Final Report on an Audit of Emera Maine’s Management Practices, Customer Information System, and Service Quality Public Version Confidential Materials Redacted Docket 2015-00360 Presented to: State of Maine Public Utilities Commission Presented by: The Liberty Consulting Group 279 North Zinns Mill Road, Suite H Lebanon, PA 17042-9576 (717) 270-4500 (voice) admin@libertyconsultinggroup.com August 8, 2016 Public Utilities Commission State of Maine Table of Contents Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Table of Contents I. Introduction ............................................................................................................................... I-1 A. Audit Scope and Objectives .............................................................................................. I-1 B. Audit Methods .................................................................................................................. I-1 C. Summary of Key Findings, Conclusions, and Recommendations .................................... I-2 1. Transmission and Distribution ..................................................................................... I-2 2. Customer Service ......................................................................................................... I-3 3. Implementation of the New CIS ................................................................................... I-5 D. Liberty’s Team .................................................................................................................. I-6 II. T&D System Operations and Maintenance ............................................................................ II-1 A. B. C. D. E. F. G. H. I. I. J. K. L. M. N. O. P. Introduction ..................................................................................................................... II-1 Field Observations .......................................................................................................... II-2 Findings - T&D Systems Operations and Dispatch ........................................................ II-4 Conclusions - T&D Systems Operations and Dispatch ................................................ II-10 Recommendations - T&D Systems Operations and Dispatch ...................................... II-11 Findings - T&D System Maintenance .......................................................................... II-11 Conclusions - T&D Systems Maintenance ................................................................... II-21 Recommendations – T&D Systems Maintenance ........................................................ II-22 Findings - T&D Reliability ........................................................................................... II-22 Conclusions - T&D Reliability ..................................................................................... II-29 Recommendations – T&D Reliability .......................................................................... II-29 Findings - Budgeting..................................................................................................... II-29 Conclusions –Budgeting ............................................................................................... II-32 Recommendations -Budgeting ...................................................................................... II-32 Findings – Managing Field Work ................................................................................. II-32 Conclusions – Managing Field Work ........................................................................... II-35 Recommendations – Managing Field Work ................................................................. II-35 III. Customer Service ................................................................................................................. III-1 A. Background .................................................................................................................... III-1 B. Findings.......................................................................................................................... III-1 1. Customer Service Organization & Staffing............................................................... III-1 2. Customer Service Costs............................................................................................. III-7 3. Customer Satisfaction Measurement ......................................................................... III-8 4. Customer Complaint Resolution ............................................................................... III-9 5. Account Creation & Management ........................................................................... III-10 6. Meter Reading & Meter Services ............................................................................ III-11 7. Customer Billing ..................................................................................................... III-12 8. Payment and Collections ......................................................................................... III-13 9. Contact Center Operations ...................................................................................... III-17 10. Revenue Protection.................................................................................................. III-23 C. Conclusions .................................................................................................................. III-25 D. Recommendations ........................................................................................................ III-37 August 8, 2016 Page TOC-i The Liberty Consulting Group Public Utilities Commission State of Maine Table of Contents Audit of Emera Maine Docket 2015-00360 Final Report-Public Version IV. Implementation of the New Customer Information System ................................................ IV-1 A. Background .................................................................................................................... IV-1 B. Findings.......................................................................................................................... IV-1 1. Elements of Effective CIS Implementation Management ......................................... IV-1 2. Management’s Business Case for the New CIS ........................................................ IV-3 3. CU-CIS Governance and Project Management ......................................................... IV-3 4. Resource Management .............................................................................................. IV-8 5. Schedule Management ............................................................................................ IV-10 6. Contract Management ............................................................................................. IV-11 7. Scope Change/Order Management .......................................................................... IV-14 8. Project Phases .......................................................................................................... IV-15 9. Cost Management .................................................................................................... IV-16 10. Project Quality Assurance ....................................................................................... IV-16 11. Risk Management .................................................................................................... IV-18 12. Post Go-Live............................................................................................................ IV-18 C. Conclusions .................................................................................................................. IV-20 D. Summary of Management’s Performance in CU-CIS Project Management ............... IV-24 August 8, 2016 Page TOC-ii The Liberty Consulting Group Public Utilities Commission State of Maine Introduction Audit of Emera Maine Docket 2015-00360 Final Report-Public Version I. Introduction A. Audit Scope and Objectives The State of Maine Public Utilities Commission (Commission) initiated a solicitation (RFP# 201604082) seeking a consultant to conduct a management audit focused on three aspects of the management and operations of the Bangor Hydro District (BHD), or South Operating Region (SOR) and the Maine Public Service (MPD), or North Operating Region (NOR), which comprise the two operating districts of Emera Maine (Emera):  Customer service functions  Transmission and Distribution (T&D) operation and reliability  Customer Information Systems (CIS) procurement and implementation. The Commission selected The Liberty Consulting Group (Liberty) to perform this focused management audit of its transmission and distribution (T&D) system. This report presents the results of Liberty’s analysis, our findings, conclusions, and recommendations, which include the just and reasonable level of costs to include in Emera's revenue requirement and retail rates. B. Audit Methods Liberty conducted this review over a concentrated, six-week period designed to produce a final report that would prove useful as part of the Commission’s review of the Emera rate filing under consideration in Docket 2015-00360. We conducted it through a series of coordinated:  Data requests seeking written responses and data sets  Interviews conducted according to established agendas, but incorporating the flexibility to address those topics we identified as useful based on the dialogue occurring at the interview sessions  On-site examinations and discussions with management employees at central work locations, such as customer service centers and T&D operations and dispatch facilities  Field inspections of T&D facilities incorporating locations identified as “trouble spots,” recent work locations, and some randomly chosen while in transit in the field. These measures comprise standard activities in our many engagements of this type. What particularly distinguished the work here is the time frame in which we conducted our field work. Such work ordinarily requires significantly longer time, given normal deadlines for written responses, interview scheduling, findings reviews, and other activities. We are indebted to both the Commission Staff and Emera management for providing the extraordinary support it took to complete our review. We spent the better part of two weeks on site early in the project, making a number of in-process requests for written and quantitative information. Company management expedited responses, not awaiting formal requests to “catch up” with their responses. Despite very short notice for second and third-round interviews, management was able to provide our team access to the people and the facilities and locations we desired. We performed the work under the administrative supervision of the Staff. Substantively, the work described in this report (its findings, conclusions, and recommendations) are strictly and August 8, 2016 Page I-1 The Liberty Consulting Group Public Utilities Commission State of Maine Introduction Audit of Emera Maine Docket 2015-00360 Final Report-Public Version entirely our own, as we conducted the audit on a fully independent basis. Nevertheless, the Staff made as much time as we requested and when we requested it to offer substantial background regarding document sources and availability, key Emera resources, and the information we needed to ensure our report’s conformity to regulatory requirements, expectations, and the case schedule. Without the cooperation we received from both Staff and Emera, we could not have provided this report in the time frame available. C. Summary of Key Findings, Conclusions, and Recommendations 1. Transmission and Distribution Liberty examined Emera Maine’s electric systems, T&D system operations and dispatch processes, inspection, repair, and maintenance of electric systems, efforts to minimize intrusion of trees into lines, measures for maintaining T&D reliability, monitoring of work completion rates, capital budgeting, and management of field workers. Our biggest concern lies in the comfort that management has in continuing to accept the level of reliability performance its metrics have shown. Management reflects that acceptance, for example, by targeting continuation of what is a comparatively extremely low level of performance in avoiding customer interruptions (measured by SAIFI, or System Average Interruption Frequency Index). For the short term, management’s targets actually countenance a reduction in performance. Its use of a five-year average incorporates two particularly bad SAIFI years, meaning that an already extremely low level of SAIFI performance could worsen in the current year, while still satisfying management’s target. We do not believe that the conditions (geographical, climatological, and system configuration, for example) in which Emera Maine operates permit superior SAIFI performance when compared with others. On the other hand, neither should it be content with performance at essentially the bottom end of experience. Management should target improvement that would move it up through the fourth quartile. It also needs to assess in the future, based on results achieved and costs incurred to make improvements, the economic practicability of seeking to move into the third quartile. Management failed to complete scheduled transmission and distribution roadside and right of way inspections in 2014 and 2015. It conducted no formal visual inspections on the distribution circuits in the MPD since at least 2011. Good utility practice and the National Electrical Safety Code place substantial importance on inspection performance. A two consecutive year failure to provide the inspections at issues violate good utility practice for promoting reliability. The failure caused management to miss opportunities to identify conditions threatening interruptions. Management has this year begun to actions to resume them, using contractors and an increased number of annual inspections to recover but it will be some time before inspection recovery returns to acceptable norms. Within the confines of its unchallenging reliability targets, Liberty found that the Company’s equipment conditions, based on inspections, and its processes and practices in the areas we examined generally comport with good utility practice for a utility of its size. We do, however, believe that a significant number of improvement opportunities exist, a number of which directly confront the reliability challenges that face management. Specifically, management should: August 8, 2016 Page I-2 The Liberty Consulting Group Public Utilities Commission State of Maine        Introduction Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Strive via its reliability projects to improve its SAIFI (reduced customer interruptions) on a year to year basis, rather than just maintaining average past SAIFI performance. Prioritize reliability projects based on estimated avoided customer interruptions and the cost to do so, and using the calculated reduction in SAIFI after projects are completed as a factor when setting year to year SAIFI targets. Include electronic applications when it updates its outage management system (OMS) to automate a number of manual activities (to minimize delay and work load), from the point of the outage report from the customer to the outage notification to the service crew. Avoid repetition of failure to conduct roadside and right of way inspections of T&D lines. Formally document its storm preparedness processes as part of its System Emergency Operations Plan (SEOP), to prevent confusion when a high impact storm is forecasted. Reduce via training the high number of “no fault found” outage causes, in order to enhance its understanding of outage causes when planning reliability projects. Include “probable lightning” as an outage cause code and use a lightning location service to help determine where lightning protection can be improved. We also found that management does not use a computerized work management system (CMMS) for managing customer and line work. Although the paper-based service order and work order systems have proven adequate to date, at some time in the relatively near future, management should examine the benefits of reduced work load and more effective management that a CMMS may bring, recognizing the need to consider the substantial costs that such systems can entail. A number of recent actions have been taken in recent years to improve operations; they include:  Integrating North and South Operating Regions, bringing on the new Operations Center, and integrating the OMS and SCADA systems, which improve efficiencies in system operations and restoration work.  Developing expected outage data based on past storm impacts, in order to enhance resource preparations for future high impact storms.  Shortening the distribution circuit tree trim cycle in 2014 and conducting special trims on circuits exhibiting tree-caused reliability issues.  Adding a number of transmission and sub-transmission line inspection programs in 2014 and 2015, including five-year roadside ground line inspections, annual thermal inspections, and shortening the drive-by roadside inspections from six- to three-year cycles.  Increasing safety monitoring and field line work supervision and training.  Creating the ability for line and substation workers to work in either region.  Hiring more experienced line and quality assurance supervisors.  Adding supervisors and line worker apprentice and refresher training programs.  Enhancing processes for budgeting and managing capital projects. 2. Customer Service We examined Emera Maine’s practices in managing and operating its customer service functions. We structured our examination of customer service into the overall categories that drive performance effectiveness and efficiency:  Organization & Staffing  Account Creation & Management  Payment and Collections  Satisfaction Measurement  Meter Reading & Services  Contact Center Operations August 8, 2016  Complaints Resolution  Customer Billing  Revenue Protection Page I-3 The Liberty Consulting Group Public Utilities Commission State of Maine Introduction Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Our examination concluded that Emera Maine’s customer service performance overall was weak over the past three years. Management failed to adequately staff its frontline customer service organization to respond to customer requests and inquiries. Call answering performance has fallen well below target levels since 2013. Complaints to the MPUC have increased and customer satisfaction, as measured by J.D. Power and Associates, falls well below panel averages, and remain unsatisfactory. Employee engagement is at its lowest levels in the last three years. Management has more recently taken steps recently to reorganize and identify initiatives to improve performance. They reflect sound measures to address issues contributing to that weak performance. Nevertheless, their preliminary or early status makes it important to monitor their continuing application and implementation in order to verify that they will prove successful on a sustained basis and with reference to meeting customer expectations. In addition to management’s steps, we found a number of other improvement opportunities. In addition to the need to properly staff the frontline customer service organization, management has opportunities to streamline business processes to gain operational efficiencies and improve the customer experience. Staffing problems affected the quality of service at the time when the new CIS went live (June 2015). Contact center staffing was then at its lowest level in two years. Spikes in call volumes increased wait and resolution times and abandoned call rates, producing the worst call-handling performance in five years, and yielding conditions management deemed urgent through early November 2015. Management announced the planned closure of the BHD contact center in 2019 (through attrition) two months prior to go-live, when it was engaged in training and preparing employees for operation of the new CIS. Management decided to go-live with the CIS eighteen months later than planned, and having had to exclude many of planned features to meet that date. Work-arounds and missing functionality affected operations efficiency and effectiveness and the quality of the customer experience following go-live. Facing a substantial list of functionalities missing and defects not resolved at go-live, management instituted what it termed Project Katahdin, which resolved many of these issues within nine months of go-live. There remain a significant number of issues to resolve. The actions begun over the last year to improve customer service performance include:  Project Katahdin addressing issues associated with the new CIS  Post-CIS installation training refresh  Revised non-residential deposit guidelines  Improved Planned Outage Process  Employment of employee-filled customer experience focus groups  Communication of JD Power customer satisfaction results  Screen Pops for CSRs  Outside assessment of the customer contact centers  Outside assessment of the credit and collections process. A number of significant challenges remain to bring customer service to a level of performance that we would consider strong: August 8, 2016 Page I-4 The Liberty Consulting Group Public Utilities Commission State of Maine            Introduction Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Completing deferred CIS items to increase system capabilities and reduce manual processing Upgrading the new CIS Migrating the MPD from the AS400 CIS to the new CIS Consolidating the BHD customer service center operations into the MPD Standardizing work processes between the BHD and MPD Consolidating billing, payment, and collections functions, policies and procedures Aligning services and self-services offered to MPD and BHD customers Addressing outdated AMR MPD meters (Turtle) no longer supported by the vendor Revising storm and business continuity plans Refocusing the organization on the customer Adequately staffing the organization to meet expectations. 3. Implementation of the New CIS Emera Maine brought a new CIS into service in June 2015. Starting from an initially planned December 2013 go-live date at an estimated cost of $19 million, project costs grew to some $30 million for a system with functionalities less than those driving the initial budget. Much of the cost increase and the functionality reduction came from delays that extended the go-live date to June 2015. We examined the planning and management of the CIS, in order to determine the reasonableness of the costs expended through go-live date. Facing what management has described as a CIS at risk of unrecoverable failure, it began in 2010 a process for selecting resources for developing a replacement. First selecting a consultant (AAC) to assist in selecting the principal vendor, management then proceeded, supported by AAC, to select a system provided by Cayenta Utilities. Management also retained AAC to assist in its efforts to oversee work required to develop and implement the new system (the CU-CIS). We examined performance in those areas important in ensuring timely, cost-efficient development and implementation of a CIS that had appropriate capability and functionalities for supporting Company needs. We found that management failed in a number of respects to adopt practices sufficient to provide for adequate management and oversight of system development and implementation. No single failure likely proved determinative, but their combination produced risks for which we believe management should be held accountable for not addressing satisfactorily. The lack of rigor, stability, experience, staffing resources, good status measurement, recognition of downstream schedule impacts, timely problem identification and response produced a management organization that did not meet the needs of the project suitably, and produced a materially more reactive approach than one should have expected. It is not the case that management failed to recognize risks or to take actions to address them, but overall, we did not find its actions sufficiently well considered or executed. The consequences of those risks manifested themselves in a schedule that could and should have been shortened by a period that we determined to be in the range of 12 months. The direct cost consequences of extending the schedule by 12 months lies in direct charges to the project by resources provided by Cayenta, AAC, and Emera Maine to provide project management and oversight. While delay had an impact on the efficiency of some of the direct work being managed, its magnitude is difficult to calculate with reasonable precision, and in any event was August 8, 2016 Page I-5 The Liberty Consulting Group Public Utilities Commission State of Maine Introduction Audit of Emera Maine Docket 2015-00360 Final Report-Public Version mitigated by cost concessions made by Cayenta and AAC, and also by the fact that earlier attention to owner staffing needs likely would have had an upward influence on costs. Absent a supportable means of netting these countervailing influences, we consider it proper to treat them as mutually canceling. It was, however, possible to measure directly the costs of the management and oversight resources charging the project. Those resources were required for so long as the project ran, and solely as a function of the need for work to continue. Their costs (for Cayenta, AAC, and Emera Maine resources combined) amounted to about $2 million of the 12 months involved. This calculation does not address the current calculation of AFUDC amounts, which the schedule delay influenced in two ways: (a) those amounts include the $2 million that unjustified schedule delay produced, and (b) expenditures even after eliminating that $2 million would have stopped accruing AFUDC 12 months earlier. Management began the project under a scope broad enough to support the customer service activities and functions that such systems typically address. A desire to mitigate go-live delay, however, caused many, significant exclusions from that scope. Work continued on them following go-live. More appears to be needed in the future, but budgets were not completed for these future activities as of the end of our fieldwork. We found the post-go-live work completed so far appropriate. While it could have been performed earlier, it still would have incurred costs. However, performing it before go-live would not have required project management costs like those we found attributable to management for work leading to go-live. Moreover, for work remaining to be planned, budgeted, and executed, we have no current basis for assessing the reasonableness of its costs. D. Liberty’s Team We conducted this work with a team highly experienced in energy utility customer service and transmission and distribution management and operations. Moreover, as a firm, Liberty has an unparalleled level of experience in examining the aspects that underlie these areas (among many others) of energy utilities. Mark Lautenschlager, a registered professional engineer, led review of T&D operations and reliability. He holds a B.S.E.E. degree. He is a past president of the International Electrical Testing Association, and is active in developing ANSI electrical equipment maintenance specifications. A nationally recognized expert in electricity transmission and distribution equipment and systems, his particular areas of expertise include electrical maintenance and reliability, and identifying the root causes of T&D equipment failures. He has conducted over 80 forensic investigations of electrical-caused damage, injuries, and fatalities. He is a registered professional engineer in Florida and Indiana and has served as president of the International Electrical Testing Association (NETA). He has contributed to numerous ANSI/NETA electrical equipment acceptance and maintenance testing specifications, authored numerous technical articles, and prepared and conducted several international seminars on electrical equipment maintenance and failure analysis. He has trained hundreds of electrical testing technicians in electrical theory, operations, maintenance, testing, and safety for various electrical testing companies. August 8, 2016 Page I-6 The Liberty Consulting Group Public Utilities Commission State of Maine Introduction Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Mr. Lautenschlager’s fifteen years of conducting T&D evaluations for Liberty include examinations of line and substation operations, maintenance, and reliability evaluations at a wide variety of electric utilities, including:  Alabama Power  Ameren Utilities (three different Ameren-Illinois electric operating utilities  Commonwealth Edison (the Chicago electric utility and an operating company of Exelon)  Newfoundland Hydro  Newfoundland Power (a Fortis operating utility subsidiary)  Northwestern Energy  Nova Scotia Power  PEPCO in the District of Columbia  Georgia Power  Virginia SCC  Cap Rock Energy. Prior to consulting, Mr. Lautenschlager also served as Senior Vice President for High Voltage Maintenance Corporation for 20 years, with responsibility for corporate-wide operations and engineering, and safety and environmental compliance. He also served an AEP operating electric company as a substation maintenance and relay engineer and later was responsible for designing, constructing, and commissioning 400kV substations off-shore for Harza Engineering. He then formed a company that specialized in training electrical maintenance technicians and engineers, developing RCM-based substation maintenance programs, and performing forensic investigations of electrical equipment failures. Christine Kozlosky is also a national recognized expert in her field - - customer service. Her extensive work experience includes many broad reviews of customer service management and operations and work in developing and implementing modern customer information systems. Her work with Liberty spans 19 years and reviews of customer service at a wide variety of utilities. She has extensive, recent customer-service experience in New England, working for Liberty. She led a section of Liberty’s review of the customer service and communications aspects of storm response on work for the Connecticut utility regulatory authority (the PURA). She led the review of customer service in our soon-to-be completed, focused management audit of Liberty Utilities for the New Hampshire Public Service Commission. She has led comprehensive Liberty reviews of customer service at Pepco, Newfoundland Power, Newfoundland Hydro, Peoples Gas of Chicago, KU/LG&E, Interstate Power & Light (an Alliant subsidiary operating in Iowa), and Elizabethtown Gas (an AGLR subsidiary operating in New Jersey). Ms. Kozlosky has been providing customer service performance benchmarking and performance improvement consulting since the early 1990s. She has led best-practice surveys addressing customer services for multi-company groups, she has published newsletters addressing utility customer-service practices, and she is a recognized national expert in this field. She also has extensive experience in competitive, functional, and process-based benchmarking, both intercompany and multi-company performance comparisons. Ms. Kozlosky has a B.S. in Information & Computer Science from Georgia Institute of Technology. August 8, 2016 Page I-7 The Liberty Consulting Group Public Utilities Commission State of Maine Introduction Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Rose Minton led Liberty’s review of implementation of the new CIS. A nationally recognized utility/local government customer service and technology expert, she has worked with over 30 customer systems software and professional services engagements. Her work has included business case development, vendor evaluation and selection, assessments during implementation, and post implementation assessments or audits. She has provided Project Quality Assurance/Independent Verification and Validation (IV&V) for 19 software and services implementation projects, providing ongoing assessments to provide management with an independent perspective on project activities and early detection of variances. She has led over 25 business case engagements for CIS, CRM, Enterprise Resource Planning (ERP) and Assets Management, including assessment of current states and analysis of solution option assumptions, benefits, costs, feasibility, and risks. Ms. Minton has led more than 25 evaluation and selection engagements for CIS, CRM, ERP and Asset Management software solutions and professional services for implementation. The engagements included defining project objectives and expectations assessments, requirements definition, and development of the request for proposal. She holds an M.B.A. with emphasis in Human Resource Management and B.A. in Social Services from the University of New Mexico and a degree in Public Utilities Management from the University of Colorado. John Antonuk managed this engagement. A founder of Liberty and its president for many years, he has