012 T&D Capital budget (adjusted
17 by removing IT & Meter budget dollars). This shows the shift of dollars from
18 Interconnect costs (2006 – 2008) to load related projects for budget years 2015 –
19 2018.
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$400,000,000
$350,000,000
$300,000,000 Transmission Reliability
$250,000,000 Substation Reliability
Other
$200,000,000
New Business
$150,000,000
N-1-1
$100,000,000
Distribution Reliability
$50,000,000 Load
$0
2015 2016 2017 2018
Budget Budget Budget Budget
1
2
3 B. Major Projects
4 Q. Please describe some of the major projects that are represented in the capital
5 budgets.
6 A. We break down the projects into a Sample Project Overview. The first projects we
7 discuss are capacity projects. The capital forecast is prepared as a collaborative effort
8 with contributions from subject matter experts representing all affected areas of the
9 company. Proposals are developed by the functional areas including T&D Planning,
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1 Substation Maintenance, Control and Protection as well as by areas with focus on
2 investments that are applicable across the electric system. Projects are initiated for a
3 number of internal and external entities including large and small customers,
4 municipalities and Company requirements. Customer requirements include new
5 services, line extensions and reinforcements intended to support the addition of
6 incremental new electric load. Government agencies annually provide a list of
7 proposed highway improvements that require the relocation of Company electric
8 facilities. The Company also generates projects that are driven by regular inspections
9 that identify areas of concern, are the result of system planning studies, or are needed
10 to correct degradation in system or equipment performance. For example, the
11 Company’s T&D Planning group conducts circuit analyses, load flow and other
12 studies to identify which circuits have reached loading limits or have the potential to
13 create reliability issues. T&D Planning then evaluates and develops alternatives to
14 address the need. T&D Planning also analyzes the demands of the electric
15 transmission system over a longer period and proposes projects that are forecast to be
16 needed to alleviate these system issues. The Company’s Substation Maintenance
17 group identifies projects from field investigations and proposes solutions to address
18 concerns. Information gained from regular inspections conducted by field
19 maintenance staff as specified within PSEG procedures is also used to support the
20 development of projects.
21 Q. Please provide some examples of specific projects that fall into this category?
22 A. The following describes two major projects being proposed:
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1 1. Plainview to Ruland Road – New 69kV Transmission Line
2 This project is the proposed installation of a new 69kV circuit from the existing
3 Ruland Road substation to Plainview substation with an expected in service date of
4 2017. Located in PSEG LI’s North East Nassau load pocket, the existing 69kV
5 circuit between the Ruland Road and Plainview substation experiences post
6 contingency overloads for the loss of the Syosset Breaker 630 or for the loss of
7 Syosset to Woodbury 69kV transmission line. Additionally, several major load
8 additions with a total of 30 MVA are proposed for this Plainview area in the near
9 future (2-5 years) that would further exacerbate the loading on the existing Ruland to
10 Plainview 69kV line. These load additions also could also require a new distribution
11 substation (preliminarily identified as Old Bethpage.) Since the need for the
12 transmission circuit is prior to the new substation, the recommendation is to route the
13 transmission in such a way as to facilitate the future interconnection to the new
14 substation. A feasible transmission route has been identified.
15 Alternatives to this project include the reconductoring of the existing
16 Plainview to Ruland 69kV circuit and investigation of the potential implementation of
17 Utility 2.0 options that will be addressed in a separate filing. The reconductoring of
18 the existing Ruland to Plainview 69kV circuit does not support the future
19 interconnection of new substation without incurring additional cost to bring the line to
20 the substation, and it would not provide increased reliability during maintenance
21 outages. The new underground alternative is significantly more expensive than the
22 overhead option.
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1 2. Kings Highway New 138kV Substation
2 This project constructs a new 3 bank 138/13kV distribution substation with an
3 expected in-service date of June 2017. The cost estimate for the project includes
4 land, transmission interconnection, substation as well as distribution Conversion and
5 Reinforcement (“C&R”). The project need was first identified in 2009 with targeted
6 installation in 2014, and then deferred to 2015 due to difficulty locating a site for the
7 substation. Real Estate has identified land and is pursuing property resulting in a
8 request for approval and funding of the project with an expected in service date prior
9 to the summer of 2017. The Kings Highway substation is being proposed to solve
10 existing normal and contingency overloads on distribution feeders and transformer
11 banks at five western Suffolk substations. The substation will also provide the
12 necessary capacity in the area to cover the potential loss of the entire Hauppauge 6H
13 Substation which serves the Hauppauge Industrial Park (“HIP”), one of the largest
14 industrial parks in the US, and an important business complex. Load in the area is
15 also expected to grow rapidly in the next few years as zoning rules are being changed
16 with the installation of sewers in the area to allow higher and larger office buildings.
17 Another benefit is that the substation will help reduce the load being served from the
18 Indian Head and Smithtown substations, which in turn will help to defer the need to
19 reconductor transmission lines supplying the Smithtown load pocket, which are
20 reaching their capacity limits.
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1 Alternatives to the project are limited, temporary in nature (i.e., it will still
2 require a new substation in the area) and result in more cost. With respect to
3 construction feasibility, three of the five western Suffolk substations have space
4 limitations for expansion, thus removing expansion of those stations as options. The
5 two substations where reinforcements can be done are Pilgrim and Indian Head.
6 Costs for these alternatives have higher revenue impacts than the proposed project.
7 Further, the Indian Head alternative would advance the need for transmission
8 reinforcement to the Smithtown load pocket, increasing that cost, and it would not
9 provide the backup capacity for the HIP that the proposed Kings Highway substation
10 provides.
11 Other major projects and their budgets are listed in Exhibit __ (CBP-2).
12 C. Blanket Projects
13 Q. You mentioned previously that some of the capital projects are necessary to
14 maintain and improve system reliability. Please give examples of these types of
15 projects.
16 A. Exhibit ___ (CBP-2) lists a number of blanket projects designed to enhance
17 reliability. The following is a description of some of the blanket-type system
18 improvement programs PSEG LI utilizes to maintain the reliability metrics within the
19 band of targeted performance and to improve/maintain the customer’s perception of
20 their electric reliability.
21 1. Circuit Improvement Program (“CIP”)
22 CIP addresses the system’s poorest performing distribution circuits (the program
23 typically targets approximately 4-5% of the total overhead circuits). These circuits
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1 have a large multiplier effect on overall reliability since the worst 5% performing
2 circuits impact 35% of the total system-wide customer interruption outage minutes.
3 In the period, 2007- 2013, 208 circuits were targeted for reinforcement, representing a
4 total of 2,650 primary circuit miles.
5 2. Multiple Customer Outages (“MCO”)
6 The MCO program targets customers with four or more non-storm related
7 interruptions over the last 12 months. About 4% of customers are currently
8 considered MCO customers (10% in the aggregate when including major storm data).
9 With addressing the most affected customers in mind, the primary focus has been on
10 customers experiencing six or more outages over the relevant time period. A large
11 component of these MCO customers reside on radial branch line, rear property
12 overhead construction in heavily treed areas where previous reliability programs have
13 reduced impact in the long term. Without circuit redesign or alternate supplies being
14 constructed under MCO, these customers would likely continue to suffer poor
15 performance.
16 3. UG Cable Testing and Replacement Program
17 This program is associated with the Distribution Cable Replacement blanket
18 identified on Exhibit ___ (CBP-2). Historically, exit feeder (underground distribution
19 cables coming out of the substation switchgear cubical and terminating at the riser
20 pole connecting to the overhead line and the beginning of the distribution circuit)
21 replacement had been the focus of the primary distribution cable reliability program,
22 and was successful in maintaining a fairly constant rate of exit failures under a
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1 targeted replacement program. A non-destructive cable testing program was initiated
2 which improved decision making for the program, helping to reduce the number of
3 previous exit failures by half over the past four years.