been consulting in the electric and gas utility industry for more than 30 years, and has served two-thirds of the country’s utility regulators and many energy utilities as well. He has managed more than 40 management and operations audits for utility regulators, which have addressed a wide variety of governance, executive management, and key technical, operations, and support areas. He has a bachelor’s degree from Dickinson College and a juris doctor degree from the Dickinson School of Law (both with honors). He has spoken on a variety of utility issues before a number of panels sponsored by NARUC’s committees and regional associations, state bar associations, and as an invited panelist before the U.S. FERC commissioners on utility financial matters. August 8, 2016 Page I-8 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Chapter Two Table of Contents II. T&D System Operations and Maintenance ...........................II-Error! Bookmark not defined. A. Introduction ....................................................................II-Error! Bookmark not defined. B. Field Observations .........................................................II-Error! Bookmark not defined. C. Findings - T&D Systems Operations and Dispatch .......II-Error! Bookmark not defined. D. Conclusions - T&D Systems Operations and Dispatch .II-Error! Bookmark not defined. E. Recommendations - T&D Systems Operations and DispatchII-Error! Bookmark not defined. F. Findings - T&D System Maintenance ...........................II-Error! Bookmark not defined. G. Conclusions - T&D Systems Maintenance ....................II-Error! Bookmark not defined. H. Recommendations – T&D Systems Maintenance .........II-Error! Bookmark not defined. I. Findings - T&D Reliability ............................................II-Error! Bookmark not defined. I. Conclusions - T&D Reliability ......................................II-Error! Bookmark not defined. J. Recommendations – T&D Reliability ...........................II-Error! Bookmark not defined. K. Findings - Budgeting......................................................II-Error! Bookmark not defined. L. Conclusions –Budgeting ................................................II-Error! Bookmark not defined. M. Recommendations -Budgeting .......................................II-Error! Bookmark not defined. N. Findings – Managing Field Work ..................................II-Error! Bookmark not defined. O. Conclusions – Managing Field Work ............................II-Error! Bookmark not defined. P. Recommendations – Managing Field Work ..................II-Error! Bookmark not defined. August 8, 2016 Page II-i The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version II. T&D System Operations and Maintenance A. Introduction Liberty examined how Emera Maine (The Company) operates, maintains, and applies resources to its T&D systems, how it plans, budgets, prioritizes, and implements capital projects, in particular its reliability improvement projects and whether the Company’s practices are reasonable and prudent. Our work included visual examinations of line and substation equipment and vegetation conditions, and recent projects, including the new Operations Center, the Eastern Maine Medical Center Substation, and the integration of the GIS, PowerOn, and AVL (automatic vehicle location) of the North Operating Regions with the South Operating Region. Emera Maine’s transmission system comprises overhead and underground high-voltage lines, substations, and other electrical equipment that delivers electricity from generating stations to the sub-transmission and distribution systems. The Company’s 115,000-volt, 138,000-volt and 345,000-volt transmission systems deliver electricity to its sub-transmission substations and provide connections to other utilities. The Company’s 34,500-volt, 44,000-volt, 46,000-volt and 69,000-volt sub-transmission systems delivery electricity from the transmission system, via substations, to the distribution systems. The Company’s 4,160-volt and 12,470-volt distribution systems deliver electricity to customers. Management reports sub-transmission along with transmission. The nature of Emera Maine’s service territory has produced a comparatively large number of radial T&D circuits. Radial circuits have only one source, distinguishing them from looped circuits, which have two or more sources. These multiple sources can provide continued service even with one circuit faulted or taken out of service for maintenance. Customers served by radial circuits have greater exposure to outages caused by electrical faults and for maintenance. Outages of radial sub-transmission circuits may have substantial effects on customers because they affect multiple distribution circuits. Utilities usually mitigate outages of radial subtransmission and distribution circuits by tying distribution circuits together in more urban areas where circuits are closer together. Particularly with lower customer densities, management must weigh the high cost of constructing and maintaining looped circuits against the improved reliability that results. Emera Maine’s substations contain large transformers, circuit breakers, and other electrical equipment. The basic function of substations is to change the voltages in the electric delivery system and to connect generating stations, the transmission system, the sub-transmission, and the distribution system. Circuit breakers operate as switching devices that immediately open or trip from protective relays to disconnect the system from an electrical fault. System Operators can generally also remotely control circuit breakers for switching purposes. Automatic Reclosers (reclosers) function as circuit breakers but do not always provide the same degree of capacity and protection. Reclosers in distribution substations protect distribution circuits. Used on circuits, they provide automatic isolation of faulted sections of a circuit without affecting upstream sections, thus reducing customer exposure to faults. August 8, 2016 Page II-1 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Emera Inc. acquired Bangor Hydro Electric Company in 2001 and Maine Public Service Company in 2010. Emera Maine operates the two areas as the Bangor Hydro District (BHD), or Southern Operating Region (SOR) and the Maine Public Service District (MPD), or Northern Operating Region (NOR). Each of the two districts operates under different control authorities. Management nevertheless has fully integrated System Operations and Dispatch and bargaining agreements of the two regions, each of which now employs the same maintenance and vegetation management programs. The Emera Maine serving regions have a number of distinguishing characteristics. It is always difficult to judge reliability results among utilities directly. Emera Maine presents particular challenges in this regard. They include low customer densities, the almost complete absence of underground facilities (0.1 percent), the large size and dispersion of its primarily rural service areas, its large percentage of radial circuits, and its high exposure (60-70 percent) of its subtransmission and distribution lines to trees adjacent to roadsides. Such factors both increase exposures to outages, and complicate efforts to respond to them. The next table compares Emera Maine and its neighbor, Central Maine Power. The latter has almost four times the customer numbers of Emera Maine, but is only larger in service territory by about 20 percent. Central Maine Power’s customer density (customers per square mile of territory) exceeds that of Emera Maine by more than three times. Emera Maine line crews generally must travel longer distances to respond to outages. Emera Maine and Central Maine Power Characteristics Characteristic Emera CMP Customers (Dec 2015) 158,000 615,000 Service Territory (sq. miles) 8,902 11,000 Distribution line miles 6,068 23,249 Customers per square mile 18 56 Customers per line mile 26 26 Emera Maine’s load growth, overall, has been nearly zero since 2011; the North Operating Region load, based on billings, has increased only about three percent while the South Operating Region load decreased by about one percent. B. Field Observations Liberty conducted on-site examinations of randomly selected transmission, sub-transmission and distribution lines; and substations. The next table summarizes them. We performed this review to look for cases of deteriorated equipment and poles, cross arms, insulators, loose tie wires, multiple-spliced conductors, and tree limbs very near to lines. Based on these brief inspections, the condition of the Company’s electrical facilities appears to be average, in general. We observed clear evidence of efforts to replace deteriorated equipment and to rebuild line sections. August 8, 2016 Page II-2 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Liberty On-Site Circuit Examinations** Date Tuesday, June 28, 2016 Transmission Line 1 (46 kV) Line 5 (46 kV) Line 7 (46 kV) Line 8 (46 kV) Line 9 (46 kV) Line 64 (115 kV) Line 246 (115 kV) Line 248 (115 kV) Line 249 (115 kV) Line 390 (345 kV) Distribution Costigan Local 1 (CC1) Enfield Local 2 (EN2) Graham Station Local 1 (GS1) Green Point Local 2 (GP2) Lucerne Local 1 (LU1) Lucerne Local 2 (LU2) Milford Local 5 (MF5) Milford Local 6 (MF6) Tibbetts Street Local 2 (TS2) Friday, July 01, 2016 Olamon (Manual Switching) Bangor International Airport (46 ‐ 12.5 kV) Graham Station 115 kV (Switch Yard) Graham Station 115 kV (Transformer Yard) Eastern Avenue (46 ‐ 12.5 kV) Wednesday, June 29, 2016 Thursday, June 30, 2016 Substation Line 1 (46 kV) Line 22 (34.5 kV) Line 28 (34.5 kV) Line 32 (34.5 kV) Line 34 (34.5 kV) Line 48 (34.5 kV) Line 60 (115 kV) Line 68 (115 kV) Burns Corner Local 1 (BC1) Burns Corner Local 2 (BC2) Burns Corner Local 3 (BC3) Green Point Local 2 (GP2) Hancock Local 3 (HC3) Line 22 Step Down Local 5 (22BH5) Line 22 Step Down Local 6 (22BH6) Lucerne Local 1 (LU1) Lucerne Local 2 (LU2) Mill Street Local 3 (ML3) Nicolin Local 1 (NI1) Bar Harbor (34.5 ‐ 4.16 kV) *** Acadia (34.5 ‐ 12.5 kV) Burns Corner (34.5 ‐ 12.5 kV) Waterworks (46.5kV -4kV) Furure Saxi Park Civil Works Line 4407 (44 kV) Circuit 12‐13 Circuit 12‐14 Island Falls (44 ‐ 12.5 kV) **Note: Time constraints allowed Liberty to inspect only one line (4407) and one substation (Island Falls) in the MPD. All of the remaining lines and substations are in the BHD. ***Acadia Substation is currently under construction and when completed, will replace the old Bar Harbor Substation. Liberty also examined the civil works ongoing at the Saxi Park Substation site, which will replace the Waterworks Substation. Liberty observed only a few locations where cross arms were decaying, but had not yet failed. These cross arms should to be replaced within a few years. We also observed some decayed poles in circuit sections due to be rebuilt. Some of the overhead conductors contained several splices in the same span, indicating that the condition of the wire should be reviewed and considered for eventual replacement. The distribution lines were protected by lightning arresters at the pole-mounted transformers, but on some lines these transformers were so far apart that more arresters may need to be installed between transformers to provide optimum lightning protection on some circuits. Liberty observed several radial sub-transmission line sections located on off road right of ways accessible only at road crossings. Some of these right of ways contained very large rocks; some were in swampy areas. It was difficult to evaluate the condition of these line segments, but some did not appear to be in very good condition. Repair and maintenance on these lines is difficult and time consuming, because trucks cannot traverse these right of ways; requiring the need for special equipment. Considerations applicable in identifying reliability projects include plans for relocating deteriorated off-road lines to roadside routes, or for constructing lines to form loop configurations. Either of these project types would serve to reduce CAIDI (restoration time) August 8, 2016 Page II-3 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version caused by outages of these difficult-to-access lines. For example, Liberty observed a section of 46kV Line 8 located in a narrow, difficult to access, right-of-way that violates the Company’s transmission planning criteria. Management has scheduled a rebuild of this section along a nearby road in 2016, it has scheduled the rebuild of 46kV Lines 1 and 80 in 2017, and it is currently replacing woodpecker-damaged 46kV Line 4407. Most of the Company’s lines run along roadways, providing easy access, causing exposure to trees and automobile accidents. Most of the roadside lines run within a few feet of forests, creating exposure to countless tightly packed trees just adjacent to the trim zone. The Company has installed insulated tree resistant bundled overhead cables (called Hendrix cable) in selected locations. Hendrix cable may not protect a line from a very large fallen tree, but it can prevent outages from smaller trees, large broken limbs, and tree limb contact. Management has been replacing deteriorated poles. Liberty observed many newer poles on the roadside lines that we observed directly. Along some secondary roads without berms the poles stand very close to the road. Car accidents cause the second or third most customer interruptions every year, excluding weather. Pole replacements generally require lengthy outages, especially for poles carrying two or more circuits. The Company should consider how it might protect high exposure poles, especially multiple-circuit poles in locations were accidents have occurred and at road intersections. The Company’s tree trimming programs appear to be effective. Only one of the line sections of those Liberty inspected had a few new limb growths near or in the lines. Liberty confirmed this line was scheduled for trim, and observed a tree trimming crew working only a few miles down the line. The Company’s substation maintenance practices appear to be effective, based on inspections of several Liberty-selected substations. The substations were free of vegetation, miscellaneous spare equipment, and trash. Only a few minor deficiencies were observed, all of which were aesthetic, except that some of the gate grounds were disconnected (NESC safety issue) and the space beneath the gates and fences was excessive (allowing animal intrusion). The Company agreed to address these issues. C. Findings - T&D Systems Operations and Dispatch A utility’s systems operations and dispatch organization should have experienced personnel using a facility equipped with the appropriate equipment to perform job effectively. Liberty examined Emera Maine’s transmission and distribution systems operations and service crew dispatching practices, its staffing of system operators, dispatchers, and service crews, its use of SCADA to monitor its systems, its use of OMS to address outages, and how it responds to severe storm events. Liberty reviewed Emera Maine’s CAIDI (restoration time) history because CAIDI is, in part, a measure of the effectiveness of the system operations and dispatching. Upon the acquisition of Maine Public Service Company in 2010, Emera Maine conducted operations for the region from the existing System Control Center at Presque Isle. Bangor Hydro conducted District operations at the legacy System Control Center in Bangor. Management found this arrangement sub-optimum, with the two centers operating independently from each other. In 2015, with the intent to improve operating efficiencies during normal conditions and severe storm August 8, 2016 Page II-4 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version events, management '''''''''''''''''''''' ''''''' '''''''' '''''''''''''''' ''''''''''''''''''''''' '''''''''''''''' ''''''''''''''''''''' ''''''''' '''''' ''''''''''' ''''''''''''''''''''''''' ''''''''''''''''' '''''''''''''''''' ''''''''''''''''''''''''''''' '''''''''''''''' ''''''''''''''''''''''' '''''''' ''''''''''''''' '''''''''''''''''''' '''''''''' ' Management retained the old facility in Bangor to provide a backup, in case the new operations center should become unusable. The back up control center has SCADA, OMS and desk top stations and monitors. A utility should have modern tools for monitoring and controlling its electric systems. '''''''' '''''''''''''''''''''' ''''''''''''''''''''' ''''' '''''''''''''''''' '''''''' '''''''''''''''''''''''' '''''''''' ''''''''' '''''''' '''''''''''''''''''' ''''''' ''''' ''''''''''''''''''''''' '''''''' ''''''''''''''''''' '''''''''''''''''''' '''''''''''''''''''' ''''''' ''''''''''''''''''''' '''''''''''''''''''''''''' ''''''''' ''''''''''''''''' '''''''''''''''' '''''''' '''''''''''''' ''''''''''''''''''''''''''' '''''''''''''''' ''''''' ''''''''''''''''''' '''''''' '''''''''''''''''''' ''''''''''''''''' '''''''''''''''''' ''''''' ''''''''''''' '''''''''''''''' ''''''''' ''''''''''''''''''''''' ''''''''''''''''' ''''''' ''''''''''''''''''''' ''''' ''''''''''' '''''''''''' '''''''''''''''' The Company also uses its new Hampden Operations Center (HOC) to streamline the inventory and issuance of material stock, fleet maintenance, and truck dispatch, via modern garage design. The upgrades made included changing out the radio transmitting units in the North Operating Region substations to allow the consolidation of the SCADA and OMS systems in the control center, and to provide, in both the North and South Operating Regions the ability to determine crew vehicle positions, via GPS, using a Vehicle Locating System. Management is currently implementing DasMap software, which will provide System Operations with more visibility to more devices on its T&D systems, thus allowing more effective response to system issues. '''''''''''''''''' '''''''''''''''''''''' ''''''' '''''''''' '''''''''''' '''''''' ''''''''''''''''''' ''''''''''''''''''''''''' '''''''''''''''' '''''''''''' '''''''''''''''''''' '''''''''''''''''' '''''''''''''''''''''' ''''''''''''''''' '''''''''''''''''' ''''''''''' ''''''''''''''' ''''''''''''''''''' '''''''''''' ''''''' ''''''''''' ''''''''' '''''''' ''''''' '''''''''''''''' ''''''''' '' '''''''''''''''''''''''''''''''' ''''''''''''''''''''''''' ''''''''''''''' '''''''''' '''''''''''''''''''''''''' ''''''''''''' ''''''''''''''''''''' '' '''''''''''''''''''''''''''''''''''' '''''''''' ''''' ''''''' ''''''''''''''''' ''''''''''''''''''''''' '''''''''''''''''' ''''''''''''' '''' '''''''''''''' '''''''' '''''''''''''''''''''''' '''''''''''''''''''' '''''''''''''''''''''''''' ''''''''''' '''''''' ''''''''''''''' ''''' ''''''''''' '''''''''''''''' ''''''' ''''''''''''''''''' '''''''''''''' ''''' ''''''' '''''''''''''' '''''''' ''''''' '''''''''''' ''''''''''''''''''''''''''''' ''''''''' '''''''''''''''''''''''''''' ''''''''''''''''''''' '''''''''''''''''' ''''''''''''''' '''''''''''''''''''''''''' ''''''''''' '''''''''''''''' ''''''''''''''''''''' ''''''''''''''' '''''''''''''''''' '''''''' '''''''''' '''''''''''''''''' ''''' ''' '''''''''''''''''' ''''''''''''' ''''''''''' ''''''' '''''''''''''' '''''''''''''''''''''''''' ''''''''''''' System operators use SCADA to track real time system status, including abnormal system configurations. System operators enter abnormal configurations in the systems operations log, and communicate the condition to the engineering department and the district supervisors using work requests, as needed to correct the condition. System Operations can request Power System Technicians (PSTs) to record loads at small distribution substations lacking SCADA. The PSTs also record loads for T&D engineering at all substations, as part of their periodic substation inspections. All system operators have access to system operating guide books indicating circuit and substation transformer summer and winter ratings. The SCADA system also includes this data to provide indications when loads approach equipment ratings. A utility’s system operators should have access to system engineers for assistance in preventing system overloads and other conditions that threaten system operations. The Company’s T&D Engineering Department assists System Operations by performing load studies for determining operational issues when planning field work, or addressing emergent equipment outages. The Engineering Department consists of a Chief Engineer, eight engineers in BHD, and three engineers in MPD. Transmission energy management studies and other studies required for predicting and managing those transmission lines that affect the regional network fall under:  ISO New England – Maine Local Control Center at Central Maine Power for the BHD  The Canadian SO system in New Brunswick for the MPD. August 8, 2016 Page II-5 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version A utility’s system operations staff should have substantial experience and sufficient numbers of system operators and dispatchers. Emera Maine’s T&D Operations and Dispatch Center currently has a staff of fourteen system operators, one supervisor, an operations technician, four distribution dispatchers, and one manager. The dispatchers dispatch service crews to address outages and customer service work during normal business hours. At least one system operator always remains on duty after hours, and has responsibility for distribution dispatching outside of normal business hours. Management requires that new operators have either a two-year degree in electrical power, or the equivalent in work experience. Once hired, each system operator receives on-the–job training, and may be promoted through various rating levels, from entry level to fully NERC rated, as they complete levels of documented training and experience. Currently, all but one system operator has top level ratings. The Company trains its system operators, based on formal guide books, to be prepared for safe and effective restorations for storm events. A utility should have a computerized outage management system that provides sufficient information about outages to minimize outage respond times. The Company has been using its current electronic outage management system (OMS) in the BHD since 1998. Prior to 1998, dispatch used pencil and paper. Prior to integration of the regions in 2015, MPD outage dispatch used a service-order-based process to address outages. The Company indicated that its OMS system is tentatively scheduled for an upgrade in 2017. A utility should have a geographic information system (GIS) that electronically stores all electric system equipment data and locations. The Company uses a GIS and vehicle locating system (called AVAIL) to track its equipment and line crew locations. Since about 2000, Emera Maine has been using GIS to provide dispatchers, line crews, T&D engineers, and field work planners with convenient access to pole and equipment data. The Company has used the AVAIL GPS system since 2008 to provide dispatchers with the ability to locate field crew positions; this is useful for determining which crew to dispatch to respond to an outage or to other customer issues. As a result of the 2015 integration of the System Operations, management now uses these tools in both the BHD and the MPD. Information about an outage should arrive smoothly all the way from the customer call to the responding service crew. When a customer outage occurs, customers call customer service, either by speaking with a representative or by interacting with the Company’s automated interactive voice response (IVR) system. The representative, or the IVR system, creates an outage ticket, which gets manually entered into the OMS system by the dispatcher (or system operators during after-hours). OMS contains the locations of all electric system protective devices, with the connectivity of these devices to customers (these data are stored in the GIS system), thus providing predictions of which device cleared a fault, and what customers are affected. In response to the OMS notification, dispatchers call service crews working in the area of the outage, either by radio or cell phone, and verbally provide the location of the outage. Dispatchers can upload GIS location data into the GPS units in the service crew trucks, if necessary. To streamline this process, management has implemented a pilot program that provides tablet computers to service crews with an application called Atlas, which contains the electric system data and mapping. Some crews should have the tablet computers in 2016, and the remainder of the crews by 2017. August 8, 2016 Page II-6 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version A utility should have service crews appropriate in numbers and in locations to minimize response times. Management has stationed 25 two-person service crews in the South Operating Region and seven two-person crews in the North Operating Region for the conduct of planned customer service work and for response to emergent outages during regular work hours. During afterhours, (365 days per year) the Company assigns two one-person service crews with bucket trucks to remain on-call to respond to emergent outages for each of the four BHD field offices. Management also assigns a one-person crew to remain on-call in each of the three MPD field offices. All on-call service crew line workers live within 25 air miles of their field offices. Smart meters can reduce restoration accuracy and times, especially following severe storms. The Company uses “smart meters” in both regions to reduce meter reading costs by gathering and transmitting energy usage data. However, only the smart meters in the BHD have two-way communication that allows the system operators and dispatchers to “ping” meters to determine whether the meter is energized or not. This capability saves time, especially during severe storm events, to verify power outages and to verify power restoration status. Since 2005, the Company has installed two-way Smart Meters on nearly 97 percent of BHD customer locations. It uses the meters to help confirm outages and restorations. The Company is planning to replace the old one-way smart meters with two-way smart meters in MPD during the next five years. A utility should have a process for identifying the causes of outages, to permit effective actions to reduce future outages from similar causes. Accurately identifying the causes of outages proves critical in developing strategies for mitigating outages and improving SAIFI. Line workers addressing outages report the cause, or probable cause, of each outage, via radio or mobile phone, to dispatchers. No electronic communications exist between Dispatch and line crews. Dispatchers enter the information into the corresponding outage ticket record in the Company’s OMS. At the end of each month, a dispatcher reviews all regional outage records for accuracy, and makes necessary adjustments to affected customer counts and “on” and “off” times. Dispatchers review outage cause codes to verify accuracy, based upon any comment located in the “comment” field of the record. Engineering personnel use the reported outage-cause data to determine the impact of specific equipment failures, non-equipment failures, tree contact, automobile contact, and weather conditions. At the end of each month, a system operator also reviews the dataset to ensure that all transmission line and substation outages get recorded in outage history and that outage times and customer impacts are accurate. Following this scrutiny, an engineer reviews the dataset again and recommends changes, if any, that need to be made to an outage record. The Company’s cause-code categories include 15 major categories, many sub-categories, and many equipment-caused codes. Thunderstorms, snow and ice storms, windstorm, and flood comprise sub-categories under “weather conditions.” Although lightning might be included in “thunderstorms,” the Company does not have a “suspected lightning” cause code. A utility should use its CAIDI value (restoration time) to evaluate the effectiveness of system operations methods and practices. The effectiveness of T&D System Operations and Dispatch, and the service crews that respond to outage reports, affect what is measured as the CAIDI, or the Customer Average Interruption Duration Index. CAIDI quantifies the average time to August 8, 2016 Page II-7 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version identity and travel to an outage, and to restore service. To determine how Emera Maine’s CAIDI compared with other utilities, Emera Maine participated with 102 other utilities in the 2014 Edison Electric Institute (EEI) Reliability Survey. '''''''' ''''''' ''''''''''' '''''''''''' '''''''''''''''' '''''''''''''' ''''''''' ''''''''' ''''''' '''''''' ''''''''''''''' '''''''''''''''''''' ''''''''''''''''' ''''''''''''''' '''''''''''''''''''''' ''''' ''''''' '''''''''''''''''''''' ''''''''''''''''''''''''''''''''' '''''''''' '''''''''''''''''''''''''''' '''''''''''''''''''' '''''''''''''' '''''''''''''' ''''''''''' '''''''''''''' '''''' ''''''''''' '''''''''' ''''''' ''''''''''''''''' '''''''''''''''' '''''''''''''''''''' '''''''''''''' '''''''''' '''''''''''' '''''''''''' '''''''''' ''''''''''''''''''''' '''''''' ''''''''''' '''''''''''' ''''''''''''''' ''''''''''''''''' '''' '''''''''''''' ''''''''' '''''''''''''''' ''''''''''''''''''''''' ''''' ''''''' ''''''''''' '''''''''' ''''' '''''''''''''''' ''''''' '''''''''''''' ''''''''''''''' '''''''''''''''''''' ''''''''' '''''''' ''''''''''''''' ''''' ''''''' '''''''''''''' ''''''''''''''' The next table shows that Emera Maine’s CAIDI improved in 2015, but still worse than its corresponding value for 2012. The use of 2015 data, for which Emera Maine had a value of 1.99 would have produced better comparative results. Emera Maine CAIDI Values Year CAIDI 2011 1.88 2012 1.85 2013 2.15 2014 2.16 2015 1.99 Emera Maine also uses the older exclusion method (excluding 10 percent of customer impact for any 24-hour period) for its internal CAIDI calculations, applicable before the IEEE 2.5 Beta method. The next table shows CAIDI values measured this way. Emera Maine CAIDI Values (old method) Year CAIDI 2011 1.53 2012 1.72 2013 2.04 2014 2.22 2015 2.09 Emera Maine’s CAIDI goal, based on its 10% exclusion method, for 2016 is 1.92 hours, the average of the previous five years CAIDIs. Management should be able to achieve this CAIDI value in 2016 as a result of the efficiencies provided by the integration of the system operations for the two regions. Planned outages for line maintenance, and construction can negatively affect CAIDI. To minimize the effect of planned outages on customers, management uses a review process that evaluates outages to ensure maximum effectiveness. Specifically, the following people review proposed outages: Manager of Line Operations, Key Relationship Specialist, Transmission Planning Engineer, and Customer Experience Program Manager. Management evaluates the customer service and reliability effects of the proposed planned outage, and considers alternative ways to perform the work. Alternative ways include mobile substation hookup to provide temporary power, performing the repair energized, or moving the repair to a different date. The outage planning process appears to be working for Emera Maine. Its average CAIDI for the years August 8, 2016 Page II-8 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version 2011 through 2015 was only 1.66 hours for planned outages, which caused its overall CAIDI indices to improve. A comprehensive SCADA (Supervisory Control and Data Acquisition) system supports effective system operations. Management’s integration of its MPD SCADA system with its BHD SCADA system allows it to monitor and control both T&D systems at its new System Operations Control Center. SCADA affects CAIDI by providing real-time information, along with OMS, about circuit outages. Management uses the SCADA system to monitor and control all transmission lines and substations, and nearly all sub-transmission circuits. It employs SCADA monitoring at 109 of the 178 distribution circuits in the BHD, and SCADA for 50 of the 64 distribution circuits in the MPD. Typical practice at smaller utilities does not include SCADA installation at small distribution substations serving one or two circuits. A utility should have comprehensive written plans to address actions preceding and following a severe storm event. Emera Maine faced seven severe storms in 2013 and 2014. Liberty reviewed how management prepares itself for a severe storm and follow up restorations. Management monitors weather forecasts, as a basis for determining when to prepare for outages that might occur. The Emera Maine System Emergency Manager, in consultation all other affected T&D and Customer Service Managers and Supervisors, monitors weather forecasts from the National Weather Service Office, located in Caribou Maine. Management starts its preparedness planning when it has a prediction of severe weather. Management began at the end of 2015 to forecast storm impacts on customers, in terms of interruptions and restoration times, conducting analyses of historical storm outage data based on storm type, time of year, wind speed, and wind direction, for example. In 2016, the Company’s Incident Command managers began using this impact data to improve preparedness plans for forecasted storms. The Company established an internal team to review possible automated modeling. Storm managers use the results to predict the number and location of customer outages for the purpose of calling system emergencies earlier in order to pre-stage damage assessors and crews. Where it has reliable information about where storms will have the greatest impact, management relocates internal and sometimes external crews from least-likely affected areas. During storm events, Central Dispatch with Field Operations Management coordinates restoration effects. Management adjusts System Operations and Central Dispatch staffing levels, based on forecast storm damage. The new Incident Command Center in the Operations Center and Central Dispatch centralize severe storm restoration procedure management. Lessons learned from past storm events produce a current restoration approach that includes, for safety and efficiency reasons, working a smaller number of line workers during storm events. Management stages the majority of crews until the weather has improved. Immediately after a severe storm, the Incident Command Manager dispatches company personnel, assigned to act as Emergency Services and Site (ESOS) personnel, to relieve first responders standing by downed lines. When safety is assured, they move on to assess system damage, or some other storm-related task. The Incident Command Manager assigns Dispatch personnel as Data Scrubbers, who use smart meter ping data (for the BHD only) and other information, such as damage assessments, and use the August 8, 2016 Page II-9 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version GIS to provide accurate outage location and size data. Line Supervisors use this scrubbed data to determine where to most effectively focus repair crews. Emera Maine has a “Systems Emergency Operations Plan (SEOP),” supplemented by a “Storm Preparedness Checklist.” Management indicated that, as a result of the SEOP, it calls System Emergencies earlier than in the past, enabling the Company to mobilize internal and external workforce resources to respond best to storms, limiting impacts on customers. However, the Systems Emergency Operations Plan does not include a written procedure reportedly used for severe storm preparations. The Company uses a separate document, “Storm Preparedness Checklist,” to help assure that appropriate resources are available for severe storm response. For training purposes, the System Operations and Dispatch Center periodically conducts severe storm emergency drills. During a snow storm in late 2015 it conducted a restoration process as if it were a severe storm to test its emergency restoration process. D. Conclusions - T&D Systems Operations and Dispatch 1. Integration of system operations has been effective and promises to provide benefits into the future. However, the OMS warrants improvement. (Recommendation #1) The integration of the Emera Maine system operations systems was appropriate and should help improve Emera Maine’s CAIDI in 2016 and beyond. Centralizing and standardizing the control of electric systems, outage data systems, and service crew dispatch are sound. Management stands to gain further efficiencies, however, by upgrading its outage management (OMS) system in order to make it fully automatic from the point of customer outage reporting to the service crews responding to customer outages. Currently, personnel are needed to enter outage tickets into the OMS system and service crews, although they have some electronic mapping data on board their trucks, must verbally receive and close outage service tickets, as well as written service orders for customer service work. Although management’s use of a paper service order method appears sufficient for communicating and tracking its customer service work, eventually the Company should evaluate the cost benefit of upgrading to a computerized work management system. 2. Outage cause reporting is reasonably accurate, but can be improved. (Recommendations #2 and 3) Accurate outage-cause data are very important for identifying and addressing the cause of outages. Since 2011, the third or fourth most common outage cause reported was “patrolled–no fault found.” To reduce the use of this non-informative category, T&D engineering should provide periodic training to service crews and dispatchers on how to best identify outage causes, and describe why accurate outage-cause identification is important for determining reliability improvements. In addition, management does not include “Probable Lightning” as a cause code (although a thunderstorm category exists). The service crew and the dispatcher should determine whether lightning was a probable outage cause. T&D Engineers could then determine, using a lightning strike location service, whether lightning actually served as probable cause. Management could use the data gathered, over time, to determine whether lightning protection and arrester grounding should be improved on specific T&D circuit sections. August 8, 2016 Page II-10 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version 3. The Severe Storm Preparedness Process is appropriate, but it can be improved. (Recommendation #4) Fully formalizing the Storm Preparedness practices and checklist, in writing, within its System Emergency Operations Plan (SEOP) would serve to eliminate the risk of confusion in preparing for severe storm events. E. Recommendations - T&D Systems Operations and Dispatch 1. Improve OMS outage reporting. (Conclusion #1) When management updates its OMS system, to improve tracking and control of outage restoration work, it should include software and hardware that automatically make the system fully electronic from the point of customer outage reporting to the service crews responding to customer outages. 2. Provide periodic outage cause training for service crews. (Conclusion #2) This training should focus on how best to identify outage causes, and to reduce the numbers of “no fault found” cause codes, to ensure that reliability engineers are receiving the most accurate cause code data. 3. Make “probable lightning” an outage cause code and verify outages so coded. (Conclusion #2) To ensure that lightning protection issues are addressed, the outage-cause codes should include a “probable lightning” cause code and engineers should use a lightning strike service to verify if lightning was the probable cause. 4. Formalize the Severe Storm Preparedness Process. (Conclusion #3) The Severe Storm Preparedness Process should be fully formalized as part of the System Emergency Operations Plan (SEOP) to better assure compliance. The procedures for addressing emergency incidents, including forecasting severe storms and estimating the expected level of storm-caused outages, are appropriate. Management, however, should formalize its process of Storm Preparedness as a chapter in the SEOP, including written descriptions of the severe weather forecasting and outage prediction process. This chapter should also include measures for determining predicted storm impact categories, based on the outage prediction process. Based on the storm impact category, a procedure should indicate, for each day for three to five days before the predicted impact day, what and when resources, including mutual aid, should be staged and what other preparations should be completed. The storm preparedness and restoration section should emphasize the necessity of having sufficient numbers of personnel, for public safety, to timely guard downed wires that could be energized. F. Findings - T&D System Maintenance Liberty examined the transmission, sub-transmission, and distribution line, and substation inspection and maintenance programs and the conformity of program inspection and August 8, 2016 Page II-11 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version maintenance activities and work schedules to program requirements. Effective T&D equipment maintenance programs and practices improve reliability by minimizing unexpected equipment failures. We also reviewed the inspection and maintenance work order and record keeping practices. Management has two strategies for mitigating equipment caused outages. One strategy employed periodically inspect T&D lines and substations for condition issues (discrepancies), immediately repair discrepancies posing an imminent threat to system operations, and then bundle nonimminent discrepancies into reliability projects to be repaired “en masse” on line sections in the future. The other strategy is to periodically service or rebuild substations and some line-mounted equipment via a formal maintenance program. Identifying the causes of outages provides useful information about those items that have significance when inspecting lines and what outage causes to target when planning and scheduling reliability projects. Since 2011, other than weather caused outages, equipment failures caused the most customer interruptions each year, followed in order by car pole accidents and trees falling on lines from outside the trim zone. Liberty reviewed the causes of equipment-caused outages since 2011 to determine whether these equipment failures indicate the need for changes in the inspection and maintenance practices. Insulator failures in substations and on transmission and sub-transmission lines caused a few major outages over the five years. By far the most customer interruptions resulted from failed distribution equipment. The largest causes of distribution outages consisted of broken conductors (wires), porcelain, fused cutout switches, and broken cross arms. Decay comprised a leading cause of transmission and distribution wood cross arm failure during the 2011 - 2015 period, eventually resulting in breakage. The cause of transmission and distribution conductor failures vary more, and include such factors as cold weather, excessive slack, burned taps, fatigue, loose connections and corrosion. Utility management should adopt and routinely employ structured, comprehensive inspection and maintenance programs. The T&D Planning and Asset Management department determines the content of inspection and maintenance programs. Maintenance on overhead lines consists of repairing discrepancies discovered by various inspections, and rebuilding circuits or circuit sections exhibiting numerous high-priority discrepancies. The T&D Planning and Asset Management group consists of an asset manager, a reliability engineer, a maintenance engineer (supported by a chief engineer), two T&D Engineers and nine Substation Engineers. The T&D Engineers support capital projects on the Transmission and Distribution system, address customer inquiries, and update standards as needed for T&D and substation assets. Substation engineers in the T&D Engineering group support substation assets, the underground system, T&D protection coordination, capital improvements and specifications for new equipment. T&D Construction Planners or inspection contractors conduct the transmission, sub-transmission line and pole inspections. In addition to submitting written reports (verbally if an imminent threat exists), the inspectors also take digital photographs of the discrepancies as applicable. Management conducts a number of different types of inspections on its transmission and sub-transmission systems. The basic inspections consist of periodic foot patrol and driving inspections. The next table describes additional inspection types. August 8, 2016 Page II-12 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Utility management should use a process should to ensure that all line discrepancies undergo prompt evaluation and appropriate corrective action. When a patrol, a drive-by inspector, or any employee determines that a discrepancy poses an imminent threat to the reliability of the power system, he or she calls in a service order to System Operations. System Operations personnel then notify Field Operations of the service order to support prompt completion of critical repairs. For all non-imminent discrepancies, the inspectors enter discrepancies into the GIS, which T&D Planning Engineers review and prioritize individually (high, medium, or low). Non-imminent discrepancies are bundled per line section and included for consideration when management develops reliability projects. The following flow chart illustrates how management addresses line discrepancies. Discrepancies identified from inspections Planners prioritize using GIS Threatening discrepancies to Engineers Customer Coordinators Line Supervisors and Crews Nonthreatening discrepancies to Engineers for evaluation for capital projects Management bases transmission and sub-transmission inspection programs on good utility practices, and as required by NERC for its bulk electric system. The patrols and inspections identify damaged or deteriorated transmission and sub-transmission equipment. The “thermal” inspections identify overheated connections and switches. The “ground-line” inspections examine pole and equipment condition, chemically treat poles to extend pole life, and sound and bore poles to identify those failing to meet NESC pole shell thickness (strength) criteria. Management intensified its inspection cycles for critical line crossings and its ground-line inspection on roadside poles in 2015, after a pilot study demonstrated the effectiveness of this practice. The next table summarizes the types and frequencies of transmission and sub-transmission system inspections. We found them consistent with good utility practice. Transmission and Sub-Transmission Line Inspection Cycles Emera Maine "Core" Transmission and Sub-Transmission Line Inspection Program Elements August 8, 2016 Page II-13 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Inspection Type ROW Foot Patrol Frequency Five-Year Cycle By In-house Drive-by Roadside Patrol Three-Year Cycle In-house Critical Crossing Inspections Three-Year Cycle At least One Annual Patrol In-house Every Five Years Contracted Thermal Roadside Inspection Annually Contracted Ground-Line ROW Inspection & Treatment Ten-Year Inspect Cycle/ Five- Year Cycle Retreat Contracted Five-Year Cycle Contracted Five-Year Cycle In-house One Annual Patrol during summer In-house Routine ROW Aerial Patrol Thermal ROW Inspection Pole Ground-Line Roadside Pole Inspection & Treatment Steel Lattice Tower Inspection Bulk Electric System Vegetation Encroachment Aerial Patrol – NERC Required Comment Inspect frequency changed from six to three years in 2016 In-house Prior to 2015 only 100+ kV inspected, expanded to all voltage classes in 2015 Added to Core Plan in 2015 Added to Core Plan in 2014 Added to Core Plan in 2016 The next table illustrates how management schedules and tracks repair work or service orders generated from the different types of inspections. Transmission and Sub-Transmission Scheduling and Tracking Inspection Program Visual Inspection (ROW, Drive-by, Critical Crossings, Steel Lattice Tower) Aerial Visual Patrols Ground Line Wood Pole Inspection &Treatment (ROW & Roadside) Prioritization Company inspectors enter into GIS problems found as facility maintenance objects (aka, wrenches). T&D Planning Engineers evaluate inspection results and request service orders and/or work orders based upon prioritization project list Line discrepancies recorded via Word document. Line Superintendents review report and repair items within their service districts at their discretion through Service Order System Poles with insufficient shell thickness (<66%) reported as either "priority" or "standard" reject by the external contractor based upon severity of decay/damage Scheduling Tracking Scheduling of service orders managed by individual line superintendents. Scheduling of work orders managed by the Company's Line Scheduling Team Service order tracking via Geographic Information System (GIS). Tracking of work orders done by the Line Schedule. Repair work scheduled using Company's service order system Tracking of service order status managed by GIS Scheduling of service orders managed by individual line superintendents. Scheduling of work orders managed by the Company's Line Scheduling Team Service order tracking via Geographic Information System (GIS). Tracking of work orders done by the Line Schedule. August 8, 2016 Page II-14 The Liberty Consulting Group Public Utilities Commission State of Maine Thermal Inspection (ROW & Roadside) Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Thermal "hot spots" discrepancies reported as "critical", "Serious" or "intermediate" based upon the level of heat difference from the external ambient air temperature Completion of service orders managed by individual line superintendents. For larger projects a work order may be created that is timing of which is done by the Line Schedule Service order tracking via Geographic Information System (GIS). Tracking of work orders done by the Line Schedule. Effective implementation of inspections requires conformance with program schedules. The two tables below show that management substantially completed sub-transmission and transmission ground-line, aerial, and thermal inspections. However, management failed to complete ROW Foot Patrol, Drive-by Roadside & Special Roadside, Critical Crossings and Lattice Tower visual inspections in 2014 and 2015. Management reported that it deferred these inspections because of the unavailability of the T&D Construction Planners who had been conducting them. Management cited heavier than expected service and capital construction planning work in 2014 and 2015 as the cause of personnel unavailability. In lieu of the omitted inspections, management depended on aerial and ground-line inspections, and on causal employee drive-by inspections to provide some level of sub-transmission and transmission system condition reviews. However, to catch up on the formal inspection tasks, management increased its planned annual transmission and sub-transmission inspections by 25 percent in each year from 2016 through 2019. Management now uses contractors to supplement in-house construction planners. BHD Transmission and Sub-Transmission Inspection Goals and Completion Visual inspections (ROW, Drive-by Roadside, Special Roadside, Critical Crossings, Lattice Tower (Miles) See Note 1 Aerial Patrol (Qty Patrols) ROW Ground Line Pole Inspection & Treat (Miles) % Completed Goal Completed 2015 % Completed Completed Goal 2014 % Completed Completed Completed Goal Goal 2013 % Completed 2012 % Completed Completed Inspection Attribute Goal 2011 113.9 113.9 100% 256.5 256.5 100% 170.7 170.7 100% 214.7 152.9 71% 276.0 27.2 10% 2 1 50% 2 47.3 43.8 93% 78.1 Roadside Ground Line Pole Inspection (Qty Poles) Roadside Thermal (IR) Inspection (Miles) 3 150% 2 77.8 100% 72.3 1 50% 72.3 100% See Note 3 1 2 1 100% 103 103 200% 100% 73.4 73 100% 982 922 94% 618 82% 150 100% See Note 2 One Patrol in 2012 See Note 6 ROW Thermal (IR) Inspection (Qty Patrols) 1 751 150 MPD Transmission and Sub-Transmission Inspection Goals and Completion Visual inspections (ROW, Drive-by Roadside, Special Roadside, Critical Crossings, Lattice Tower (Miles) See Note 1 Aerial Patrol (Qty Patrols) ROW Ground Line Pole Inspection & Treat (Miles) Roadside Ground Line Pole Inspection (Qty Poles) Roadside Thermal (IR) Inspection (Miles) ROW Thermal (IR) Inspection (Qty Patrols) 75 75 88.2 88.6 100% 75 See Note 4 100% 47.6 75 100% See Note 3 2 1 50% 1 47.6 100% 56.8 78.9 139% 67.8 See Note 5 See Note 2 See Note 6 90.6 0 % Completed Completed Goal 2015 % Completed Completed Goal 2014 % Completed Completed Goal 2013 % Completed Completed Goal 2012 % Completed Completed Inspection Attribute Goal 2011 0% 2 200% 1 1 100% 67.8 100% 96.8 97 100% 353 378 100% 50 50 100% Note 1: Pilot inspection of roadside transmission poles added to core inspection in 2014. Note 2: Roadside thermal (IR) inspection added to core inspection plan in 2015. August 8, 2016 Page II-15 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Note 3: Visual inspection of ) transmission assets during 2013 and 2014 accomplished by ground-line pole and aerial inspections. Note 4: Routine aerial patrols of MPD began in 2013. Note 5: Sound, bore, and treatment, of MPD roadside transmission poles part of its ROW program until 2015. In 2015 poles excavation and external treatment of ROW poles began and sound and boring inspection of roadside poles continued but tracked separate from ROW poles. Note 6: ROW asset thermal (IR) inspection added to Emera Maine’s integrated inspection plan in 2015, first integrated serial patrols planned for 2016. Testing and treating poles (ground line inspections) is necessary to comply with National Electrical Safety Code guidelines and to extend the useful life of poles appropriately. Transmission and sub-transmission pole ground-line inspections (not performed on distribution poles) not only identify pole and equipment discrepancies, but also sound (strike with a hammer) and bore poles (to identify voids from decay) 11 years old or more to determine poles strength (by measuring pole shell thickness) and to apply chemical treatments to prevent further decay and insect damage. The Company has 26,023 transmission and sub-transmission poles in the BHD and 7,441 in the MPD, comprising a total of 33,464 poles. About one-half of these poles, (16,732) should have been inspected since 2011. Since 2011, 32 poles of the estimated 16,732 poles have been identified as “priority” (less than NESC shell thickness requirement) and 37 poles have been identified as “standard,” (approaching minimum shell thickness). Therefore, of the about one-half of the poles inspected (only about 0.4 percent) failed to meet, or just barely to meet, NESC strength requirements. This low reject rate indicates that the transmission and sub-transmission pole plant overall is likely in better condition when compared with other utilities we have examined. We have observed at other utilities two to three percent rejection rates. Management replaced at least 37 of the bad poles identified by the transmission ground line program since 2011. As of the end of 2015, 37 poles await replacement under reliability projects. Some limits exist on the ability to rely upon the reported data. An unknown number of transmission and sub-transmission poles, and distribution poles, were also replaced because of car pole accidents or as a result of pole condition determinations made under the patrol inspections, and not as a result of the ground-line inspection program. Moreover, there is no record of the number of poles replaced in the MPD in 2011 through 2015. The main objectives of Emera Maine’s Overhead Distribution Circuit Inspection Program is to: identify, prioritize, and mitigate hazardous or potentially hazardous conditions that place employees or members of the public at risk, and any distribution facilities issue which, because of non-conformance with the National Electrical Safety Code, Company distribution construction standards or otherwise, that poses a safety or reliability concern. Management conducts roadside distribution circuit and pole inspections from a vehicle. Right-ofway, road and water crossing, and non-passable right of way inspections occur through a walking inspection, or by using snowmobiles or all-terrain vehicles. The inspections include distribution pole condition, pole-mounted components, and guy wires. Workers “sound” suspect poles using a hammer, in order to determine pole integrity (not as thorough as occurs under transmission ground-line inspections). Management does not chemically treat distribution poles. Established program cycles require distribution inspections on six year cycles, except for water and highway crossings, and distribution circuit segments serving 1,000 customers or more, which use threeyear cycles. August 8, 2016 Page II-16 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Utility management needs to provide for timely inspections of overhead distribution circuits, because distribution equipment-caused outages greatly contribute to SAIFI. As was true for transmission and sub-transmission inspections, management did not complete formal distribution visual circuit inspections in 2014 and 2015. Management similarly reported deferral of these inspections because of the unavailability of the T&D Construction Planners. Management relied here as well on casual inspections by company employees while traveling and working. Again, management set goals to complete an additional 25 percent of inspections each year from 2016 through 2019 and now uses contractors to supplement in-house line workers to complete inspections. The next table summarizes distribution line inspection completion rates. As of 2015, management had not conducted any formal inspections of the distribution system in the MPD. Management depended on informal inspections by field office and regional personnel to identify distribution condition discrepancies. Distribution Line Inspection Completion Rates Bangor Hydro District Maine Public District % Completed Completed Goal 2015 % Completed Completed Goal 2014 % Completed Completed Goal 2013 % Completed Completed Goal 2012 % Completed Completed Visual inspections (Cycle‐based, Special, & Critical Crossings) (Miles) Goal 2011 792 792 100% 751 751 100% 793 635 80% 746 223 30% 738 115 16% Formal Inspections Not Conducted 302 0 0% Utility substation equipment maintenance practices should take place according to plans and schedules that seek to minimize equipment failures and on tests resulting in observed conditions that trigger maintenance activities. Management bases substation and large equipment maintenance, testing and inspection program on a combination of equipment condition and timebased intervals. The T&D Planning and Asset Management group analyzes test data, following which adjustments to established time intervals occur as indicated by test results. The next table summarizes the basic maintenance cycles., Substation Maintenance Schedules Substation Equipment Transformers Transformer test results determine whether maintenance work is required, or if testing should be conducted more often. Circuit Breakers Maintenance and Tests Dissolved Gas in Oil Testing Electrical Testing on 3 MVA +– Power factor, TTR, exciting current Cycles Annual, Semi-annual for 345kV 46kV and greater - 3-year cycles Less than 46kV – 4-year cycles Others – 6-year cycles Minor inspections include servicing the mechanism, and if the breaker is suitable for service Air magnetic – 5-year cycles Vacuum – 6-year cycles Oil – 5 year cycles SF6 w/air mechanisms – 3-year cycles SF-6 w/spring mechanisms – 6 year August 8, 2016 Page II-17 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Reclosers Protection Relays Testing and recalibration Battery Banks Hot connections AMI equipment Spraying vegetation Impedance testing Infrared Scans Condition Inspection cycles Vacuum/oil > 34.5kV – 3 year cycles Vacuum/oil < 34.5kV – 6 year cycles Oil - 3 year cycles NERC required relay tests – 6 years Microprocessor relays – 9 years Electromechanical/solid state–7 yrs Electromechanical for XF/bus– 4 yrs All others are tested with breakers Annually Semi-annually Annually Annually Utility management should provide for the periodic inspection of substations, in order to identify discrepancies that warrant action for discrepancies. Power Systems Technicians (PSTs) inspect substations every two months, with monthly inspections applicable at the Graham substations and weekly inspections at the MEPCO and Chester SVC facilities. Substation inspections include checking battery voltages, equipment oil levels, oil and winding temperatures, load readings, nitrogen pressures, air pressures, counters, heaters, cooling system operation, load tap changer counters, oil leakage, and any other condition that is abnormal. Inspectors enter substations discrepancies (from inspections or test results) directly into software on their mobile computers. Issues that require immediate attention are immediately communicated by the inspector to one of five PST supervisors and the System Operator, depending on the situation. The PST supervisor determines a course of action. The T&D Planning and Asset Management, group administers substation inspection, maintenance, and testing programs and programs, conducts substation inspection and maintenance activities and schedules such substation work into the computerized maintenance management system (CMMS). This system automatically and timely generates program work orders for the PSTs, who conduct the substation inspection and maintenance work. The database contains all substation equipment and some line equipment. The system allows the Power System Operations Planner (PSOP) to forecast maintenance requirements for the upcoming year. The PSOP takes into consideration previous test results, known service advisories, and other conditions that may require placing the equipment in a higher priority category. Equipment not maintained in the year scheduled secures a higher priority for completion in the following year. Sub-transmission and distribution substation equipment maintenance is based on the last maintenance date. Plans and priorities for transmission substation equipment 115kV and higher are based on last maintenance dates, as adjusted for certain equipment types that must comply with NERC requirements. Substation inspectors finding non-emergency repair items generate a repair work order and a comment describing the issue and its severity. Critical, non-emergency issues undergo discussion the next day at regular supervisors’ morning meetings. These daily meetings address plans for August 8, 2016 Page II-18 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version these items, with formal scheduling occurring at weekly supervisor scheduling meetings. Noncritical, non-safety related work orders undergo review periodically by PST Supervisors at the weekly scheduling meeting, with their scheduling typically coordinated with planned maintenance or other work at the locations involved. Furthermore, the entire list of open items undergoes in-depth annual review. Management prioritizes substation capital projects under by a scoring method similar to that applicable for transmission and sub-transmission work. As with substation inspections, substation equipment maintenance work is scheduled and tracked in the computerized maintenance management system. Work order data remains available (through a macro-enabled Excel Worksheet) to display all planned maintenance for the current year, including the percentage of completions shown on a year-to-date basis. Both operating regions can then obtain various “maintenance due” and “maintenance complete” reports from an Access-based report generating tool to track maintenance progress. To monitor maintenance work completions, the Power System Operations Planner (within the T&D Planning and Asset Management group) meets monthly with the PST Superintendent and VP of Operations and Engineering to review progress and discuss the overall maintenance plan. PSTs also test protective relays. The Emera Maine system employs approximately 1,000 protective relays in the BHD, 200 relays in in the MPD and 200 relays in MEPCO and Chester SVC facilities. Management tests all transmission and distribution protection relays not regulated by NERC or NPCC on eight- to ten-year maintenance cycles. Management functionally tests relays for its 2.4kV to 34.5kV lines during the breaker maintenance cycle for that circuit. Management tests all relay systems operating at 100 KV and above per NERC standard PRC005-2 requirements. As the next table demonstrates, management substantially completed scheduled substation inspection and maintenance work in 2013 through 2015. Only 69 percent of circuit breaker maintenance was completed in 2015 because of plans to replace the breakers not inspected. Substation Maintenance Completions 2013 Breakers Transformers Substation Inspections (Includes ReadingsIR Scans-Spraying) Relays MEPCO Tasks 17 39 2014 2015 EM % MEPCO EM % MEPCO EM % Combined Completed Combined Completed Combined Completed Tasks Complete Tasks Tasks Complete Tasks Tasks Complete 123 140 102 73 5 87 92 92 100 3 113 126 87 69 264 303 293 97 19 211 230 227 99 23 209 316 308 97 110 1591 1701 1649 97 110 1411 1521 1475 97 110 1722 1832 1687 92 8 72 80 68 85 8 134 142 141 99 59 108 167 151 90 Tree and limb contacts contribute substantially to interruptions that drive SAIFI measures. Some 60 to 70 percent of Emera Maine’s sub-transmission and distribution lines run just adjacent to trees. A substantial number of customer interruptions result from tree limbs coming into contact with lines or from trees and large limbs falling onto lines from outside the trim zone. The numbers of BHD interruptions caused by limbs contacting lines was about the same in 2015 as in 2011, but the MPD experienced an increase in outages from such contacts. Interruptions caused by trees falling into lines decreased in both regions in 2015, as compared with 2011. Vegetation Management, especially tree trimming and hazard tree removal comprises a central means for minimizing tree-caused outages. Utility management needs to set trim schedules on August 8, 2016 Page II-19 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version the basis of growth rates for the tree species creating exposure for overhead lines. Management mitigates new growth limb contact by trimming the trees on all lines to clearances of 10 feet to the side and 15 feet above the nearest conductors. However, fallen trees and large limbs have proven a primary cause of outages. To mitigate tree contact, management uses contractors to apply herbicides in transmission and sub-transmission right of ways on five-year cycles, supplementing such treatment mid-cycle with mechanical cutting where herbicides have not controlled growth. Contractors also trim trees growing adjacent to, overhead, and beneath transmission and sub-transmission lines on five-year cycles. The 34.5kV lines comprise an exception; six-year cycles are set when determined prudent by the Vegetation Management Supervisor. Management conducts vegetation management on its distribution circuits on threeyear cycles for circuits serving 1,000 or more customers and on six-year cycles for other circuits. These cycles reflect increased frequency, as compared with the seven-year cycles used prior to 2014. Management based this increased frequency a survey it conducted of the other New England utilities. That survey indicated an average cycle of five years. The Emera Maine territories are further north by comparison, producing slower growth that led to the six-year trim cycle. Management also determines whether to conduct special trims on line sections, using as criteria with the following characteristics, as measured over the previous 12 months:  Outages under the weather, trim, and no fault found categories produced a SAIFI greater than 3.00  Outages in these three categories produced a SAIFI greater than 2.00 and service interruptions per mile exceeded the annual SAIFI target  At least two outages coded to the inadequate trim category, regardless of overall SAIFI value. Management attempts during tree trimming activities to mitigate outages caused by fallen trees by removing hazard those trees outside the trim zone, but obviously presenting a danger of falling due to wind, snow, and ice. The impracticability of removing the many thousands of possible danger trees adjacent to the lines makes it necessary to use judgment in determining where to apply this practice. The next table shows that management has been substantially completing its vegetation management work as scheduled since 2013. Year 2011 2012 2013 2014 2015 Vegetation and Tree Trimming Work Completed BHD MPD Transmission Transmission Distribution Distribution ROW Roadside ROW Roadside 100% 100% 86% 100% 100% 75% 100% 100% 100% 100% 100% 72% 100% 100% 97% 100% 100% 100% 100% 100% 97% 100% 100% 100% 100% 100% 98% 100% 100% 100% The next table shows expenditures of about $5.24 million on vegetation management in 2015. Since 2011 (2013 for the MPD), the vegetation management spend, including trimming trees and August 8, 2016 Page II-20 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version removing danger trees, has been consistent with budgeted amounts. Management has increased vegetation management spending by 20 percent above 2013 levels, reflecting the 2014 change to a six-year cycle. It will take the full six-year cycle or longer for standard reliability measures to begin to show the effects of a shorter trim cycle. Year 2011 2012 2013 2014 2015 Budget $2,634,823 $2,851,908 $2,960,623 $3,262,131 $3,799,089 Vegetation Management Spending BHD MPD % Actual Budget Actual Variance $2,641,224 0% Not Available $2,823,378 1% $2,852,122 4% $1,278,780 $1,257,242 $3,537,150 -8% $1,457,082 $1,380,216 $3,777,999 1% $1,437,659 $1,463,534 % Variance 2% 5% -2% G. Conclusions - T&D Systems Maintenance 4. Current T&D inspection and maintenance programs are appropriate. The management and substance of current formal inspection programs and cycles for transmission, sub-transmission, and distribution lines and circuits, and its tracking of inspection completions by asset management, are appropriate for the electric systems that Emera Maine operates. They address needs comprehensively, employ a sound organizational structure, have appropriate staffing, and include sound measurements of performance. 