4 4. Automatic Sectionalizing Unit (“ASU”) Installation Program
5 ASU’s are “smart switches” which are typically deployed in a mid-point
6 configuration, where one mid-point ASU is in a normally closed state and one or
7 more normally open. ASU’s are deployed at the end points where the feeder connects
8 to an adjoining feeder. This scheme allows for reduced customers being affected by
9 sustained interruptions by isolating a line fault (auto-sectionalizing) and then allowing
10 system operators to quickly (via radio communications) restore service to additional
11 customers by back feeding from the adjoining circuit. Since the program’s inception,
12 over five million sustained customer interruptions were averted due to the ASU
13 program. Because most of the 2016-18 ASU installations are expected to be installed
14 utilizing FEMA funding, this initiative is not expected to have a significant impact on
15 the capital budget during the Rate Plan.
16 5. Transformer Load Management (“TLM”)
17 Customer electric loads can increase over time to a point where they may overload
18 their transformer and cause an outage. The TLM program evaluates and prioritizes
19 distribution transformer loads using a prediction algorithm. The program seeks to
20 proactively replace transformers in advance of an emergency replacement during a
21 heat storm.
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1 6. Transmission & Distribution Wood Pole Inspection/Replacement
2 Programs
3 Transmission and Distribution wood poles are inspected for adequate strength on a
4 regular basis. Poles with insufficient strength are replaced. This is an ongoing
5 process. Pole replacement funding is addressed via two separate budget line items.
6 Transmission pole replacements are budgeted at approximately $1.5 million for 2016,
7 since a portion of the replacements are anticipated to be funded as part of the FEMA
8 work. Distribution pole replacements/reinforcements are budgeted at approximately
9 $8.2 million for 2016, since a portion of the replacements are anticipated to be funded
10 as part of the FEMA work.
11 D. Utility 2.0
12 Q. Please discuss treatment of Utility 2.0 programs in the capital budget?
13 A. Since the Utility 2.0 program has not yet been approved for the activities proposed
14 during the Rate Plan years, the impacts of the Utility 2.0 plans have been removed
15 from this Rate Plan filing, although the Utility 2.0 filing under consideration by the
16 Department of Public Service (“DPS”) and LIPA is described in the testimony of the
17 Utility 2.0 and Energy Efficiency Panel. PSEG LI continues to believe the proposed
18 Utility 2.0 solutions are preferred for recommended T&D applications, particularly in
19 addressing design deficiencies on the South Fork of Long Island, and PSEG LI will
20 continue to recommend Utility 2.0 solutions to the LIPA Board and in the parallel
21 Utility 2.0 track. Additional information on PSEG LI’s “Utility 2.0 Long Range Plan
22 – Update” (“Utility 2.0 Update”) dated October 6, 2014, is available at:
23 https://www.psegliny.com/page.cfm/AboutUs/PressReleases/101414-hearing.
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1 E. NERC Bulk Electric System Reliability Projects
2 Q. Earlier in your testimony, you discussed the need for increased capital spending
3 to meet new reliability requirements. Please describe that process.
4 A. We were referring to what are called our IRP/RFP N-1-1 Project Impacts. The
5 projects shown in the capital budgets represent a one-time cost to bring existing
6 facilities into compliance, based on currently approved NERC standards. Revisions
7 to existing standards or additional standards could add to these cost estimates. As
8 noted above, a series of capital projects will be required to meet the newly applicable
9 and expanded NERC Transmission Planning (“TPL”) standards, including “TPL-001-
10 4.” This Standard specifies the performance criteria that must be met for multiple
11 element contingencies characterized by loss of a BES element, followed by system
12 adjustments, followed by loss of another BES element. This multiple element
13 contingency is commonly referred to as “N-1-1.” Two capital projects have been
14 identified to meet NERC TPL performance criteria for N-1-1 events:
15 1. Syosset to Shore Road 138kV circuit:
16 Based on internal studies of the Glenwood area, N-1-1 criteria violations are observed
17 on the existing East Garden City to Carle Place circuit 138-361 for loss of Y50
18 followed by loss of Glenwood GT – Glenwood North Bus circuit 138-366. Other N-
19 1-1 combinations involving loss of Y50 also result in criteria violations. Addition of a
20 new 138kV circuit from Syosset to Shore Road substations will eliminate all N-1-1
21 violations in the Glenwood area.
22 2. East Garden City to Valley Stream 138kV circuit:
23 Based on internal studies of the Barrett area, N-1-1 criteria violations are observed on
24 the existing East Garden City to Valley Stream 138kV circuit 138-262 for loss of
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