5. The failure to conduct scheduled roadside and right of way inspections in 2014 and 2015 did not comport with good utility practice. Management substantially completed its aerial, ground-line and thermal inspections on transmission and sub-transmission lines. The Company, however, did not perform roadside and right of way inspections scheduled in 2014 and 2015 on either transmission or distribution systems. It conducted no formal visual inspections on the distribution circuits in the MPD since at least 2011. The failure to conduct these important inspections for two consecutive years violates good utility practice, missing opportunities to identify possible discrepancies that threatened system reliability (e.g., outages). In 2014, management realized that it did not have the resources to conduct its overhead line inspections, but it did not hire an inspection contractor to assist with the inspections until 2016. In 2016, management begun to recover from the non-compliance to its inspection programs by using contractors to supplement its own inspection resources, and by increasing the number of inspections conducted each year by 25 percent until 2019. The existence of these measures, assuming that no further gaps occur in the inspections involved, resolve the problem. 6. Substation inspection and maintenance programs are appropriate. August 8, 2016 Page II-21 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version The substance and intervals, completion rates, and management processes of the substation inspection and equipment maintenance programs are appropriate. T&D Engineering, Asset management, and the PST department work closely together to take responsibility for the condition of substation equipment and some line mounted devices. Management inspects substations at least once every two months, conducts basic maintenance and testing of its substations every few years, and triggers major maintenance based on inspections, numbers of operations, or test results. All substation work orders are software driven, as are all inspection and maintenance results records. 7. The sub-transmission pole testing and treating program is appropriate. The transmission and sub-transmission pole testing and chemical treating program (ground-line inspections) and the hazard pole replacement program and activities are appropriate for extending pole life and for removing hazardous poles. Management does not apply the same program for distribution poles. Including distribution poles in the sub-transmission and transmission ground-line inspection program does not currently have priority, as it does little to improve SAIFI. 8. The T&D vegetation management program is appropriate. Vegetation management (spraying, tree trimming, and hazard tree removals) programs and activities are appropriate. Management has been conducting activities on transmission and subtransmission lines on a five-year cycle, and on distribution circuits on a six-year cycle since 2014. The shortening of the distribution trim cycle was appropriate for the species of trees in northern Maine. Tree limb contacts do cause some customer interruptions, but we did not observe any critical tree intrusion issues during its drive-by inspection of randomly selected lines and circuits. H. Recommendations – T&D Systems Maintenance Liberty has no recommendations in the area of T&D Systems Maintenance, but notes the importance of continuing the roadside and right of way inspections it failed to conduct in 2014 and 2015, but has since resumed. I. Findings - T&D Reliability Liberty reviewed the causes of customer interruptions since 2011 to determine how and to what extent management addresses their causes in planning, scheduling, and executing projects focused on enhancing reliability. Porcelain cut out switches comprised a major source of outages caused by equipment failures. Porcelain cut out switches have a design or manufacturing issue that causes them to break and fall into lines. Decay caused transmission, sub-transmission, and distribution wood cross arm breakage during the period 2011 through 2015. The more varied causes of transmission and distribution conductor failures include factors such as cold weather, excessive slack, burned taps, fatigue, loose connections and corrosion. Excluding weather caused interruptions, car pole accidents comprise the second or third greatest cause of customer interruptions every year. Liberty observed that some sub-transmission and distribution lines run beside secondary roads that have no shoulders, with poles very close to the roadway. Pole replacements generally require lengthy outages, especially for those poles August 8, 2016 Page II-22 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version carrying two or more circuits, and for guyed corner poles. The resulting outages have adversely affected CAIDI and SAIFI values. Management has not taken focused actions to mitigate car pole accidents, except for replacing broken poles with stronger poles. Management has been taking action to mitigate fallen trees. It has been using Hendrix aerial cable when replacing some three-phase overhead open-wire sub-transmission and distribution line sections exposed to fallen trees and large limbs. The insulated and bundled Hendrix cable can withstand the weight of some trees and large limbs without causing outages. It also does not cause a short circuit when limbs grow into it. Since the 1960s, management has installed about 1,375 miles of Hendrix cable. The unit costs of Hendrix cable are about three times those of open wire construction, but management finds justification in specific locations as a cost effective way to improve SAIFI and to reduce tree trimming needs. Not all discrepancies can be repaired when identified, but a method of prioritization should exist and provide for eventual correction of all significant discrepancies through reliability projects. Management repairs T&D line discrepancies immediately through O&M service orders in those cases where they cause an outage, or where inspections observe a discrepancy that poses an imminent threat to system reliability. Management expects all discrepancies to be corrected within one or two years, depending on priority. For all non-imminent discrepancies, inspectors enter discrepancies into the GIS. T&D planning engineers then review and prioritize them individually (high, medium, or low). Non-imminent discrepancies and other equipment targeted for repair or replacement are bundled per line section, and included for consideration when T&D planning engineers develop reliability projects. Planning engineers use a weighted scoring method for prioritizing transmission and sub-transmission capital projects, based on equipment condition, the number of discrepancies on a line needing mitigation, the effects on customers and need for improved load flow. For determining the total discrepancy score, the engineers apply weights to each discrepancy: 60 percent for high priority, 30 percent for medium priority, and 10 percent for low priority, and then total the score for each line section. Applying a weighted score to each potential reliability project offers a good method for prioritizing and ranking reliability projects. We reviewed the current list of scored and ranked transmission and sub-transmission line reliability projects. The 2016 Transmission Line Assessment (which includes sub-transmission) indicates the total “scores” on about 84 lines or segments. The scores on these lines ranged from 253 down to 10. The table below illustrates the maximum points that can be assigned for each criterion. The table describes the allocation of points. Cond ition & Perfo rman ce Transmission and Sub-Transmission Assessment Prioritization Criteria Aggregate Maximum Category Criteria Category % of Total Weighting Weighting Pole Age 50 points August 8, 2016 200 points 40% Page II-23 The Liberty Consulting Group Loadability Customer Public Utilities Commission State of Maine           Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version % Poles with Internal Decay 100 points Facility Maintenance Objects 50 points Quantity of Customers Served 30 points Critical Customer 30 points Public Safety 50 points 3-Year Rolling ASAI 50 points Power Flow (Primary or Back-up) 20 points Configuration (Radial or Loop Feed) Power Flow (Need for Reconductor) 20 points 160 points 32% 140 points 28% 100 points Pole age – Lines with poles with average in-service year of or after 1985 receive 0 points. Percentage of poles with decay – Lines with no decay receive 0 score. Facility maintenance objects – The more the discrepancies identified by inspections the higher the score. Customers served – Lines that serve 50 percent of more of the customer base receive the highest score. Customer Critical – Lines that serve critical customers: i.e., wholesale, generators, industrial, and large commercial receive higher scores. Public Safety – Lines that have a higher percentage of their length along roads, higher percentage of older poles, and the most discrepancies receive highest scores. Lines on ROWs away from roads receive 0 points. Three-Year Rolling ASAI - Transmission lines with lower three-year average system availability index receive higher scores. Power flow – Lines that are the primary source of power flow receive 20 points, back up lines receive 10 points. Configuration – Radial lines receive 20 points and looped lines receive 10 points. Reconductor – Lines that have been identified for reconductor within 5 years receive 100 points; within 10 years receive 50 points Management’s asset management approach does not use a formal scoring matrix for ranking distribution reliability projects as it does for transmission and sub-transmission projects. Management ranks distribution circuit projects based on potential reliability impact, costs, risk, and synergies with other potential candidate projects. Planning engineers analyze reliability data to identify targeted projects for its capital plan. Examples include porcelain cut out switches (which cause the most equipment-related interruptions) and dead end insulators (the second most common). Management has also been replacing obsolete oil-filled reclosers, transformer bushing types with high failure rates, and circuit breakers types that have operational issues. Planning and scheduling bundles other maintenance and repair work with the replacement of these devices to maximize reliability work performed during planned outages. When prioritizing distribution projects, T&D Planning considers efficiencies achievable that exist by combining multiple, similarly prioritized projects. Some utilities score circuits for reliability projects based on the amount of SAIFI improvement versus cost. Management August 8, 2016 Page II-24 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version qualitatively considers reliability, but does not perform quantitative cost/benefit (reduced customer interruptions and improved SAIFI) analyses in its prioritization. For substations, management uses an assessment matrix when considering substation power transformers in short and long term planning processes. Management ranks power transformer major maintenance replacements based on the probability of failure, on test results and potential impacts to customers and the environment. A utility should use the reported causes of outages and the number of customers affected by outages as a factor in setting priorities. Service Crews report the causes of outages using outage cause codes. Asset Management analyzes the outage cause-code and customer interruption data to determine where to target specific projects based on equipment condition and performance, and customer impact, including:  Component types with high failure rates and high customer impact  Component types with low incident failure rates but extraordinary high customer impact  Identification of circuits for application of animal guard protection  Using Average System Availability Index (ASAI) in the Transmission Line Assessment process. Emera Maine uses porcelain “cut out” disconnect switches throughout its distribution system. These cut out switches fail mechanically and fall into lines with some frequency. The legacy companies installed more than 20,000 porcelain body cut outs by the early 2000s in the BHD and by the late 2000s in the MPD. Management began replacing porcelain cut outs on an on-going basis, using a target program approach. It has been replacing porcelain cut outs on main line circuits where it has determined that it will achieve the highest reliability gains. Management has addressed over 60 of about 250 circuits, and plans to continue the replacement program under the same approach. Management applies an annual worse performing distribution line section program to addresses circuits causing excessive interruptions to some customers, but which might not be addressed in regular reliability projects. Per an agreement with the Commission, management applied from 2011 through 2014 a reliability program for addressing the annual top-ten, worst performing circuits as measured by SAIFI (excluding major events). T&D Planning personnel analyzed specific outage history data for each circuit in an effort to identify what actions, if any, could be taken to improve their reliability. Beginning in 2015, management modified the program to address its “worst performing line sections.” This program targets specific line sections that cause high SAIFI. The annual base capital plan includes T&D projects (including reliability projects) determined through a routinely applied process. First, T&D Planning enters all company-wide proposed T&D projects into the candidate project database that includes proposed projects from all areas of the Company. The group assigns each T&D project a preliminary priority of 1 through 5 based on equipment condition, reliability impact, environmental impact, safety, cost, and other impacts. T&D Planning, working with personnel from the Engineering Department, meet on a continuing basis to develop further each project, while also refining their scope, costs, and priority to determine a final listing of proposed T&D projects to include in an annual Capital August 8, 2016 Page II-25 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Plan. The Asset Management Team then makes the determinations of which proposed T&D projects to include in the Capital Plan. We reviewed the list of T&D capital reliability projects for 2011 through 2015. The table below lists the numbers of annual reliability projects. We observed that management justified a portion of its 2011 through 2015 projects primarily on the basis of a condition-based assessment, with reliability comprising the primary risk to be mitigated in case of failure. Examples include condition based line rebuilds for those with known high failure rates. Some of the projects formed part of outage mitigation programs targeting specific poor performing equipment, such as decayed cross arms, porcelain cut out switch replacements, animal protection and lightning protection additions, replacement of poor performing conductors, and targeting worst performing circuits. Some of the reliability projects were also required to increase capacity and to loop the system for example, installation of new line in the Down East. Distribution Reliability Projects Year 2011 2012 2013 2014 2015 BHD 54 62 57 74 58 MPD No Records 45 46 40 Typically, utilities plan to apply reliability projects sufficient to improve SAIFI in a measurable way. Emera Maine’s strategy differs from what we have customarily observed in that it seeks to maintain SAIFI, rather than to improve it measurably. Management sets the T&D reliability budget for the following year, based on project priority and on rough estimates of project content and cost. Initial annual capital plans use rough cost estimates and initial assumptions about design, resources, workability and weather. However, management makes adjustments to the plan after the initial approval, via change orders, such as project rejections or project deferrals because of more accurate engineering, scheduling, resources and emergent reliability projects (the Company has a contingency account for emergent projects). Inclusion in the budget approved by the board of directors (based on rough estimates) does not necessarily authorize the work. That formal authorization generally comes for larger projects after more detailed estimates produce estimate refinement and a smaller error band around the estimate’s listed dollars. The capital reliability project budgeting process essentially remained unchanged over the years, except that in 2015 and 2016 management enhanced capital planning and execution procedures to improve initial estimates and provide better overall management, as discussed in the next section of this report. The following flow chart illustrates how a proposed project is selected for the final capital budget. August 8, 2016 Page II-26 The Liberty Consulting Group Public Utilities Commission State of Maine Asset Management or Business Development Project Proposals Project Management Planning Engineer Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Engineering Internal or External Rough Estimate on Excel sheet No accuracy assured at this point Final Capital Estimate Approval, Deferral, or Denial Project Schedule Requests for Proposals Approvals based on Rough Estimates Detailed Engineering to 5-10% accuracy Thus, the early estimates used for establishing the annual budget do not provide hard caps at the individual project level. The board-approved annual budget operates on a total dollar basis, leaving management free to adjust estimates and project priorities as more definitive estimates emerge. Generally, after more definitive estimates emerge (typically those used to authorize work to proceed) management establishes five percent for base capital projects and ten percent for major projects as the variance level triggering the need for approval to spend more than a project’s individual budget. Management tracks it the base capital project and the major capital spend on a monthly basis, using a web-based application. Management reviews capital project spending and forecasts on a monthly basis. In 2015, the Company completed 95 reliability projects. Management, however, deferred 33 additional reliability projects originally planned for 2015. Emergence of higher-priority reliability projects as the year progressed drove much of the deferral. For 2015, the Company’s sustaining Capital Plan for reliability projects had a budget of $7,623,141. The Company’s 2015 spend for T&D reliability projects was $7,723,558, or 28 percent of the total Base Capital Plan of $27,520,630 budgeted and $27,620,727 actually spent. Emera Maine has experienced particularly lower reliability when measured by the frequency of interruptions (SAIFI). Comparisons to other companies using the IEEE 2.5 Beta exclusion method show the company at essentially the bottom of the comparative list. The next table shows Emera Maine’s SAIFI values for 2011 through 2015. SAIFI Values Year SAIFI 2011 2.40 2012 2.26 2013 2.81 2014 2.88 2015 2.34 August 8, 2016 Page II-27 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version '''''''''''''' ''''''''''''' ''''''''''''''''''''''''''''' '''''''''' ''' '''''''''''' '''''''''''''''''' ''''' ''''''''''' ''''''''''''''' ''''' ''' '''''''''''' '''''''''''''''''''''' '''''''''''''' '''''''''''''''''''''' '''''''''''''''' ''''' ''''''''''''''''''''''''''' ''''''''' '''''''''''''''' ''''''''''''''''' '''''''''' '''''''''''''''''''''''' ''''''''''''' ''''''''''''''' ''''''''''' '''''''''''''''''''''''''''''' '''''''''''''''' '''''''''''''''''' ''''' ''''''' '''''''''''''''''' '''''''''' ''''''''''''' ''''''''''''''''''''' '''''''' ''''''''''' ''''''''''''''''' ''''' ''''''' ''''''''''' '''''''''''''''' ''''''''''''''''' '''''''''''''''''' ''''''''''''''''''''''''' ''''''''''''''''' ''''''''' '''''''''' '''''''''''''' '''''''''''''' ''''''''''''''' '''''''' ''''''' '''''''''''''' '''''''''''''' '''''''''''''' '''''''' ''''''''''''' ''''''''''''''''''''' ''''' ''''''' '''''''' ''''''''''''''''' '''' ''''''' ''''''''''''''' ''''''''''''''' '''''''''''''''' '''''''''''''''' ''''''''''''''''''''''' '''''''''''''''''''' ''''''''''''''''''''''''''''' '''''''''''''''''''''' ''''' '''''''''' '''''''' ''''''''''''' ''''''''''''''' ''''''''''''''''''' '''''' ''''''' '''''''' '''''''''''''' ''''''''''''''' ''''''' ''''''' '''''''''''''''''''' '''' ''''''' ''''''''''''''''' '''''''''''''''' ''''''''''''' '''''''''' '''''' ''''''''''''' '''''''''''''''''''''''''''' '''''' ''''''' '''''''''''''''''''''''' ''''''''''''''''''''''''' ''''''''''' ''''''''''''''' ''''' ''''''''''' ''''''''''''' ''''''''' '''''''''''' ''''''''''''''' ''''''''' ''''''''''''''''''''''' '''''''''''' ''''''''''''''' '''''''''''''' '''''''''''''''''''' ''''' ''' '''''''''' ''''''''''''' '''''''''''''''' ''''' '''''''' ''''''''''''''' '''''''''''''' '''''''' '''''''' '''''''''' '''''''''''''' ''''''' ''''''''''''''' '''''''''''''''''''''''''''' ''''' ''''''' '''''''''''''''' '''''''''''''''''''''' ''''' ''''''' '''''''' '''''''''''''''''' ''''''' '''''''' '''''''''''''''' ''''''''''''''' '''''''' '''''''''' '''''''''''''''' '''''''''''''' ''''''''' ''''''''' ''''''''''''''''''' ''''' '''''''''''''''''''''''''''' '''''''''''''''''''' ''''''''' '''''''' ''''''''''''''''''''' ''''''''''''''''''''' '''''''''''''' '''''''''''''''' '''''''''''''''''''''''''''' '''''''''''''''''''' ''''' '''''''' ''''''''''''''''''''''''' '''''''''''''''''''' ''''''' '''''''''''''''''''''''''''''' '''''''' '''''''''''''''''' ''''' ''''''''''''''''''''''''''' '''''''''' ''''''''''''''' '''''''''''''' '''''''' ''''' ''''''' '''''''' ''''''''''''''' ''''''''''''''''''''''''''' ''''''''' '''''''''''''''''' ''''' ''''''''''''''''''''''''''' ''''''''''''' ''''''''''''' '''' ''''''' ''''''''' ''''''''''''''''''' '''''''' '''''''' ''''''''''''''' '''''''''''''''' '''''''''''' ''''''''''''''''''''' ''''' ''''''' ''''''''''''''''''''''''' ''''''''' '''''''''''''''''''''''' '''' ''''''' '''''''''''' '''''' ''''' ''''' '''''' '''''''''''''''''' '''''''' '''''''''''''' ''''''''' '''''''''''''' ''' '''''''''''''''' '''''''''''''' ''''''''' '''''''''''''''' '''''''''''''''''''''''''' ''''''''''''''''''' ''''''' '''''''''''' ''''''''''''''''''''''''''' ''''''''''''''''''' ''''''''''''''''''''' ''''' ''' ''''''''''''''''''''''''''''' '''''''''''''' '''''''' ''''''''''''''''' '''' ''''' '''''''''''''''''''''''''''''' '''''''''''''''''' ''''''''' '''''''''''''' ''''''''''''''' '''''''' ''''''' '''''''''''''''''' ''''''''''''''' ''''''''''''''' '''''''' '''' '''' ''''''' ''''''''''''''''''''''' ''''''''' '''' ''''''''' '''''''''''''''''''''''''' '''''''''''''''' ''''''''''' ''''''''''''''' '''''''''''''''''''' '''''''''''''''''' ''''''''''''''''''' ''''''''' ''''''''''''''''''''''' ''''''''''''''''''''''''''''''''' ''''''' ''''''' ''''''''' '''''''''''''''''''''''' ''''' ''''''''''''''''''''''''' ''' '''''''''''''''''''''''''''''''' ''''''''''''''''''''''' '''''''''''''''''''''' '''''''' ''''''' ''''''''''''''''''''' '''''''''''''''''''' '''' ''''''''''''''''''''''' ''''''' '''''''''''''''''''''''''''''''' ''''' '''''''''''' ''''''''''''' ''''''''''' ''''''' '''''''''' ''''' ''''''''''''''''''''''''''''' '''''' '''''''''''''''''''''''''' ''''''''''''''''''''''''''''' ''''''''''' ''''''''' ''''''''''''''' For its own internal year to year comparisons, Emera Maine has used the older method generally used, i.e., before the IEEE 2.5 Beta method, and it, as is appropriate, has excluded the effects of major outage events. Management’s method excludes customer interruptions for any 24-hour period during which at least 10 percent of the customers were affected. The next table shows management’s computation of SAIFI values using this method. Alternate SAIFI Calculation Year 2011 2012 2013 2014 2015 SAIFI 1.67 1.78 2.32 2.08 1.65 Management set its 2016 SAIFI goal as the average of the SAIFI values for the past five years, calculated per its alternate method. That approach incorporates the substantial “breathing room” provided by the storm influenced values of 2013 and 2014. In so doing, management explicitly acknowledges that performing at that average (1.90) constitutes acceptable performance, despite the fact that it would be some 15 percent worse than the 2015 value of 1.65 and significantly worse than the 2011 and 2012 values as well. We believe that this target fails to provide the incentive needed to move SAIFI in a positive direction. That Emera Maine is not likely to be August 8, 2016 Page II-28 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version able to reach the average does not mean that it should not strongly strive to move upward in the fourth quartile, or, depending on success over time, to set even more aggressive targets. I. Conclusions - T&D Reliability 9. Matching five-year average SAIFI values does not provide sufficient stimulus to improving reliability performance. (Recommendation #5) In a narrow sense, management uses T&D reliability projects appropriately to maintain a more or less constant SAIFI, but it should use a more aggressive target. Doing so would result in greater priorities on reliability improvement work. Absent clear and convincing information showing that customers consider the current reliability benefit versus cost tradeoff effective, it appears to us that reliability improvement should have a greater priority and be supported by quantitative improvement goals. J. Recommendations – T&D Reliability 5. The Company should adopt the objective of making steady improvement in SAIFI as compared with 2015 levels and develop an improved method of ranking reliability projects. (Conclusion #9) Eliminating the five-year average approach and using 2015 SAIFI values as a floor, from which to seek steady, year-over-year improvement is in order. Moreover, management’s prioritization of potential projects should begin considering the calculated numbers of expected customer interruptions avoided, after project completion, versus the cost of the project. That metric should be among those used to make comparisons with other potential projects when setting priorities. Using the avoided customer interruption method of ranking allows each project to have a cost per avoided customer interruption value that can be measured in a quantitative way. These estimates could be based on either the known outage history of the circuit section, or on the calculated numbers of customers affected if an outage occurred because the project was not completed. This approach would, for example, give radial sub-transmission lines higher priority than looped lines, and would provide a method of selecting the order to replace porcelain cutouts and prioritizing other projects to quantitatively determine SAIFI reductions for the least cost. K. Findings - Budgeting The preceding section examined how management prioritizes capital T&D reliability projects, how its makes adjustment to reliability projects included in the annual capital budget, and how it increases budgets when necessary and tracks capital project costs. This section examines overall how management prioritizes, compares, ranks, and manages costs of all capital projects. It also looks at O&M budgeting and spending. We looked at T&D O&M budgets and expenses for 2013 through 2015.. The next table shows that management has operated within its O&M budgets, except for deviations resulting from the seven severe storms of 2013 and 2014. O&M spending for 2014 increased about two percent (excluding including storm costs) from 2013, and 2015 O&M spending increased almost five percent from 2014 levels. August 8, 2016 Page II-29 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version Emera Maine O&M Budgets and Spend for 2013 through 2015 Capital Planning Engineering Field Ops PST Sys Ops Trans Development Total w/o storms 2013 2013 2014 2014 2015 2015 Budget Actual Budget Actual Budget Actual 1,300,388 816,267 1,223,398 725,280 1,620,935 905,822 867,394 944,979 992,604 960,420 1,020,436 950,842 6,857,774 6,810,026 7,426,601 7,227,784 7,923,713 8,344,939 2,798,751 2,619,454 3,014,189 2,745,035 3,393,595 3,093,325 2,541,856 3,257,505 3,850,273 3,087,545 3,267,232 2,171,980 240,848 85,018 188,212 119,133 212,790 97,636 14,607,011 14,533,249 16,695,276 14,865,196 17,438,701 15,564,543 Storms Total w/storms 469,930 1,505,867 417,000 6,679,634 1,151,234 -557,271 15,076,941 16,039,116 17,112,276 21,544,830 18,589,935 15,007,271 We examined how management prioritizes and ranks overall base and major capital plans. The primary purpose of Emera Maine’s Asset Management Model is to manage its capital expenditures using it as the basis for driving operational and capital budgeting to provide for:  Business needs, including IT, fleet, and facilities: to improve efficiency, meet regulatory requirements, or mitigate unacceptable business risk  Power line inspection program activities  Substation inspection and maintenance program activities  Meeting T&D system capacity growth requirements  T&D reliability improvement projects. The sustaining or base capital plan includes ongoing, non-discretional and discretional categories. The non-discretionary category includes addressing service to new customers and addressing contractual, statutory, and regulatory obligations, including State and municipal road construction projects and telephone company requests. The discretionary category includes addressing business, fleet, and IT needs, addressing reliability projects for mitigating the effects of age, condition, equipment ratings, and specific and system performance issues, and for addressing T&D system capacity growth, replacing and upgrading end of life or failed T&D equipment (which includes unplanned storm damage, accidents caused by others, and premature equipment failures), and special projects (which sometimes are non-discretionary). Before determining the capital plan, each business area gives its projects a priority level relative to the area’s other submissions, based on safety, productivity, reliability, or customer satisfaction, depending on the project. The Asset Management Team performs a series of iterations, including direct discussion with personnel from the various business groups. This group assesses the business cases offered. It does not use a “scoring” system to rank potential projects, but examines and validates costs and benefits as proposed. Asset Management applies a holistic view of how proposed projects satisfy overall risk, needs, and business gap issues. A resulting, recommended capital budget goes to the Capital Review Committee for review. The committee’s members include the VP Operations and Engineering, the COO, the VP Finance, the VP Performance, Planning, and Strategy, the Director of IT Facilities and Fleet, the Manager of Financial Planning, and the VP of Customer Experience. August 8, 2016 Page II-30 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version This group determines the total discretionary budget available for each year, based on current and forecasted business metrics, and ranks proposed discretionary projects based on impacts to safety, reliability, financial performance, employee satisfaction, customer quality indicators, and impact on load growth. Subsequently, management pares down the proposed projects to create a final capital plan that satisfies targeted business metrics, financial considerations, and promotion of sustainability. Major projects outside of the scope of the base capital plan must be brought forward on a line item basis. They require executive sponsorship and undergo review and evaluation before authorization. Management realized that it had issues with cost estimating, communications, and other matters related to its capital planning and execution. The Company added in 2015 a new position, Manager of Capital Financial Planning. It also updated and improved the capital planning process, and changed its approvals and forecasting processes to improve control, efficiencies and internal communications. An important element in the changes was to improve accounting controls and to strengthen the linkage between engineering and finance resources engaged in planning and budgeting. Improvements included standardizing contents of business cases and cost estimates, revamping the approvals process for different project categories. Management developed Web-based tools for producing timely and accurate monthly progress reporting and forecasting. Management is also making improvements in method to track project costs. The next table shows reasonably consistent funding of Base Capital transmission and distribution work, most of which is reliability-related. However, since 2012, the Company consistently underspent its BHD Major Capital Transmission Plan budget, especially in 2012. The Company overspent its 2011 major transmission capital budget by about $8 million, and underspent its 2012 and 2014 major transmission budgets by about $11 million and $4 million, respectively. Management reported that its escalation of the Down East Reliability Project in 2011 caused the overspend of the budget in that year. This multi-year project came in under budget overall. A schedule change on one major project (Line 51/93 Rerate) largely drove the 2012 underspend. Management not accomplished this project until completion of the new Down East Reliability Project, which provided the redundancy needed to take 51/93 out of service. Management originally scheduled the Down East line for completion in the first half of 2012, followed by work on the 51/93 line in the second half. This plan placed the majority of line 5193’s cost in 2012. A need to optimize schedules for other projects produced a decision to extend Down East completion date to the end of 2012. This delay in turn created the need to shift the 51/93 work from 2012 to 2013, resulting in the underspend of over $10M for this project in calendar year 2012. The underspend for 2014 was the result of the timing on a reimbursement from CMP for the Chester SVC Project. Emera Maine Capital Budgets and Spends 2011 Business Plan 2012 Actual Business Plan 2013 Actual Business Plan 2014 Actual Business Plan 2015 Actual Business Plan Actual BHD August 8, 2016 Page II-31 The Liberty Consulting Group Public Utilities Commission State of Maine Base $17,983,749 $15,757,490 Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version $18,035,202 $17,215,292 $18,546,408 $18,521,915 $19,551,183 $18,946,388 $20,131,083 $20,843,353 Transmission $1,595,948 $2,600,616 $1,568,403 $2,078,529 $2,952,901 $2,806,436 $2,808,801 $2,048,969 $3,384,693 $1,596,636 Distribution General Property Intangible $12,247,970 $10,021,706 $11,766,219 $11,946,189 $12,162,719 $11,718,413 $11,321,333 $11,739,418 $11,909,830 $12,892,454 $3,248,798 $2,532,277 $3,993,453 $2,936,186 $2,985,366 $3,825,551 $4,703,198 $4,434,523 $4,127,274 $6,015,128 $811,033 $538,130 $707,128 $169,762 $351,043 $74,972 $471,371 $405,742 $480,562 $266,987 $80,000 $64,760 $0 $84,626 $94,379 $96,543 $246,480 $317,736 $228,724 $72,148 $51,879,824 $60,032,784 $43,682,157 $32,595,740 $33,318,817 $32,593,229 $18,884,605 $14,503,472 $6,338,610 $4,916,461 $0 $0 $1,051,728 $297,336 $513,106 $121,868 $486,561 $1,190,489 $1,622,971 $3,416,077 $0 $0 $0 $0 $5,500,000 $6,222,517 $11,003,737 $7,130,967 $3,162,840 $3,555,240 $9,650,503 $4,416,742 $6,404,856 $4,461,137 $5,911,526 $6,028,948 $3,627,880 $8,009,947 $3,082,732 $6,402,083 $7,998,800 $8,096,686 $4,508,664 $7,663,448 $7,312,705 $6,776,874 Transmission $943,800 $1,318,804 $440,400 $711,734 $1,155,854 $1,220,247 Distribution $5,262,083 $5,222,615 $2,710,649 $4,829,081 $3,982,157 $4,031,684 $1,481,817 $311,100 $1,502,51 6 52,751 $2,154,63 1 ($31,998) $1,824,974 $349,720 $1,523,36 1 $1,583 Internal Combustion Major **Transmission Distribution General Property Intangible MPD Base General Property Intangible Note: Budget vs. actuals for the categorization requested Major is unavailable for this year. Note: Budget vs. actuals for the categorization requested $764,99 0 $592,62 5 is unavailable for this year. Transmission General Property $500,004 $3,757,185 $7,557,010 $11,402,819 $8,891,270 $6,316,018 $379,104 $132,210 $0 $108,097 $5,579,764 $1,587 Intangible $2,497,000 $1,546,973 $1,492,607 $1,618,942 $0 $416,584 ** Excluded funds budgeted for purchase of transmission line to Evergreen wind farm. Purchase from third party not completed. Excluded budgeted amounts: $30 million in 2012, $20 million in 2013, and $30 million in 2015. L. Conclusions –Budgeting 11. The budgeting and cost tracking processes are appropriate for managing capital funding and spending. Budgeting occurs through defined, regularly applied processes. Management has recently addressed a number of budgeting and budget management issues that provide for greater rigor and controls in budget formation and management. M. Recommendations -Budgeting Liberty has no recommendations regarding budgeting, apart from enhanced treatment of reliability projects as described in the previous section. N. Findings – Managing Field Work Emera Maine uses line workers for addressing customer service orders, for responding to outages, for repairing line equipment, and for working capital line projects. We verified that management was tracking service order and work order completion via weekly or monthly reports. We discussed above the use of paper service orders and work orders for line work, and consider the introduction of greater automation a matter warranting examination, in order to improve work tracking and reduce labor requirements. We discussed earlier the use of the electronic system (no paper) to generate, track, and close substation work orders, and the use of mobile computers for PSTs, which we consider appropriate. August 8, 2016 Page II-32 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version We examined the numbers and allocations of line workers and PST (substation) personnel, the numbers of their supervisors, means for management and control of field personnel, and management’s use of contractors. We also reviewed any recent improvements in how the Company manages its crews. Management locates line workers at the Systems Operations Center in Bangor, at the three field offices in the BHD, and at the three field offices in the MPD. Staffing includes 50 line workers and six supervisors in the BHD, and 15 line workers and two supervisors in the MPD. These line workers make up the service crews that address customer work and power outages. Additionally, management deploys 14 traveling line workers and a supervisor in the BHD, and 13 traveling line workers and a supervisor in the MPD. These traveling line crew resources work primarily on base capital reliability projects. As needed, service line crews can assist other crews, including traveling crews, regardless of where stationed. The Power System Technicians (PSTs) inspect, repair, maintain, and test substation equipment. The Company has 25 PSTs and four supervisors in the BHD, and nine PSTs and a supervisor in the MPD. The line and meter crews (two-person service crews) perform work under most customer service orders prepared by Central Dispatch and Customer Coordinators. These orders include coded completion dates. Construction Planners prioritize this customer work along with capital improvement projects which are assigned to the respective district field office. The following flow diagram illustrates how the Company manages its customer service orders. Engineers if necessary CustomerDriven New Service Customer Services Customer Coordinator Planners using GIS Close out Coordinator prepares Electronic Work Package Line Supervisors and crews Unscheduled crew hours are filled by work on large capital projects in the crew’s district or by helping local crews in neighboring districts. All line work orders are created in the GIS system, August 8, 2016 Page II-33 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version but are provided to crews in paper, and thereafter closed-out by calls from the crews to Dispatch. Dispatchers, track schedule status through a weekly spreadsheet report. Management receives a monthly report. Paper work orders address the base capital projects that traveling construction line crews typically work. The crews do not receive work orders or report progress via computer-based applications. Management generally uses line contractors for major capital projects. Internal or external Project Managers manage the contractors with the assistance of project coordinators, such as line and power system technical supervisors. Management also uses external contractors as needed for capital line work, engineering services, flagging service and other services. In 2015, outside services accounted for 68 percent of labor expenses. Substation and underground work is planned separately from T&D line work. The Asset Management team generates an annual maintenance plan, which it enters into the CMMS (Cascade) database. Cascade automatically generates the O&M work orders required. PST supervisors plan and prioritize O&M work against substation capital work generated from preventative maintenance activities, performance issues, obsolescence or load growth. Work orders for PST crews working on substations get electronically communicated via truck mounted computers. Substation crews stationed in the MPD and the BHD generally perform work assigned by district. Management moves PSTs between districts as required to balance the resources with the work load. PSTs directly close substation work orders in Cascade (CMMS) without generating paperwork. Supervisors and Managers receive weekly and monthly electronic reports. PST uses its Cascade maintenance software to track the status of work orders. PST leadership reviews this report with management during weekly scheduling meetings to make adjustments required. Work deferred or incomplete remains in the system, and becomes part of the maintenance plan for the next year. Management reported that during the last three years, it increased its safety department resources to improve the safety program, to better monitor safety compliance, and to allow the supervisors to focus more on the behavioral aspects of safety (job observations and coaching), as well as crew effectiveness and efficiency. A modified Collective Bargaining Agreement allows line and PST personnel to work in either district. Management hired three new Line & Meter Supervisors from outside and promoted two reputable internal line workers to supervisory roles. It added two new quality assurance supervisors internally for the line department in the BHD District’s busiest areas. The purpose was to provide for better workforce planning and crew scheduling. In the last two years, management has focused on supervisor leadership development including these programs, including bi-annual supervisor leadership forums, people leadership skills workshop, and new supervisor training. In 2015, management established a Competency Based Training and Testing program for line worker apprentices and refresher training as needed for existing 1st class line workers. It assigned energized work to external contractors and Company line workers no longer do live line bare-hand work, which reduced cost by allowing focus on de-energized construction activities. Energized work forms a small percentage of the overall work, making it costly to continue this program. August 8, 2016 Page II-34 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 T&D System Operations and Maintenance Final Report-Public Version O. Conclusions – Managing Field Work 12. The Company’s field work practices are appropriate. The Company has an appropriate number of line workers, PSTs and supervisors, and these resources are appropriately stationed and are sufficiently mobile between the districts to be effective. Supervision and management have appropriate oversight of the field work activities. Also, management appropriately uses line construction contractors for its major projects, and during the last few years, the Company has made several enhancements to improve crew supervision, safety, and mobility. P. Recommendations – Managing Field Work Liberty has no recommendations August 8, 2016 in this area. Page II-35 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Chapter Three Table of Contents III. Customer Service ................................................................................................................. III-1 A. Background .................................................................................................................... III-1 B. Findings.......................................................................................................................... III-1 1. Customer Service Organization & Staffing............................................................... III-1 2. Customer Service Costs............................................................................................. III-7 3. Customer Satisfaction Measurement ......................................................................... III-8 4. Customer Complaint Resolution ............................................................................... III-9 5. Account Creation & Management ........................................................................... III-10 6. Meter Reading & Meter Services ............................................................................ III-11 7. Customer Billing ..................................................................................................... III-12 8. Payment and Collections ......................................................................................... III-13 9. Contact Center Operations ...................................................................................... III-17 10. Revenue Protection.................................................................................................. III-23 C. Conclusions .................................................................................................................. III-25 D. Recommendations ........................................................................................................ III-37 August 8, 2016 Page III-i The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version III. Customer Service A. Background Emera Maine provides customer service through phone, field, and web services. The Company serves approximately 159,000 customers in portions of northern and southern Maine. Emera Maine’s Bangor Hydro District (BHD) serves 123,000 customers in four counties, corresponding to the territory of Bangor Hydro Electric) and the Maine Public District (MPD) serves 36,000 customers in two counties, corresponding to the territory of Maine Public Service. Residential customers comprise 84 percent of the total, and generate 51 percent of total revenues. Emera Maine’s customers account annually for approximately 500,000 customer calls, 1.9 million bills issued, and 2 million customer payments. B. Findings 1. Customer Service Organization & Staffing a. Organization Structure The Vice President (VP) of Customer Experience leads Emera Maine’s customer service organization. The group under this executive has responsibility for most customer-facing functions. Responsibilities include: the customer contact centers, billing and collections, energy efficiency and customer programs, and resource planning, scheduling, and dispatch. The next chart shows the organization of these functions under the VP of Customer Experience. Emera Maine Customer Experience Organization August 8, 2016 Page III-1 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version The Customer Contact Center Operations Manager oversees Emera Maine’s primary customerfacing groups; i.e., the two Customer Contact Centers located in Bangor and Presque Isle. Additional responsibilities include customer account management, account investigation, billing preparation, inside collections, and other customer accounting duties performed by the CSRs when not answering incoming customer phone calls. The Supervisor of Billing and Payment oversees customer billing and payment operations, including customer usage collection, meter data edits, and bill print and delivery (which a thirdparty provider performs for BHD and which MPD prints in-house). Payments arrive electronically through third-party vendors and include a lock-box to process mailed customer payments and a network of non-company retail locations (pay stations) that accept Emera Maine customer payments. The Manager of Resource Planning, Scheduling, and Dispatch coordinates all requests for new and returning electric service connections, electric service disconnections, and electric system maintenance activities. The group also dispatches line crews and meter service personnel to install or repair lines, services, and meters. The Manager of Customer Initiatives has responsibility for managing and implementing projectbased customer service improvement initiatives. Current and recent projects include: Customer Satisfaction Measurement, Project Katahdin (resolution of outstanding CU go-live issues), and a Heat Pump Pilot. The Customer Experience organization relies on several third-parties to provide services to customers. These outsiders provide:  Lockbox remittance processing (FISC Solutions/Wausau Financial Systems)  Electronic and paper bill printing and mailing (Kubra)  Field collectors (Grid One Solutions)  Debt collection (CBCS National)  Telephony (WG Technology Partners)  eBill and web services (Kubra) needs  Various agency pay stations. Most meter reading (99.6 percent) uses automation, with a small remaining few requiring manual readings. The responsibility for obtaining manual meter reading lies outside of the Emera Maine Customer Service organization. Emera Maine’s Line and Metering Department provides meter reading and other meter-related support services. b. Customer Service Staffing We examined staffing in the customer service functions of Customer Contact Centers, Billing & Payment Processing, Credit and Collection, and Meter Services. The Customer Contact Centers comprise the majority of positions within Emera Maine’s customer service organization, as the table below shows, using year-end numbers. August 8, 2016 Page III-2 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Customer Service Staffing (year-end) Function 2013 2014 2015 2016* 59 57 62 60 CSRs/Lead CSRs 46 43 48 48 Supervisors 5 5 5 4 Other Contact Center Staff 8 10 9 8 Credit/Collection (Office) 1 1 2 2 Billing & Payment 9 10 9 7 CIS Project (dedicated) 8 7 7 0 Meter Services 8 8 8 8 Total Customer Service Staffing 85 83 88 75 Customer Contact Centers Customers at year-end 155,310 155,492 158,767 159,308 Staffing per 100,000 Customers (calculated) 54.7 53.4 55.4 47.1 *As of May, 2016 The current customer service staffing level falls eight percent below the corresponding figures for prior years (after excluding CIS project resources), as seen below in the following chart: Management had reassigned or released the majority of dedicated CIS project resources by the beginning of 2016. From 2011 to 2013, management focused on merger integration and rebranding under the Emera Maine name. As part of these efforts, the Customer Service organizations established a common management team for two contact centers, and created a common public web site. Following the 2011 merger integration analysis, management committed to consolidating contact center August 8, 2016 Page III-3 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version operations in the MPD and closing the BHD contact, using attrition. The recommended consolidation of the centers assumed migration to a single, combined customer information system. Shortly after the CU implementation began for the BHD, management expanded the effort to include a parallel effort in the MPD. Management then expected deployment of CU by the end of 2013. However, with implementation extending well past that date, management had to spend significant efforts to get CU up and running throughout 2014 and through the first half of 2015. In January 2015, management assembled a team to examine the structure and locations of the Contact Centers. The team recommended closing the BHD Contact Center in 2017. However, senior Emera Maine executive leadership decided to defer closing the BHD center to 2019, when the lease expires on the current location. Management announced this plan to employees in April 2015 (shortly before the June 2015 eventual CU go-live date). Subsequently, four CSRs left the BHD Contact Center during the period of April 2015 to October 2015. At the CU go-live date, BHD Contact Center staffing was near its lowest level in two years. Seeking in mid-July to ease escalating call volumes and long wait time, management invoked a system emergency to provide a basis for pulling in additional resources from other areas of the company to handle incoming calls. The CU system emergency ran from July 10 through November 10, 2015. This measure helped address the problems. Since October 2015, management has been filling open BHD CSR positions with reporting to the MPD, to remain consistent with its strategy to close the BHD by 2019. As of May 2016, the number of CSRs who work out of the MPD contact center are approaching the number of CSRs who work out of the BHD contact center, as the following chart shows. August 8, 2016 Page III-4 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version c. Customer Service Reorganization Emera Maine reorganized in August 2015 to form a Customer Experience organization, headed by the Vice President of Customer Experience. This new organization took responsibility for customer service, billing, payment, collections, field order dispatch, and new service. Management made the change in order to increase focus on the customer. Since last summer, the Customer Experience organization focused on stabilizing the CU CIS and identifying incremental improvement opportunities. Management commissioned two external assessments of the Contact Centers and Credit and Collection processes to identify improvement opportunities. Over the next year, management will prepare a Customer Experience strategy and five-year plan to focus on the “most valuable improvements that can be made to serve Emera Maine customers while managing costs.” Management created a Customer Experience Council in early 2016 to focus on the quality of service delivered. The council has cross functional membership, and exists to address process and customer experience challenges that span departments. The Council began meeting in April 2016 and will continue to meet monthly. The Council “owns” the five-year Customer Experience Plan, related budgets, and corporate objectives relating to the customer experience. As defined in the Customer Experience Council Governance Document, the Customer Experience Council will:  Review and approve the five-year Customer Experience Plan, including sign-off on O&M budgets for all Customer Experience operations  Approve any requests for any changes to customer service levels or offerings, including technology projects justified on the basis of customer service that would be submitted to the Emera Maine Board of Directors for approval  Review and analyze all customer service metric performance versus plans and forecasts and reports provided to the Emera Maine Board of Directors  Identify cross-functional, customer-facing processes to be examined by specialist teams re-engineering, in order better to address customer needs (e.g., new-customer connections)  Act as a review board for customer experience efforts and programs  Discuss cross-functional ideas arising from employees through Customer Experience Focus Groups. The Customer Experience organization kicked off an initiative in February 2016 to gather input and ideas from employees to improve the customer experience. Employees form a crossfunctional team with a mission to discuss current challenges which hinder or detract from the customer experience, suggest process improvements, and present a prioritized list to the Customer Experience Council for review. Management intends to award finders’ rewards for any ideas implemented. d. Employee Performance & Development Employee bonus programs seek to align compensation with corporate targets and results, and to reward personal achievements linked directly to overall corporate performance. Emera Maine uses a Corporate Balanced Scorecard (BSC) incentive compensation program for all employees August 8, 2016 Page III-5 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version and a Long Term Incentive compensation program (Performance Share Unit Plan and Senior Management Stock Option Plan) for certain executives. Management sets annual BSC goals at threshold, target and stretch levels in five categories - Safety, People, Customer, Asset Management, and Financial. The Customer component of the BSC applies a Service Quality Index (SQI). The next table lists the metrics that comprise SQI and the 2016 goals and weightings. 2016 Balanced Score Card SQI Metric Goal Weight SAIFI 1.90 25% CAIDI 1.92 30% Calls Answered in 30 seconds 70% 20% Service Order Timeliness 90% 20% Bill Error Rate .13% 5% Three of the five SQI components measure performance of Customer Service related functions - Calls Answered in 30 seconds, Service Order Timeliness (Meter Orders), and the Bill Error Rate. The next table summarizes performance under these three metrics. SQI Performance (Customer Service Metrics) Metric Goal 2013 BHD 2013 MPD 2014 20162 Calls Answered in 30 seconds 80%1 80% N/A 64% 66% 64% Service Order Timeliness 90% 92% N/A 91% 98% 98% .13% .40% N/A .05% 1.31% 4.61% Bill Error Rate 1 2015 2015 and 2016 goal of 70% 2 Through May At the beginning of 2015, management lowered the call answering goal to 70 percent answered within 30 seconds to allow for the expected decrease in productivity due to longer call handle times following go-live. The goal has remained at 70 percent since that time. An 80/20 call answering goal is common within the utility industry. Emera Maine did not meet Call Answer SQI thresholds in 2014 or 2015 and Bill Error Rates exceeded threshold in 2013 and 2015. Year to date 2016 performance has also tracked below threshold. Service order timeliness has exceeded goal since 2013. The 2016 payouts for all non-bargaining unit employees will include a component based on the Corporate BSC and a component based on the results of individual or team goals. Customer Service supervisory employees and non-bargaining unit union employees work with their direct supervisors to complete a MAPP (My Annual Performance Plan) process used throughout Emera August 8, 2016 Page III-6 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Maine. This process sets individual goals and then forms the basis for evaluating individual performance. For bargaining unit employees, MPD CSRs also use the MAPP process, while BHD CSRs use a separate evaluation that prior to December 28, 2015, was used to determine pay. Pay for performance was eliminated in the 2015 bargaining unit agreement. 2. Customer Service Costs a. Operation & Maintenance Expenses The next tables show that Customer Service operation and maintenance (O&M) expenses increased from 2013 to 2015, producing an increase of $4.24 per customer. Contact center O&M costs produced this increase, rising since 2013, while other customer service functional O&M costs fell. The next chart summarizes the changes in O&M costs by major category. After exceeding budget in 2013, Customer Service O&M actual expenses ran below budget in 2014 and 2015, as the next table summarizes. August 8, 2016 Page III-7 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version b. Customer Service Capital Costs The next tables show that Customer Service Capital Costs averaged $8.7 million a year from 2013 to 2016 (YTD May), dominated by implementation of the new CIS. CIS costs represent 88 percent of Customer Service capital costs in 2013, 99 percent in 2014 and 2015, and 75 percent in year-to-date 2016. This sum represents an average annual capital spend of $55 per customer. 3. Customer Satisfaction Measurement Emera Maine relies on the J.D. Power and Associates Customer Satisfaction Residential Survey to measure customer satisfaction. J.D. Power and Associates annually compiles customer satisfaction results within the utility industry. This index has wide industry acceptance for measuring overall satisfaction, and provides Emera Maine the ability to benchmark performance on a national and regional basis. The J.D. Power insights, however, do not extend to capturing the views of customers in a particular jurisdiction, which tend to vary. The next table shows that Emera Maine has ranked near the bottom in rankings of the East Midsize Segment of the J.D. Power & Associate Electric Utility Residential Customer Satisfaction survey for the past three years. In 2014, Emera Maine ranked 133 of 138 in the national panel for overall customer satisfaction. While Emera Maine’s overall customer August 8, 2016 Page III-8 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version satisfaction trended up since 2014, so have those of the average for the East Midsize Panel and for the nation as a whole. Emera Maine’s J.D. Power overall Satisfaction Ranking Ranking vs Year East Midsize Panel 2014 14 of 15 2015 14 of 15 2016 12 of 13 4. Customer Complaint Resolution Customers with complaints about a bill, hardship-status determination, or a payment arrangement can contact customer service representatives at the contact center. Customer service representatives escalate complaint calls to the Lead Customer Service Representative or a Customer Service Supervisor. Customers can also call the Public Utilities Commission’s Consumer Assistance & Safety Division (CAD) if dissatisfied with payment arrangements offered or if they have a complaint regarding Emera Maine. The CAD will contact representatives at Emera Maine to inquire about particular customer accounts, and to open complaint cases. Commission representatives contact an MPD supervisor regarding complaints involving that region. A Low Income Rate Administrator in the BHD served as the Commission contact for complaints involving that region. Separate complaint resolution processes remain for each region, because they use a different CIS. Both regions, however, follow similar resolution processes. The Commission sends notification of a complaint’s opening, and issues a case number. The Company has 10 days to acknowledge the complaint. Within a few days, CAD sends an information request. The Company has 30 days to respond. Upon review, the Commission personnel issue a decision and the customer has 10 days to appeal. Emera Maine does not conduct root cause analysis of customer complaints. August 8, 2016 Page III-9 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version 5. Account Creation & Management The Resource Planning and Scheduling group has responsibility for new services. These services include locations without electric service, without a meter, or possessing a meter inactive for a number of months. The Company directs customers requesting new services to the Resource Planning and Scheduling organization, either through the phone menus or through routing by CSRs. New customers speak first with a customer coordinator, who gathers information about the work involved. The customer coordinator assigns a planner, who works with the customer to determine the services needed at the location. In some cases, this process requires design work to install a service extension needed to enable service. Following these steps, the customer coordinates with the planner and customer coordinator as the work progresses. After inspection, the customer coordinator issues a service order to construction to begin any main and service installation work required, followed by a meter set to finalize a new service. The customer coordinator creates the customer account in the customer information system to initiate new service. Management has established service order timeliness goals based on the type of customer requested work: eight days for new services, 18 to 30 days for line extensions, eight days for entrance changes, and eight days for temporary to permanent service. The process from end-toend for a new service generally takes from two to four weeks, depending upon the construction, permitting, and customer coordination required. Customers who move into premises that have electric service begin the service initiation process with the Customer Service organization. CSRs in the Contact Center process these requests for service, and set up customer’s accounts in the billing system. CSRs may require customers applying for service to provide a security deposit, under certain conditions. Chapter 815, Consumer Protection Standards for Electric and Gas Transmission and Distribution Utilities, permits Emera Maine to demand a security deposit if one or more of the following conditions apply to a residential applicant:  No source of income sufficient to pay the cost of utility service  Unpaid residential service balance within the past six years (with Emera Maine)  Unpaid residential service balance within the past 12 months (with any utility)  Unpaid residential service balance within past six years, not paid until after a judgment  Disconnection for non-payment within the past 12 months (by any utility)  Disconnection for theft of service within the past 12 months (by any utility)  Chapter 13 repayment plan dismissed for non-compliance with terms in past 6 years. Emera Maine may demand a security deposit (greater than $100 but less than the sum of the two highest bills at the premise) from any non-residential applicant as a precondition of service. However, upon request, the need for a deposit can be based on a review of prior credit history. On customer request, the deposit may be split into two equal installments, the first payable immediately and the second payable within 30 days. Failure to pay any portion of a deposit subjects the customer to disconnection procedures. The Company must return the deposit (or August 8, 2016 Page III-10 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version apply it to the account) with interest, after five years of good payment history, or when discontinuing service. In place of a deposit, the Company must accept: irrevocable bank letters of credit, surety bonds, third-party guarantees, and letters of good credit. Emera Maine has secured a relatively low number of security deposits from residential applicants over the last three years (on average, 1,200 residential applicants a year are secured with a deposit). In 2015, Emera Maine requested more non-residential deposits than in the two prior years. The next table shows the growth in non-residential deposits received. In March 2016, the Emera Maine Customer Experience organization kicked off an initiative to revise the non-residential deposit guidelines, with the goals of ensuring a consistent approach, allowing flexibility in waiving deposit requirements, and returning deposits for qualified nonresidential customers. 6. Meter Reading & Meter Services Emera Maine has approximately 127,586 electric meters in the BHD and 35,932 electric meters in the MPD. Automated Meter Reading (AMR) or Automated Metering Infrastructure (AMI) read approximately 99.6 percent of the meters. Management thus reads only about 0.4 percent of meters manually each month. Most manual meters remaining are in the BHD. Meter Service Representatives from the Line and Meter Department obtain manual meter readings, and perform meter service activities required in the field. The Line and Metering Department also has responsibility for system and customer generated service orders, including: on/offs, transfer of service, shut-off for non-payment, high bill investigations, off-cycle reads, crossed meters, and unauthorized reconnects. Management measures and collects energy usage information through automated meter reading devices. Within BHD, Emera Maine has deployed two-way Automated Metering Infrastructure (AMI). The MPD has deployed one-way Automated Meter Reading (AMR) devices. The Meter Data Management (Itron MDM) system houses data from AMI meters. The Turtle AMR system collects AMR data. The Company’s MDM will ultimately store AMR meter readings, following MPD’s eventual transition to the new CIS (the Cayenta Utilities CU). Management is exploring August 8, 2016 Page III-11 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version options to replace the AMR devices on MPD meters, because the technology is outdated and no longer supported. Large commercial customers using more than 500 kW per month are telemetered through Itron’s MV90 system. Each meter has an assigned meter reading route and each route has an assigned revenue cycle. The Meter Reading Schedule determines read dates for each cycle, providing a three-day window to obtain and validate readings. For billing purposes, meter reads take place on a monthly basis. The CIS prints service orders nightly for distribution to Meter Service Workers in their work reporting locations. Dispatchers route any orders received during the day by radio or phone to the appropriate worker. Management does not have a mobile data system to support service order work in the field. Meter Services operation and maintenance (O&M) costs, and cost per meter service order have increased 10 percent from 2013 to 2015, as the following table shows. These costs comprise labor, materials, supplies, and office expenses, and do not include facility or fleet costs. Meter Services Costs Year O&M Cost Meters Read (monthly) % AMIRead Completed Meter Service Orders $/Order 2013 $467,684 160,278 99.6% 33,735 $13.86 2014 $503,906 160,536 99.6% 33,182 $15.19 2015 $513,571 163,151 99.6% 33,913 $15.14 2016* $217,570 163,518 99.6% 14,695 $14.81 7. Customer Billing Emera Maine bills for metered electric service and for several unmetered services, including area lights, line extensions, service establishment charges, temporary service charges, and pole charges. The billing systems also perform billing of supplier charges for all Standard Offer Provider charges and the Competitive Electricity Supplier (CES) accounts that have consolidated billing. The Emera Maine’s systems use EDI (Electronic Data Interchange) to create and communicate transaction sets of customer usage and other information to CES accounts, with pass-through billing, so they can bill customers. Management uses revenue cycle billing, assigning BHD customers to one of 24 cycles, or MPD customers to one of 16 cycles. The Billing and Payment group creates a billing cycle schedule specifying the required dates for meter read, bill extract, and bill print. The Billing and Payment group manages the meter data collection process and identifies, investigates, and resolves meter data exceptions to provide a smooth flow of data from the meter August 8, 2016 Page III-12 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version to the billing system. Completing the meter reading scrubbing and pre-calculation work, the cycle is set up for bill calculation. A nightly batch procedure reviews all accounts, calculates billing charges, and generates alerts for any accounts that may require additional review or additional information. Executing this procedure ensures that customers’ accounts contain the necessary information to render accurate bills. Four billing CSRs in BHD and one billing specialist in MPD address cycle billing exceptions. The last step in the nightly batch creates a bill export file, encrypted and sent to Kubra, the thirdparty bill print vendor. Processing at Kubra creates PDFs (Portable Document Files) for e-bill customers and printed bills for mailing. MPD prints, stuffs, and mails bills in-house, rather than relying on a third-party vendor. Billing operation and maintenance (O&M) expenses increased by four percent from 2013 to 2015, as the following chart shows. Bill Processing Costs Year O&M Cost Bills Issued $ / Bill 2013 $1,704,275 1,915,418 $0.89 2014 $1,792,637 1,906,806 $0.94 2015 $1,750,071 1,890,061 $0.93 2016* $673,557 797,707 $0.84 *Through May 2016 8. Payment and Collections a. Payment Processing Customers can mail check payments or pay in person by cash or check at 48 pay stations located within the service territory. Customers can also pay by phone, online, or through the assistance of a CSR, using a credit or debit card or check draft (ACH payment). Emera Maine’s third-party payment processor, Kubra, charges customers a convenience fee of $2.95 for credit or debit card payments. As of May 2016, Emera Maine’s lockbox (operated by FISC Solutions/Wausau Financial Systems) receives and processes mail payments representing approximately 60 percent of total customer payments received. The Company receives another 33 percent electronically (web, ACH, CheckFree, Kubra). The following charts detail payments received by channel from January through May 2016 and the percent of electronic payments received each year. August 8, 2016 Page III-13 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Since 2013, payment processing costs have increased 24 percent, while payment volumes have increased only two percent. Payment processing costs consist of third-party payment processor fees and the fees that Emera Maine pays Kubra when customers pay through the online payment portal. Emera Maine recently added Western Union as a qualified payment processor. The percentage of self-service payments (paid online) increased from 22 percent in 2013 to 33 percent in 2016. Payment Processing Costs Year O&M $ Payments % Online $/Payment 2013 $168,733 1,975,934 22% $0.09 2014 $226,575 1,998,797 26% $0.11 2015 $209,874 2,018,885 28% $0.10 2016* $88,248 33% $0.09 975,700 *Through May 2016 b. Collections The Commission’s Chapter 815 Consumer Protection Standards for Electric and Gas Transmission and Distribution Utilities address the timing and specifics of credit and collections policy and actions. Whether management employs effective credit-and-collection practices that accord with established requirements and support effective financial performance at the same time presents a significant issue. The typical 2015 residential bill averaged $33.43 for MPD customers and $52.54 for BHD customers. Customer bills become due for payment within 30 calendar days of issuance date. Failing full payment by the due date, Emera Maine assesses a late payment charge on the current month’s balance. At 90 days after the due date, the Company mails a disconnect notice to all accounts showing more than $100 past due on the current invoice. In most cases, management sends a notice 14 days before a stated disconnection. However, a three-day notice is sent to customers that have broken payment arrangements, failed to pay a deposit, or received service without applying to become a customer. The notices advise that the account will be “subject to August 8, 2016 Page III-14 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version termination” in 10 days if payment is not received. Emera Maine issued more than 200,000 disconnect notices to customers in 2015. In order to provide a reminder, management initiates an automated phone call 95 days after the due date. The call advises customers of the need to contact the Company concerning overdue balances. A disconnect order is generated 104 days after the due date. Disconnect orders expire in 10 days. Following proper notification, Credit CSRs select accounts for discontinuation of service based on the outstanding balance. Management does not disconnect service for customers agreeing to and complying with the terms of a payment arrangement to pay off arrearages. Management also does not disconnect customers experiencing medical conditions that would pose risk absent service continuation. Monday through Thursday, from April 15th to November 15th, Credit CSRs prepare daily disconnect orders for Emera’s third-party collectors, who then attempt to contact personally delinquent accountholders in order to notify them of pending disconnection. The collectors accept payment in the field and facilitate communication with CSRs, who can explain account details, accept payment by phone, and offer customers payment arrangements in lieu of disconnection. Emera Maine disconnected close to 4,200 customers for non-payment during 2015. A final bill goes to customers who have been disconnected and have not made arrangements to pay to have service reconnected within seven days and to customers wishing to discontinue service voluntarily. The “final” bill is due within 30 days. If not paid within 45 days, management turns accounts that have a greater than $15 balance over to an outside collection agency for final collections. The BHD writes-off outstanding accounts about 60 to 75 days later (105 to 120 days after disconnect, 209 to 224+ days past due). MPD’s process differs in that write off occurs at the time of debt placement with the outside collection agency (45 days after disconnect, 149 days past due). Management credits any subsequent payments received by Emera Maine or its outside agency collector back to the write-off. Management has assigned resources to initiate collections calls on delinquent commercial accounts, in order to stimulate payment without the need for a field visit. Management has not conducted fraud detection, bankruptcies, and other key activities consistently in the past, but now plans an additional resource to perform them. Management commissioned the Monticello Consulting Group to perform an assessment of credit and collection practices in the third quarter of 2015. The assessment produced recommendations to strengthen processes associated with account initiation, active account collection and account management, and inactive account management, collection and recovery. Management has begun to implement a number of recommendations, including a revised account placement strategy designed to maximize recoveries. August 8, 2016 Page III-15 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version The next chart summarizes net write-offs as a percentage of revenue in recent years. It reveals lower than average write offs in 2011 and 2015, and higher than average write offs to date in 2016. Management says that it reduced BHD field collection enforcement during 2015, due to the timing of CU go-live, which had the effect of reducing write-offs in that year. Management also stated that an issue with the new CIS after go-live delayed write-offs for some accounts from 2015 to 2016, which had the effect of increasing 2016 write-offs. Gross write-offs peaked in 2014, following what management reported as a lack of timely write-off processing in 2013. This circumstance pushed into 2014 some write-offs that would ordinarily have occurred in 2013. Adjusting for the delay produces a more consistent write-off trend over time, as the next chart demonstrates. For 2015 and 2016 so far, the average account balance at write-off of $556 represents about 10 months of delinquency, based on an average residential bill of $52. Management’s current collection timeline sends a minimum of three monthly bills with “past due” messages (90 days) before a disconnect notice is generated. MPUC rules permit notices of disconnection for August 8, 2016 Page III-16 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version delinquent accounts to be issued 30 days after the original bill date. Treating accounts sooner is better for the Company and customers. The next chart shows that Credit & Collection operation and maintenance (O&M) costs have increased 28 percent since 2013, hitting a peak in 2014. Excluding write-offs, third-party contractor fees generate 90 percent of Credit and Collection O&M expenses. Credit & Collection Costs Year O&M Cost Accounts Placed Net Write-off Cost/Action & Field Action % of Revenue 2013 $562,692 17,684 $31.82 1.29% 2014 $829,880 18,513 $44.83 1.37% 2015 $718,919 12,440 $57.79 0.92% 2016* $283,534 2,869 $98.83 2.26% *Through May 2016 (Excludes Uncollectible Costs) 9. Contact Center Operations Customers can call Emera Maine Contact Centers between the hours of 7:30 a.m. and 5:00 p.m., Monday through Friday. After hours and on weekends, emergency calls route to after-hours CSRs. Emera Maine’s IVR and web remain available at all hours. Customers call the Contact Centers for issues related to new-service connection, service disconnection, electric outage, billing, credit or collection issues and to raise general customer-relations questions. Management relies on Interactive Intelligence’s Customer Interaction Center (CIC) to provide CSR workstation phones, Integrated Voice Response (IVR) technology, and Automatic Call Distributor (ACD) to route customer calls from the public telephone network. Calls get distributed by priority, call type, availability, and agent skill. Management received between 500,000 and 600,000 calls per year in 2013 and 2014, with slightly fewer in 2015. The following chart depicts the total calls received and details the portions handled by CSRs, IVR, and the level of callers abandoning. August 8, 2016 Page III-17 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Prior to 2014, Emera Maine averaged five to eight percent abandoned calls. In 2014, that percentage rose significantly to 20 percent of calls abandoned before speaking with a CSR. The level of abandoned calls moderated somewhat thereafter, averaging 13 percent year-to-date 2016. Two large storms in 2014 drove call volumes higher, but 2015 brought no significant storms. Call volumes in 2015 increased, however, at go-live for the new CIS. Inexperience with the new customer system and inadequate staffing of the center created longer calls, longer customer wait times, repeat calls, and the highest abandonment rate in the last three years, as the next chart illustrates. Good utility practice limits abandonment rates to 5 to 10 percent of calls received, a level that Emera Maine has not achieved since 2013. August 8, 2016 Page III-18 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version CSRs have put callers on hold more and more frequently over the past three years. CSRs often put callers on hold when unsure of the answer, facing difficulties with the system, or having to calculate or process something manually. Frequent holds lengthen call handle times and often frustrate callers. Management dedicates 69 inbound phone lines to the contact centers. Callers select the appropriate option on a menu, which directs them to self-service or to a customer service August 8, 2016 Page III-19 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version representative. If there are no available CSRs, callers are held in a queue, and offered the option of leaving a voice mail. If all inbound lines are busy, callers are routed to a 54-port call announce box, where they hear what is termed a “polite disconnect” message, as follows: “You've reached Emera Maine. Due to unusually high volume, all of our phone circuits are full. If you are calling to report an outage, please try calling again in a few minutes or visit emeramaine.com to report your outage online. For all other needs, please try again at another time during normal business hours, or visit our website to pay your bill, view payment options, and for additional company information.” Emera Maine offers the following self-service options to BHD callers:  Access Account Information o Current Balance/Due Date o Last Payment Amount/Date o Next Payment Amount/Due Date o Bill history o Meter reading history  Re-direct callers to Kubra to make payments  Report an electric outage (by voice mail)  Request a call-back when power is restored. MPD callers can hear account information and report a power outage, but cannot currently pay electric bills by phone. Management plans to introduce this option to customers following the Phase II of the new CIS implementation. CSRs initiate service for new and returning customers, update customer accounts, handle customer inquiries, create and issue customer energy usage bills, receive and process customer payments, and collect delinquent customer payments. The CSRs multi-task - - answering customer calls and performing various non-phone customer accounting duties when incoming phone volumes allow. Customer inquiries primarily drive CSR workload overall, but, several CSRs work cycle billing exceptions and assist with field collection activity. Drivers for those two specialty groups include the volume of billing exceptions/investigations and accounts eligible for field activity. Management trains all CSRs to handle electric customer service and emergency calls. Electric emergencies, and customers reporting hazardous conditions, such as a wire down, get the highest priority, which includes routing the call to the first available CSR. Outage and emergency calls are handled on a 24/7 basis, while customer service calls are handled from 7:30 am to 5 pm Monday through Friday. Customers calling outside business hours hear a message advising that the office is currently closed, and are offered the opportunity to report an outage or to leave a voice mail message. Emera Maine does not have reporting in place to track the volume of voice mail messages received. CSRs returning voice mail messages approximate receiving 1,200 messages in May and June of 2016. August 8, 2016 Page III-20 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version As of January 2016, management deployed the same CSR set of scorecard metrics in both centers. Performance metrics include: availability, off-call, after-call follow-up, calls handled per hour, and call quality (as measured through side-by-side live observation or by review of recorded calls). Supervisors in each center monitor two random calls per month per CSR (newer employees might be monitored more frequently), to determine the quality of call handling and to identify opportunities to coach and praise performance. CSRs receive by e-mail the results of these evaluations, which form part of their annual performance measurement. Currently, 31 percent of calls require no agent assistance. The next chart summarizes self-service calls. Emera Maine’s IVR or the third-party phone payment vendor (Kubra) handle them. Phone based self-service has declined since 2013, hitting a low in 2015. The large storms of 2013 and 2014 increased the volume of self-service calls handled through the IVR. In 2015, management set an overall target of answering 70 percent of calls within 30 seconds; previously, a higher, 80 percent goal existed. The BHD contact center achieved its answering goal infrequently (in only seven of the past 40 months), and experienced a significant drop in answer level performance since May 2014, as the next chart illustrates. August 8, 2016 Page III-21 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Customers experienced long wait times during 2014 and 2015, and again at the start of the credit season in 2016. As the following chart shows, management has been filling open CSR positions with persons who report to the MPD contact center, consistent with its strategy to close the BHD contact center by 2019. Since April 2014, the BHD contact center has experienced a steady decline in CSRs, from 34 CSRs to 29 at go-live, which dropped to 28 in August 2015. However, management trained six of the 17 CSRs in the MPD contact center to use the new billing system, which made these six available to assist BHD customers by November 2015. August 8, 2016 Page III-22 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Emera Maine has limited capacity to handle calls during large outages and weather events. Callers can leave a message about their outage; however, if all the trunks are full, callers get referred to the Call Announce Box, which provides the “polite disconnect.” With all 54 ports on the Call Announce Box full, callers hear a busy signal. Management does not track the volume of calls referred to the Call Announce Box when all lines are busy nor has management conducted any stress testing of Contact Center telephony. An employee-led team conducted an early 2015 analysis that sought to identify potential solutions for handling high-volume calls received during storms and large outages. The team recommended proceeding with a third-party solution, invocable as needed during declared outage events. The next table summarizes Customer Contact operation and maintenance (O&M) costs, and cost per call, which have increased 18 percent, from 2013 to 2015, while call volume decreased by 10 percent. Customer Contact Costs Year O&M Cost Calls Handled Self-Service % $/Call 2013 $2,770,553 544,095 38% $5.09 2014 $2,799,319 592,605 34% $4.72 2015 $3,280,817 490,103 26% $6.69 2016* $1,205,984 209,539 31% $5.76 Note: Calls Handled include those addressed by agents or technology 10. Revenue Protection Utilities have traditionally relied on meter readers and other field employees for the identification of meter tampering and energy diversion. Emera Maine uses this approach. A August 8, 2016 Page III-23 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Security Specialist, reporting to the Supervisor of Compliance, Security & Environmental, has responsibility for the Company’s energy diversion processes which include investigation, documentation, and testimony. Emera Maine relies on bill stuffers and its website to educate customers about energy theft. Customers can report energy theft anonymously on the website or by calling the Security Specialist directly. The following chart details theft of service investigation activities by year. Theft of Service Investigations Category 2014 2015 2016 YTD Theft Hotline 2 2 4 Unauthorized Users 41 38 24 Unauthorized Use Value $9,109 $18,997 $7,277 # Theft Cases Opened 41 38 24 # Theft Cases Closed 13 31 41 Theft Cases Backlogged 0 0 0 No. of Cases Prosecuted 10 13 3 Management created the Security Specialist position in 2012 as the company and the industry experienced significant levels of copper theft. Management added a dedicated resource to develop processes to protect copper and investigate potential theft of service and current diversion cases. The Security Specialist compiles and provides case documentation to local law enforcement to facilitate investigation, court summons, and arraignment. Since starting the program, Emera Maine increased the number of cases opened, investigated and prosecuted, and dollars recovered, as the next chart summarizes. Court-ordered restitution or fines represent more than half of the money billed and recovered to-date. August 8, 2016 Page III-24 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version C. Conclusions 1. Emera Maine’s overall customer satisfaction levels fall well below panel averages, and remain unsatisfactory. (All Recommendations) The Company ranked near the bottom of the East Midsize Segment of the J.D. Power & Associates Electric Utility Residential Customer Satisfaction survey for the past three years. In 2014, Emera Maine ranked 133 of 138 in the national panel for overall customer satisfaction. 2. Escalation of customer complaint levels demonstrate a need for greater management focus. (All Recommendations) Customer complaints to the MPUC have escalated each year for the past two years. Key drivers of MPUC complaints during this time were related to security deposit requirements and payment arrangements. 3. Employee feedback surveys reveal a need for action to improve employee satisfaction and engagement. (Recommendation #1) Gathering feedback from employees comprises an important step in promoting customer service efficiency and effectiveness. Management surveys employees annually. Employee engagement across the Company generally and within the Customer Service organization specifically has declined since 2013. The next chart shows that it continues to fall further below IBM norm. Engagement levels in customer service are lower than the whole-company level. August 8, 2016 Page III-25 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Employee Engagement Survey Results Customer Service Department Attribute Engagement Index Future Vision Customer Communication Growth Survey Follow-up Managing Change Manager Effectiveness Leadership Effectiveness Empowerment Quality Recognition Safety Involvement Corporate Social Responsibility Transformation Health & Wellness Our Story/Vision % Favorable 2014 % Favorable 2015 2015 vs 2014 56% 44% 55% 47% 62% 40% 58% 63% 43% 66% 60% 49% 82% 60% 87% 31% 66% N/A 52% 45% 31% 42% 54% 34% 51% 62% 34% 60% 50% 51% 82% 47% 81% 33% 59% 42% -4% 1% -24% -5% -8% -6% -7% -1% -9% -6% -10% 2% 0% -13% -6% 2% -7% N/A Individual attribute ratings for the Customer Service organization declined in 13 of 18 survey attributes from 2014 to 2015, most remarkably in the Customer attribute which experienced a 24 percent decline. The Customer attribute was the least favorably rated attribute by the Customer Service organization in the 2015 survey, followed by Transformation. Transformation was the least favorably rated attribute by all Emera Maine employees. 4. Management has failed to adequately staff the BHD Contact Center to meet call answering service level goals consistently since 2013. (Recommendation #2) Since 2015 management has set an overall goal of answering 70 percent of calls within 30 seconds, reducing the prior goal of 80 percent. The next chart shows that the BHD Contact Center has achieved its answering goal few of the past 40 months, with a significant drop in answer level performance since May 2014. The Service level metric defines the level of contact center staffing needed to achieve the answer goal desired. A shortage of resources will result in a reduction in service level performance. Management’s failure to meet service level goals indicates inadequate staffing of the BHD contact center for this period. August 8, 2016 Page III-26 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version 5. CSR Staffing levels were inadequate at go-live in June 2015, and proved insufficient to handle the call volumes received following that date. (Recommendation #2) CSR staffing levels in the BHD contact center remained below required levels for 13 months prior to go-live and the percent of calls answered within 30 seconds dipped to 21 percent following go-live June 2015. Management documented the challenges facing the BHD contact center, including the decline in CSRs in the July 2015 CSC Phone Stats Summary. The following chart (extracted from that report) shows the decline in available BHD phone representatives during the period of 2nd quarter 2011 through 2nd quarter 2015, reaching a minimum in the 1st quarter of 2015. Comparing the available CSRs on this chart to the total rostered CSRs results a shrinkage factor of 40 to 50 percent. Shrinkage, in contact center terms, is the percentage of hours lost in the call center to non-call handling activities such as vacation, breaks, lunch, holidays, sick time, training and back office project work. *BHD August 8, 2016 Page III-27 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Based on the level of reduction in June 2015 (44 percent), management reported the need to add at least 13 more CSRs to successfully meet the goal of answering 70 percent of calls within 30 seconds. On July 10, 2015, management was forced to declare a system emergency (as defined in the collective bargaining agreement) to facilitate bringing in additional call takers in the BHD Contact Center. The system emergency continued through November 10, 2015. The following chart demonstrates the improvement in service level and the reduction in customer wait time and abandoned calls following the addition of these resources: Call Wait-Time Reductions 6. CSR Multi-tasking between producing bills and handling customer inquiries compromises call handling and billing performance. (Recommendation #2) Management has defined the role of a CSR to include answering and responding to customer inquiries, researching billing issues, researching credit and collections issues, and conducting other miscellaneous office activities. Management expects CSRs to answer calls and work “back office” duties when call volumes permit. This combination of duties limits the number of hours per day that CSRs can handle phone calls or work back office work, effectively shrinking available resources for either work group. Additionally, employees face the decision to answer the customer waiting in the phone queue or to research an account to resolve a billing exception. Such multi-tasking produces inefficiency and compromises billing integrity and service level performance. 7. Emera Maine’s meter-to-bill process is disjointed, which unduly reduces accountability. (Recommendation #2) The billing process splits between two work groups - - the Contact Centers and the Billing and Payment group. Within the Billing and Payment group, AMI Analysts pull meter readings from the MDM or other metering systems, and review them for completeness. The readings are imported into each of the two billing systems for pre-bill processing. CSRs in the Contact August 8, 2016 Page III-28 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Centers review and resolve any exceptions prohibiting billing. Following this work, Billing and Payment analysts review the bills again prior to export and print. The responsibilities for these billing duties are split between two groups with competing needs. Management asks CSRs to perform other “back office” billing-related duties as project work, when call volumes permit. This work includes processing returned checks and ACH payments, managing landlord agreements, return mail, processing deposits on final accounts, selecting accounts for field activity, applying reconnect fees, setting up collection activity for broken arrangements, calling delinquent commercial accounts, returning voice mail messages, responding to customer emails, and other seasonal transactions. Contact center supervisors assign this back office billing support work. Supervisors in the Contact Centers and Billing and Payment have limited reporting available to identify workload volumes for this “back office” project work, making it difficult to determine required staffing or identify backlog. 8. Offering agent-assisted credit/debit card processing in the Contact Center increases PCI compliance and employee fraud risks. (Recommendation #3) PCI DSS requirement 3.3 describes two means for risk mitigation: (a) requiring segmentation of call-center operations to minimize the number of agents with access to customer payment card data, and (b) suggesting the consideration of solutions under which the agent need not enter card information into the system. Management has not segmented contact center operations. Emera Maine does offer customers the option of self-service credit and debit card payments through the IVR, however, customers can also pay by card with the assistance of a representative. All calls get recorded, for quality monitoring purposes. These calls include customer payment calls (CSRassisted). PCI security guidelines seek to avoid recording/storing card validation codes in all cases and strongly discourage storing card numbers and expiration dates. Emera Maine practices do not conform to these PCI security guidelines. Moreover, CSR-assisted credit/debit card payments are the costliest to process and the riskiest in terms of employee fraud. PCI DSS requirements and the need to encourage customers to use more cost-effective payment channels has led the utility industry in the direction of exclusive use of self-service credit/debit card payment processing, through the web and IVR. As a Level 3 Merchant (processing 20,000 to 1 million card payments annually), Emera Maine must perform an annual self-assessment and quarterly PCI DSS scans of its data network. Management processes payments through a third-party, but this arrangement does not exclude Emera Maine from PCI DSS compliance. 9. CSRs do not consistently authenticate callers. (Recommendation #5) CSRs should verify that the caller is the customer of record, or authorized by the customer of record, prior to providing account information or assisting the customer with changes to the account or services. CSRs in the MPD and BHD are not consistently authenticating callers before they respond to requests or inquiries. August 8, 2016 Page III-29 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version 10. Emera Maine’s Call Quality Monitoring Process Lacks Routine Calibration. (Recommendation #5) Both Contact Centers now use the same call quality evaluation form, but management has yet to conduct regular call quality calibration sessions to align supervisor expectations. Call calibration proves critical in ensuring that supervisors measure quality consistently thereby building credibility among CSRs for the monitoring process. This process has particular importance for new call-quality programs and following the introduction of a new evaluation form. Supervisors have the opportunity separately and jointly to score a set of calls and discuss the basis for their ratings. When supervisors work through a number of different types of calls together, they reduce variances in scoring, and calibrate supervisors’ measurements. Calibration among supervisors and calibration conducted on a regular basis comprise the top two key drivers of quality monitoring program credibility. 11. Meter Reading performance appears adequate, as evidenced by a high read rate and a low percentage of estimated bills. Meter Reading read rate has been good, as would be expected, with nearly 100 percent of meters read through automation. Emera Maine reads approximately 0.4 percent of meters manually each month. The percentages of estimated electric bills have remained low since the transition. Resulting meter reading performance ranks well above goal. 12. Procedures for addressing theft of service and unaccounted for usage are sufficient. Management has formalized procedures and added a resource to investigate meter tampering, theft of service or other unaccounted for usage. One employee has been assigned the responsibility for manning efforts to optimize revenue assurance. Policies and procedures exist to guide efforts to investigate suspected theft of service, meter tampering, or other unaccounted for usage. Since starting the program, Emera Maine increased the number of cases opened, investigated and prosecuted, and dollars recovered. 13. Billing performance has not returned to target levels. (Recommendation #2) The BHD has struggled with billing issues following go-live of the new CIS. Bill error performance fell below target in June 2015 and has been problematic since, as management continues to address CIS-related issues. Most utilities implementing new customer information systems experience billing issues post-implementation. However, as compared to goal, Emera Maine’s billing errors have spiked since go-live, since several of the errors have impacted a significant number of customer accounts. Chapter 815 requires Maine utilities to notify the Consumer Assistance Division (CAD) of billing errors that affect more than 10 customers. The Chapter also requires that a utility notify customers promptly in writing of a billing error after it discovers or is notified of the error. The Bill Error Customer Impact chart, depicts the number of customers notified of billing errors since 2013. August 8, 2016 Page III-30 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version 14. Emera Maine does not have a high-volume call overflow service to ensure that customers can communicate effectively with the company during a large outage or storm. (Recommendation #4) Emera Maine has a limited capacity to handle calls during large outages and weather events. While callers can leave a message about their outage, if all the trunks are full, callers will be referred to the Call Announce Box, which provides a “polite disconnect”. When the 54 ports on the Call Announce Box are full, callers will hear a busy signal. Emera Maine does not track the volume of calls referred to the Call Announce Box when all lines are busy nor has the Company conducted any stress testing of the Contact Center telephony. During storms at the end of 2013 and in 2014, Emera Maine experienced high levels of abandoned calls as customers struggled to get through to the company to report outages or obtain restoration status information. An employee-led team conducted an analysis in early 2015 to identify potential solutions for handling high-volume calls during storms and large outages. The team recommended proceeding with a third-party solution that can be invoked as needed during declared outage events. Management is currently evaluating options for moving forward. 15. The Contact Center specific emergency/storm plan is out of date, and in need of update. (Recommendation #6) Management has underway an update of the Emera Maine System Emergency Operations Plan in order to reflect a scalable incident command approach. Management released an updated version of the Roles and Responsibilities which designate Customer Service and Communications roles during a system emergency. However, Customer Service Center tactics and response during a system emergency detailed in the Emera (Bangor Hydro Electric Company) System Emergency Operations Plan are also outdated and in need of review and update. 16. Management has several application-level Business Continuity Plans that address Customer Service operations, systems, and telephony; many of these plans require update and testing. (Recommendation #7) Emera Maine prepares application-level Business Continuity Plans for key customer service systems and processes. Only two of these plans have undergone updates within the past two August 8, 2016 Page III-31 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version years. Others have not been updated to reflect the change in the CIS from Banner to the new CU system. Additionally, management has not conducted testing of these plans for two or more years. Application-level plans include:  Cayenta CIS Disaster Recovery Plan  Contact center Telephony Disaster Recovery Plan  Advanced Metering Infrastructure (AMI) Business Continuity Plan  Meter Data Management System (MDMS) Business Continuity Plan  Billing Processing (Kubra) Business Continuity Plan  Payment Processing (FISC Solutions) Business Continuity Plan. The Contact Center Telephony and Cayenta CIS Disaster Recovery Plans were created in June 2016 and are not fully developed. Neither of these plans discusses business continuity for the customer service operation in the event of a CIS or contact center equipment outage. Emera Maine did not provide a plan for the AS400 CIS; however, a three-page document presents CIS System Disaster Recovery Results from a test conducted on December 17 and 18, 2014. Emera Maine’s AMI Business Continuity Plan, for instance, provides the steps needed to reassign resources to manual meter reading in the event of an AMI outage lasting longer than one full billing cycle. Because management no longer maintains a full complement of handheld devices, the majority of readings would be collected on paper logs, requiring manual loading of premise locations in GPS devices to determine walking routes. Management has not updated this plan since 2014 and has not tested the plan since 2007. Business Continuity Plans should be tested and updated annually. 17. Emera Maine’s write-off process has been inconsistent and untimely. (Recommendation #8) Emera Maine suspended all field collections activities company-wide during the week of go-live in June 2015. Management resumed field collection in July for commercial accounts, but did not resume collections on residential accounts until the last week of July and then only on a reduced level compared to prior years. As a result, past due receivables grew. Suspension of collection action is typical following the implementation of a new Customer Information System within the utility industry. During post-go-live, the focus is on producing accurate and timely bills and being responsive to customer inquiries and concerns. Collection treatment usually resumes, as did Emera Maine’s activities, within a few months. As a result, the total number of field orders worked in 2015 is substantially less than the five prior years, as seen in this chart below. The write-off process continued through this period. August 8, 2016 Page III-32 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version The BHD credit group has not consistently worked the write-off process over the past five years; in each year a portion of the write-offs should have been written-off in the prior year. This inconsistency creates an unrepresentative view of write-off activity. A review of net write-offs as a percentage of revenue from 2009 to 2016 year-to-date reveals lower than average write offs in 2011 and 2015, and a much higher rate in year-to-date 2016. A glitch in CU resulted in some BHD 2015 accounts being improperly aged which delayed write-off until 2016. Another CU flaw prohibited accounts closed with open payment arrangements to be picked up by the writeoff process. The Katahdin Project resolved both of these CU issues during the post go-live cleanup effort. Management is currently evaluating the best way to synchronize the write-off processes between MPD and BHD, and is now analyzing the impact to 2016-2017 write-offs if the two processes August 8, 2016 Page III-33 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version were aligned at once or phased-in over a period of time. The Company will prepare a transition plan by the end of 2016. 18. Management has opportunities to shorten active collections time. (Recommendation #9) For 2015 and 2016 year-to-date, the average account balance at write-off represents about 10 months of delinquency. The current collection timeline serves to delay action on the account. Treating accounts sooner is better for the Company and customers. 19. The customer-facing website lacks key account information, and should provide additional self-service to customers. (Recommendation #10) Management had intended the new CIS to include a Customer Self-Service (CSS) web portal linked with CU. This capability would provide billing and payment history, usage graphing, allow sign up for budget billing, permit customers to update account information, request service to be turned on or off, and support other features. During May of 2014, management became concerned that introduction of a new customer-facing website at go-live might increase call volumes and lengthen call handle times, making it more challenging to serve customers. Additionally, many of the tasks to develop, test, and produce training material for the website were not completed. Management deferred work on the CSS so that developers and testers could focus on other aspects of the CU implementation. This effort remains on-hold today. As a result, the website today does not link to the CU system. Rather, billing and payment services are provided by Kubra, as it prepares bills for print and electronic distribution. Accordingly, the Kubra system does not show payments made through other channels, such as mail, pay stations, other electronic banking channels. Additionally, the bill balance is only as upto-date as the billing extract is updated and provided to Kubra (no real-time or nightly updates). Customers may thus become confused when they log-in and do not see a payment properly credited. Additionally, when customers want to set up recurring auto-payments through Emera Maine’s website, they must opt out of receiving the paper bill, something that many customers still want to receive when they are on auto-pay. Until very recently, customers reporting outages on the website used an electronic form that was emailed to employees for manual entry into the PowerOn system. Management has now automated the update of this information directly to the PowerOn outage system, eliminating manual entry. MPD customers cannot pay bills by credit or debit card through Emera Maine’s web payment portal or the IVR pay-by-phone. MPD meters service through older AMR technology that has not been integrated with the MDM system. As a result, this data is not available to the PowerSmart system, which Emera Maine uses to share detailed usage data with customers on the website. Emera Maine’s website is device-responsive on some web pages but not on others, making it more challenging to access the website from a mobile phone or tablet. Currently, management does not stress test website user functionality other than during the initial August 8, 2016 Page III-34 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version build of a server. Emera Maine does have enterprise monitoring and capacity management systems in place, through service agreements with outside vendors. These systems provide alerts when performance degrades so that Emera Maine’s IT resources can take action as needed to address the situation. 20. A significant number of capabilities not present in the go-live version of the new CIS have been resolved by “Project Katahdin.” A number of items in the original CU scope were not completed at go-live resulting in workarounds and missing functionality which impacted operations and the customer experience following go-live. However, Emera Maine’s follow-on Project Katahdin has resolved many of these issues. Management made the decision to go-live with a less than perfect CIS. Eighteen months later than planned, the new system was put into production for the BHD. However, many of the features in the original scope of work were, for one reason or another, not present at golive. In some cases, the need was no longer there. For others, the scope was deferred to Phase II because of complexity, a lack of time or resources, or the realization that it could be better deployed post go-live. Deferred scope items included:  Group Billing  Customer Self-Service Web Portal  Mobile Service Orders  Performance Dashboards  Batch Processing  Supplier Hourly Pricing. Delayed scope aside, the Company was also faced with a long list of issues not resolved prior to go-live and still needing resolution. Management has had a significant number of issues to resolve while using the system to bill and support customers. In October, Emera Maine embarked upon a follow-on project to resolve incidents and issues arising with and after go-live. Project Katahdin was launched, with the help of an external consultant, and aimed to lower the count of incidents and focusing on the highest impact fixes. The team quickly surveyed missing scope, incidents, and defects with a focus on regulatory, financial, customer-facing, and efficiency-gains. The team started with 369 issues on October 1, 2015. Phase II issues and system enhancements were excluded (144 items) while other incidents were added (181). After six months of work, the Katahdin Project Team closed 342 incidents which included 43 production incidents. At the end of the project, 64 projects remained, 43 of which had been issued to the Cayenta eSupport team for resolution. The Katahdin was successful, primarily because it used smaller teams and apportioned the work into short-sprint projects designed to achieve quick wins and build confidence. Additionally, the team was allowed and encouraged to work directly with the business to resolve complex issues. Teamwork was emphasized as was a work/life balance, and successes were celebrated to build team morale. The new external project manager (vendor) brought a clear strategy and approach for completing the work that instilled trust among team members. Most importantly, an executive steering committee was engaged and provided clear direction for the team. August 8, 2016 Page III-35 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version The following functionality was installed as a result of Project Katahdin:  Fixed a flaw that prohibited accounts closed with open payment arrangements to be picked up by the write-off process  Reduced unapplied credits, allowing the matching of certain unapplied credits with the appropriate accounts and ensuring that the aging balances reflect these applied credits  Accomplished more than 40 EDI fixes to improve the quality of EDI transactions sent to marketers  Corrected several customer letters, sent by Kubra, to communicate Commission-required information including the winter warning letters, seasonal connects, and Lifelight  Enabled enrollment of customers into the Low Income Assistance Program (LIAP)  Built a new Finance Portal to ease reconciliation between CU and Oracle General Ledger  Addressed a GIS logging transaction to keep the systems up to date and current regarding meter changes  Created a work flow popup for RPSD with alerts/confirmations of work flow steps in the new business process to provide status of a request  Reduced runtime of PowerOn interface from 20 hours to five (daily operation to monitor, update data so that dispatchers have data for system operations, power outages, and customer details)  Enabled cancellation and setting of payment arrangements on certain accounts that had payment arrangements that could not be cancelled  Created a program to compare invoice from CU and the number sent to Kubra to ensure that missing bill prints can be identified and acted upon  Developed an automated process to transfer refund payment files back to BoA and pick up the daily reconciliation files to save time and eliminate the risk of pulling files manually  Created ability to process return checks and fees for the applicable reason  Allowed all work orders to show a meter serial number to improve field efficiency and validate that work is completed on the correct meter  Eliminated a step when resolving a meter exchange to save time for the billing group. The Katahdin Project created a CIS communications plan to guide communications and to build confidence in the quality and accuracy of CU within the user community. 21. Management has a plan to transition the organization and prepare for deployment of CU to support the MPD. Management announced in 2011 and again in 2015 the intention to close the BHD contact center by 2019. Since late 2015, open positions in the BHD have been filled in the MPD. Ultimately, management intends to close the BHD Contact Center (through attrition) by 2019. Until that time, management is considering options to facilitate a smooth transition. These options include the potential for remaining BHD CSRs to work remotely, bid into other positions within the Customer Service organization and company, or work on improvement projects that will be pursued from the two external assessments as well as this audit. The Customer Experience organization will also require additional staffing to support the implementation of CU within the August 8, 2016 Page III-36 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version MPD, especially as the system is tested and deployed. Over the next two years, management will continue to staff the MPD Contact Center to ultimately handle all incoming calls. D. Recommendations 1. Create and implement a focused plan to improve customer service working environments, focusing on higher retention and employee engagement. (Conclusion #3) CSRs provide a direct point of contact for customers about their utility service. Because issues related to utility service can be complex topics for customers, it is imperative to have skilled agents. Recognizing it takes considerable time to learn the extensive subject matter required of an agent, the recruitment and retention of qualified agents for this important front-line position is a high priority.  Enhance retention of employees by further defining career progression paths for CSRs and providing additional training opportunities  Continue to fund on-going reward and recognition activities for staff  Deliver coaching training for contact center supervisors and management staff  Fully commit to a call quality monitoring program to identify employee development opportunities and encourage more consistent call handling  Formalize a refresher training program to further develop call-handling skills  Pursue plans to facilitate a smooth transition to one contact center, providing options for the remaining BHD employees to continue to support the customer service organization or other Emera Maine functions. 2. Properly staff the Customer Contact Centers and streamline Billing, and Credit functions to eliminate multi-tasking and improve service level response. (Conclusions #4, 5, 6, 7 and 13) Management does not currently employ sufficient staffing to meet service level objectives. Average handle times are longer with the new billing system, until CSRs become well-versed and remaining issues resolved. Management needs to dedicate resources to resolve billing issues and exceptions and credit and collections activities, so they do not have to choose between answering a customer call and correcting a customer’s bill. Management should also provide scheduled off-call time for CSRS to work back office project work, during lower call volume days or times of the day. Management should also put work tracking and reporting in place to provide visibility into the work that needs to be accomplished and to match resources to workload. This includes taking advantage of call forecasting tools to predict the level of resources needed to answer calls to meet service level goals. Off-call project work should also be tracked and forecasted to determine required back office staffing and to identify work that is overdue or at risk of becoming overdue. Management should also review the billing process and group resources completing billing tasks together within the same organization to bring a focus on the meter to cash process and improve accountability. August 8, 2016 Page III-37 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version 3. Cease phone recordings of credit/debit card payments calls and explore options to further reduce the risk associated with handling credit and debit card payments. (Conclusion #8) Emera Maine’s recordings of customer calls store card member data without encrypting it. Management should immediately cease phone recordings of all credit/debit card payment calls. Management also needs to examine and adopt other strategies to further reduce the risk associated with the handling of credit and debit card payments. If management continues to process card payments through Kubra’s online tool, it should review and take actions that accord with its responsibilities for remaining compliant with data security standards. 4. Improve the process to measure the quality of service provided to customers. (Conclusions #9 and 10) Corporate customer service decision-making and execution must include a focus on quality; management must consider the customer needs before, during and after each contact to ensure a high level of quality service. Call quality monitoring refers to the process of listening to or observing an agent’s phone conversations or other multi-media contacts with customers. Quality monitoring can comprise one of the most effective methods for improving the level of service provided to customers. The process can enhance overall contact center performance, reduce customer callbacks, focus training efforts, identify system and process improvement opportunities, and facilitate employee development. Both Contact Centers now use the same call quality evaluation forms, but management has yet to conduct regular call quality calibration sessions to align supervisor expectations of quality. Common failings of call quality programs include: poorly designed evaluation criteria, lack of buy-in, insufficient resources or time, untimely or ineffective feedback, inadequate training for coaches and supervisors, inconsistent evaluation results, lack of support from management, and inadequate measurement of the factors that are important to customers. Management should review and revise its call quality processes to avoid common pitfalls and strengthen results:  Include components that monitor compliance with MPUC chapter rules in the quality evaluation criteria (significantly weighted) as well as properly authenticate callers.  Monitor all customer contact—inbound and outbound calls, written correspondence, email, chat, and social media posts.  Conduct regular calibration sessions to build consistency in scoring.  Commit resources to adequately monitor, evaluate, and discuss results. Effective call monitoring requires commitment of resources; supervisors should have the time to monitor and coach employees, and employees should have time off the phones for coaching and development.  Implement coaching training to ensure that supervisors, trainers and managers are equipped to provide constructive coaching feedback and developmental guidance.  Develop and evaluate coaching performance (observe and coach). August 8, 2016 Page III-38 The Liberty Consulting Group Public Utilities Commission State of Maine  Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Educate employees on the monitoring processes, especially how calibration sessions develop consistency and hold monitors accountable for the evaluations they render; the measures and the measurement process must be meaningful to employees so they are encouraged to change their behaviors. 5. Explore options for increasing the capacity of inbound communications channels to better support customers during a large outage or storm. (Conclusion #14) Management has only limited capacity to handle calls during large outages and weather events. Callers can leave a message about their outages, but if all the trunks are full, callers receive a “polite disconnect”. When the 54 ports on the Call Announce Box are full, callers will hear a busy signal. Neither of these options provides a good experience for customers. An employee-led team conducted analysis and provided recommendations to improve highvolume call handling. Management is currently evaluating these recommendations. Increased connectivity and smart phone popularity have increased customer expectations for services and communication. Emera Maine’s deployment of smart meters provides the potential to communicate more proactively with customers. Many utilities are redesigning communication options to leverage these technologies and offer customers the ability to designate preferred communications channels by service. Management should explore options to supplement or expand existing communications channels to improve customer communication during a large outage or storm. Possible options include contracting with a third-party to provide high volume call overflow, adding 2-way SMS text notifications, offering a more robust website to offload call volumes, mobile phone apps, and expanding self-service phone options to provide individualized ETRs to callers. Until options are expanded, management should review existing communications channels to ensure that these channels will operate effectively under increased load. 6. Update the Storm Customer Response Plan to make it reflective of the desired Customer Experience. (Conclusion #15) Storms present unique challenges for utility customer service. Many customers can simultaneously lose power, causing a flood of calls to the utility. The bigger the storm in terms of customers affected, the higher the number of customers trying to contact the company. Management is updating its System Emergency Operations Plan. The Contact Center plays a key customer communications role during a large outage or storm. This role should be well-designed and should be tested through practices, so that the customer service storm response can be delivered efficiently and effectively. Management should update the Customer Experience Emergency Response & Storm Plan ahead of the coming winter. An effective Customer Experience Emergency Response & Storm Plan includes pre-storm planning checklists as well as detailed descriptions of roles and responsibilities to guide personnel during large power outages or other emergencies. The plan should also designate a August 8, 2016 Page III-39 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version Customer Experience Emergency organization and detail levels of supervision, lines of authority, and channels of communication. To be adequately prepared for the high volume of calls into a contact center during a large outage, utilities should have adequate supply of experienced agents on hand to respond. To assist with the need to ramp up staffing beyond normal staffing levels, customer service organizations should have a call-center resource plan that it activates during major storms or large outage events. Integrated with this plan should be a staffing model that will provide guidelines for adding resources, based on the predicted severity of the event, projected call volumes, the timing, and expected duration. Storms arriving at night or over a weekend are particularly challenging to resource. In certain situations, when weather makes travel difficult, a pre-storm staging strategy for contact center agents becomes prudent. Customer Experience should also establish director-level presence in the Emergency Operations Center (EOC). This position should participate in conference calls, work with Corporate Communications team members on customer messaging and outbound campaigns, and help communicate restoration status information back to Customer Experience Communications Leads to create talking points for CSRs and second-role employees answering calls. 7. Develop Business Continuity Plans and a unified business continuity plan for Customer Contact Center systems and technologies, and develop and execute plans for regular testing. (Conclusion #16) Management should combine the various disaster recovery procedures at the application level for Customer Experience systems and technologies into a unified plan that can be easily understood and accessed by key support personnel. Additionally, the Customer Experience organization should develop business continuity plans to direct personnel in the event of an interruption or stoppage of operations. Business continuity plans should address various potential scenarios that could impact the workforce and include steps to mitigate impacts to employees, customers, and other stakeholders. Plans for testing these plans should be developed and the plans themselves should be exercised annually. 8. Take measures to standardize and stabilize the write-off process. (Conclusion #17) Management has observed that the BHD credit group has not consistently worked the write-off process over the past five years. The BHD and MPD have two different write-off processes with different timings. Management is currently evaluating the best way to synchronize the write-off processes between MPD and BHD, anticipating a transition plan by the end of 2016. Management should take measures to standardize and stabilize this process so that write-offs are processed in a timely manner and on the same schedule. 9. Pursue options to act sooner on delinquent active accounts. (Conclusion #18) Management should explore options to act sooner on active delinquent accounts, to move closer to what is allowed by the MPUC. August 8, 2016 Page III-40 The Liberty Consulting Group Public Utilities Commission State of Maine Customer Service Audit of Emera Maine Docket 2015-00360 Final Report-Public Version 10. Review and Enhance Self-Service Options to Improve the Customer Experience. (Conclusion #19) CSS (Customer Self Service) was deferred to post go-live so that developers and testers could focus on other aspects of the CU implementation. This effort is still on-hold today and Emera Maine continues to offer the website that was in place prior to the CU implementation. Management should enhance the website to provide additional self-service options and to improve the customer experience. The customer account portal should be fully integrated with CU to provide a complete picture of energy usage, billing and payment history, current services, customer notification preferences, outage status and estimated time of restoration. Management should also evaluate current IVR self-service options to ensure they provides the experience customers expect. The website should also be reviewed to ensure ease of navigation, readability, and mobile compatibility. The Company should review the reasons that customers are leaving voice mail messages and consider expanding self-service options to accommodate more calls after hours. It should also discontinue the use of voice mail; this practice is not recommended for an inbound contact center. August 8, 2016 Page III-41 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version Chapter Four Table of Contents IV. Implementation of the New Customer Information System ................................................ IV-1 A. Background .................................................................................................................... IV-1 B. Findings.......................................................................................................................... IV-1 1. Elements of Effective CIS Implementation Management ......................................... IV-1 2. Management’s Business Case for the New CIS ........................................................ IV-3 3. CU-CIS Governance and Project Management ......................................................... IV-3 4. Resource Management .............................................................................................. IV-8 5. Schedule Management ............................................................................................ IV-10 6. Contract Management ............................................................................................. IV-11 7. Scope Change/Order Management .......................................................................... IV-14 8. Project Phases .......................................................................................................... IV-15 9. Cost Management .................................................................................................... IV-16 10. Project Quality Assurance ....................................................................................... IV-16 11. Risk Management .................................................................................................... IV-18 12. Post Go-Live............................................................................................................ IV-18 C. Conclusions .................................................................................................................. IV-20 D. Summary of Management’s Performance in CU-CIS Project Management ............... IV-24 August 8, 2016 Page IV-i The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version IV. Implementation of the New Customer Information System A. Background Emera Maine began in 1995 to use the Banner CIS, a Customer Information System (CIS), supplied by Ventyx, and most recently purchased by Hansen technologies. Management upgraded the Banner CIS in 1999, in order to address Maine’s restructured marketplace and to address Y2K issues. Management continued to make changes to meet regulatory needs and to extend system life. In 2010, management began a process for selecting a consultant to assist in evaluating and selecting a new CIS solution. Management observed during our fieldwork that circumstances put the legacy Banner CIS at risk of failure from which it could not effectively recover. Management selected AAC Utility Partners (AAC) to provide the CIS-selection assistance. An accounting and systems consulting firm, AAC’s services included work with clients and their software providers to ensure optimal system configuration. Following a process under which management, supported by AAC selected from a number of alternatives, the board of directors of Bangor Hydro in 2011 approved the recommendation to implement a system provided by Cayenta Utilities (Cayenta) and to retain AAC for support through the development and implementation process. Cayenta, a division of N. Harris Computer Corporation, has supplied CIS solutions for many years. The parties finalized contracts and Statements of Work (SOW) for the Cayenta CIS (CU-CIS) and the AAC work in the third quarter of 2011. The initial work scope included only Bangor Hydro (BHD), or the South Operating Region (SOR). That initial scope excluded Maine Public Service (MPD), or the North Operating Region (NOR), which operated a separate CIS through separate customer service resources. Shortly after work initiation, management brought the MPD CIS into the project, but later dropped it, as the complexities of dealing with BHD alone became evident. The CU-CIS work would eventually come to include two phases - - Phase 1 involving the BHD and Phase 2, the MPD. Work on the latter was suspended in February 2014 until after the “golive” date of the CU-CIS for the BHD. The term “go-live” refers to the date from which a new system becomes fully operative. As we explain later, difficulties in reaching Phase 1 go-live also led to the exclusion of a number of capabilities planned to exist at that time, with work on them held to after the Phase 1 go-live date. B. Findings We sought to determine how well management planned and managed Phase 1 through what proved to be a June 2015 Phase 1 go-live, at which time originally budgeted costs of about $19 million had grown to about $31 million. We focused on efforts to manage project costs, schedule, and to deliver expected capabilities and functionalities effectively. 1. Elements of Effective CIS Implementation Management Liberty organized this study area’s CIS review into eleven areas, which we consider important in effectively planning and managing a project with the characteristics of the CU-CIS Phase 1 through go-live: August 8, 2016 Page IV-1 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version 1. Business Case 2. Governance/Project Management 3. Resource Management 4. Contract Management 5. Scope/Change Order Management 6. Schedule/Timeline Management 7. Project Phases 8. Cost Management 9. Project Quality Management 10. Risk Management 11. Post Go-Live Experience Well-managed CIS implementations center around a customer-service delivery vision that includes clearly defined objectives and a full understanding of how the CIS solution will support that vision. The initial phase includes selecting, under a well-structured and defined set of methods, the vendor who will provide the software solution and the professional services associated with doing so. Traditionally, such work occurs under a scope defined sufficiently to allow for a finalized fixed price for the services required. Working with the vendor, the owner must also establish a firm and final solution design that includes clear and comprehensive descriptions of business processes, pre- and post-implementation roles and organizations, and identification of associated business changes. These factors provide a baseline for development of the definition and design of the system’s technical components and functionality. Implementing and testing the solution design includes business process assessment and reengineering, conversion of existing data for successful processing in the new system, hardware and software configurations, go-live acceptance criteria, pre-go live testing to ensure satisfaction of those criteria, training of system users, and post go-live transition plans. Late-stage preparation for go-live includes assessment of the system and its user organizations and resources, user acceptance testing, a “Go/No-Go” decision to go live, migration to production and end user training. The focus of post-go live activities involves monitoring and resolving any known issues deferred until after go live and any further issues identified post go-live, in order to transition into ongoing support mode. Effective CIS implementation depends on quantitative objectives to track performance in meeting goals for schedule, cost and quality. Additionally, management should monitor performance and progress on achieving the goals and assess whether the project has the required resources necessary to achieve the goals. The results of CIS implementations over the last decade have proven mixed, reflecting their complexity and the novelty of the issues they bring for utilities - - particularly smaller ones. A 2013 survey of 21 utilities seeking their perception of recent CIS replacement projects produced the views about project success depicted in the next chart. August 8, 2016 Page IV-2 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version 2. Management’s Business Case for the New CIS The business case documents the justification for proceeding with a CIS project. It explains the dimension of the business problem and the needs created, it assesses the tangible and intangible benefits to be gained, it gauges the potential impacts of the project on the organization, and it lays out the approach and methods for conducting the project. Management completed an extensive CIS Assessment and Recommendation process before making a commitment to the CU-CIS. This assessment included gathering of CIS background information, identification of issues and constraints and elements of resource planning. The process incorporated decision analysis, it examined selection of a preferred alternative supported by analysis and it produced a recommended solution for an established CIS Executive Steering Committee (ESC), which approved that solution June 2009. The recommendation package followed the standardized approach for seeking approvals required from the Emera Maine board of directors. 3. CU-CIS Governance and Project Management Project management used the work of the Project Management Institute (PMI) to guide development of its approach to managing the CU-CIS development and implementation. In existence for a period approaching fifty years, the institute involves some three million project management professionals working across the world, working to “mature” the profession through measures that include standards, certifications, resources, tools, academic research, and publications. Management relied on the respected PMI publication titled The Guide to the Project Management Book of Knowledge (PMBOK Guide) in developing its project management methods. The standards incorporated in the PMBOK Guide began in 1987 as an attempt to standardize the information and practices of project management generally accepted as good practice by the community of project managers. a. Governance Project governance comprises a project’s strategic management and governance functions and activities. Governance includes organizations and measures that cover oversight committees, steering committees, technical committees, project status reports, and required approvals. The company’s ESC consisted of all members of the senior management team and other stakeholders, including representation from MPD. The committee received project status reports, provided project guidance, and provided resources, and input to the project as needed. The ESC did not approve change requests or have other decision-making responsibility. Internal Audit August 8, 2016 Page IV-3 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version participated in an advisory capacity. The key objective of the Internal Audit involvement consisted of participation in the identification of risks, and in ensuring effective addressing of identified risks. Internal Audit did not publish reports or recommendations, but they acted as observers at ESC meetings. The ESC members, all of whom had major roles apart from the CU-CIS project worked at different offices throughout the state. The ESC did not experience full attendance at any meeting throughout the course of the project. From 2012 to 2013 the ESC had 11 committee members, with an additional member added in 2014. The next chart summaries attendance through go-live date. ESC Meeting Attendance The group exercising the functions of the CU-CIS ESC should ensure appropriate engagement and management of key project service providers, such as Cayenta and AAC. Our interviews and document reviews did not disclose a substantial ESC role in providing project guidance, participating in vendor selection and contracting contract processes, or in ensuring effective management of key service providers. The AAC and Cayenta contracts came into being before the project started. Their SOWs documented the services required, accountabilities for performing them, definitions of key deliverables, and delivery dates. b. Project Management The principal of “unity of command” comprises a best practice for project management. It means that each individual resource (employee, vendor, or contractor) should receive direction from one manager and remain answerable to that manager. A lack of unity that leads to multiple sources of assigning tasks and responsibilities inevitably tends to produce confusion and conflicts, which have consequence for cost, schedule, and quality. A project can operate under the direction of more than one “project manager.” A common approach on projects having distinct business and technical aspects (such as the CU-CIS project) can work under an organization that divides responsibilities for the two aspects among two project managers. This approach requires clear roles and responsibilities that do not overlap and it also requires a resource above them sufficiently engaged in project details to resolve potential confusion or conflict, and to ensure a vision that recognizes the need to harmonize their efforts. Sometimes dialogue will support this harmonization, but on complex projects like this one, timely “command” decisions are also inevitable. The CU-CIS project had actually had three project managers (from Cayenta, AAC, August 8, 2016 Page IV-4 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version and Emera Maine), not one or even two. Above them as a project sponsor who, while an authoritative executive, also had sufficient other responsibilities to prevent deep engagement in project details on a real-time basis. The Project Sponsor had the responsibility to provide high-level oversight of the project, direct the company work of the Emera Maine Project Manager, and meet monthly with the AAC Project Quality Audit Consultant (PQAC), responsible for analyzing project criteria each month to assess progress and identify concerns. The Project Sponsor, Emera Maine’s VP, Transmission and Distribution Operations, had at the same time operational responsibility for the utility’s Transmission and Distribution (T&D) Operations, Engineering, Asset Management, Resource Planning and Scheduling, Customer Service, and Information Technology. The Project Sponsor’s role on the project proved much than expected as work unfolded. The Project Sponsor served as the single point of contact between the ESC and the three Project Managers. The initial roles and responsibilities of the company’s project management team were documented in December 2011. The SOWs for Cayenta and AAC served as the documentation for their roles and responsibilities. Each of the three project managers had responsibility for weekly and monthly status reports, weekly team meetings and the monthly ESC presentations. Each project manager had various responsibilities (some overlapping), regarding risk, project schedule, deliverable acceptance, and direction of team members. Interviews consistently indicated the project managers sought consensus before making project decisions. That approach eventually proved a source of delay in recognizing and responding to performance issues that arose with increasing frequency and significance. This initial organizational chart showed all EM team members reporting to the EM project manager. Initial CU-CIS Project Organization The project maintained a scheduled go-live date of December 2013 well into the year. The project added a Senior Project Manager to the team in 2013 and a Technical Project Manager in 2014, as management continued to extend the go-live scheduled date. Management added the Senior Project Manager to provide oversight to the project, and to strategically examine the activities underway and the problems and delay being experienced, in order to identify trends and issues meriting attention and solution. The 2014 hire of a Technical Project Manager having August 8, 2016 Page IV-5 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version experience with large system-related projects provided a single source for technical project management, in accord with a model we have seen in other CIS implementations. These additions came late, at dates approaching and after the date by which the CU-CIS was scheduled to be operational. Moreover, their addition to the project organization shows further layering and complexity, producing a five-headed “PMO” (Project Management Organization) and showing the six different project teams reporting to this collective organization. It also produced two supra-project reports to the project sponsor - - one each from Cayenta and AAC, each of which also have a project manager within the PMO and each of which had resources playing key roles on the multiple project teams. The organizational chart shows no direct accountability from the project managers to individual team members. The last update to roles and responsibilities is as shown in a November 2014 organization chart, reproduced below. The post-go-live organizational chart has maintained this same project management structure. November 2014 CIS Project Organization c. Status Reporting Status reporting informs key project stakeholders of the critical aspects of project health, including schedule, scope and cost, providing a basis for confirming that status is in accord with plans, or laying a foundation for timely action to address needed changes. Sound status reporting prevents surprises to project sponsors and stakeholders, by reporting status fully and timely and by identifying variances, trends, and emergent circumstances that may call for action. Formal status reporting needs accompany project steering committee meetings as well, but its importance for project management is even more critical and time sensitive. The information provided should be clear, concise, and actionable. It should contain the details necessary to allow management to act quickly and decisively and it should also allow the steering committee, given its role and level of management, the information to make informed decisions and maintain August 8, 2016 Page IV-6 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version oversight of the project. Important information should not be glossed over, buried in a mass of non-critical data, or presented in forms that blur its significance. We did not find status reporting to be clear, concise, and actionable. The same audience received multiple reports, ranging from 10 to 35 pages. Not all reports were shared across all the parties represented in project management, resulting in a diminution of transparency. The Project Sponsor received a separate report. The next chart summarizes project reporting at a high level. CIS Project Reporting Structure The three project managers developed the weekly and monthly status reports as a group. The status reports used multiple formats. It is unclear from the documents presented who authored the documents. The documents were frequently undated and it is unclear if reports were to the ESC or the Emera Maine board of directors. The examples below illustrate weekly status reports. The reported completion status clearly does not reflect what was actually happening on the project, given the eventual go-live date of June 2015. Even that date ended up being achievable only after significant functionality was deferred until after go-live. Weekly CIS Status Report Samples August 8, 2016 Page IV-7 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version Management set December 2013 as the original go-live date. Efficient and effective project management depends on accurate reporting to support the identification of trends and problems early enough to take corrective action. Project management reports did not provide early warning. The chart below (taken from a report by Emera Maine’s consultant PwC) shows what our detailed review of official project change requests demonstrated about these requests (which substantially affect work performed by Cayenta, AAC, and Emera Maine resources). The chart shows a moderate level of change requests occurring during the main body of planning and execution work and even through mid-2013, as the scheduled December 2013 go-live date was fast approaching. A veritable storm of changes occurred thereafter, showing the degree of misunderstanding of project status that continued essentially throughout the project leading up to the eventual go-live date achieved. Matching those change request clusters with the weekly schedule information shown in the preceding charts shows the depth of management’s misunderstanding of project schedule and scope. Tellingly, even the number of change requests coming after the June 2015 go-live date exceed those occurring through the time initially set for go-live (December 2013). It should have been clear much earlier in the project that management and resource changes were needed to get the work done efficiently and timely. Failing to make the first change in the go-live date, an 18-week extension, until March 2013 and the need to change it multiple times thereafter show that project management did not have a sound grasp on project work, its status, and, in turn, the resources required to accomplish it. Dates of CIS Project Change Requests 4. Resource Management Managing staffing effectively on a project such as the one at issue here requires ensuring that the right people, with the right skills and tools, are performing the right tasks, at the right time. Effective staff management is essential to a successful outcome. Emera Maine experienced significant gaps in its efforts to staff the project appropriately. August 8, 2016 Page IV-8 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version a. Emera Main Contributions to Staffing AAC and Cayenta both provided Emera Maine project leadership with estimates of the Company resources that the project would require. In particular, the role of client personnel on projects such as this one, impose particularly critical schedule requirements during acceptance testing and user training. The testing phase confirms the existence of required functionalities and system capabilities. The ability to complete testing timely is critical in allowing the re-work inevitably accompanying projects like this one to be performed in time to support go-live. The staffing requirements Cayenta presented addressed only the Discovery Phase of the project. This phase also takes substantial owner participation, in order to ensure a design basis that will support detailed development work by vendors such as Cayenta. The Cayenta recommendations did not address Emera Maine staffing requirements for participation in and support of testing, conversion, interfaces and report definition teams. AAC did address Emera Maine staffing across all project phases, recommending an initial Company staff of 19.5 full time equivalent personnel (FTEs) and a maximum of 27 FTEs at project peak. Nominally, the organization charts that management provided appear to show suggested Company staffing levels. However, the persons assigned by Emera Maine in many cases already had other responsibilities, or were asked to take on additional work in other areas, as non-CIS needs emerged across the life of the CU-CIS project. We repeatedly heard from company and vendor resources we interviewed that Emera Maine was simply unable to make the required levels of contribution, recognizing the difference between a “body” nominally assigned to the project and the number of hours expressed on the basis of full time equivalency that those bodies actually were available to provide. The pull on resources to perform other work outside the project was substantial, as reported often in interviews and as confirmed by examining project details. For example, a Project Management Quality report stated that the project team spent approximately 35 percent of their time on activities not related to the project. Examples of activities that took the team away from project activities included a state rate case, the Maine Pubic Service merger integration work, the joining of MPD into the CU-CIS project, production support for the legacy CIS, power outages, vacations, new Maine Public Utility Commission regulatory initiatives, and other IT projects. Even within the project, Emera Maine participants received multiple assignments, establishing dual roles for testing and training, whose activities overlapped in time. Other confirmations of the inability to resource the project with sufficient Emera Maine resources came with the November 2013 change request to add an AAC testing manager, the January 2014 change request to add AAC testing resources and the December 2013 change request to add AAC training resources. Beginning at least by mid-2013, the project experienced an extended period of testing delays. b. Vendor Personnel Experience Projects like the one at issue here required experienced resources. One common way of assessing the quality of vendor and consultant experience is to seek key staff members with resources that August 8, 2016 Page IV-9 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version have worked on projects of similar size and complexity. Emera Maine management should have expected Cayenta to offer resources with knowledge of the Cayenta product and implementation methods as implemented successfully elsewhere. However, we found no evidence that Emera Maine management received or reviewed resumes for key Cayenta project team members. The Cayenta Project Manager changed during the course of the project at the request of the Project Sponsor due to performance issues. The second Cayenta Project Manager’s resume indicated no prior service in project management on a Cayenta CIS implementation. The second AAC Project Manager’s resume indicated he was part of the AAC management team as a project administrator/facilitator. Emera Maine’s own internal project managers also did not have experience with a project of this size or complexity. Taken alone, that fact might not have been of singular importance, but it emphasized the need for due diligence regarding the experience levels of Cayenta and AAC. Based on a review of the second Cayenta project manager qualifications, the turnover reported in Project Management Quality Reports and management observations reported in our fieldwork, we concluded that Cayenta did not provide the project with resources with a high level of product knowledge. 5. Schedule Management A project like the CU-CIS should operate under a detailed project plan updated weekly. Good practice calls for the creation of a master, detailed schedule at initiation, supported by an appropriate schedule tool (for example, MS Project). Gantt or PERT charts should be continually updated to support effective tracking, monitoring, and reporting of progress. Project management created and maintained the CU-CIS plan using MS Project. The Cayenta contract included an attachment setting forth an initial project plan. Cayenta created a baseline project plan in January 2012. AAC had responsibility for supporting Cayenta’s development of this project plan. The January 2012 project plan did not contain the detail needed to ensure team members clearly understood assignments and completion dates, and did not provide accurate status. The Project Sponsor directed Cayenta and AAC to create a detailed project plan in March 2013, well into project duration. The baseline project plan was not maintained and when delays and major changes occurred a new baseline project plan was requested from Cayenta. Status reports do not indicate when new baseline project plans were created. Emera Maine paid two resources, the Cayenta PM and the AAC PM to create and ensure completeness of the project plan. In addition, in February 2013 the AAC PQM was paid for additional hours to work on the project plan. In March 2013 the AAC PMQA deferred development of the Project Management Quality Report to work on the re-plan. In two instances, the AAC quality manager did not do project quality management for two months and was paid instead to create a realistic schedule, the responsibility of the Cayenta and AAC project managers. For those two months, three resources were paid to work on the project plan. Status reports to the ESC did not contain Gantt or Pert charts directly from the project plan. Status reports showed the timeline at a very high level and in PowerPoint format. We did not see indications of the incorporation of contingency into the new project plans. Identification and August 8, 2016 Page IV-10 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version assessment of critical path activities is important in analyzing downstream impacts of current sources of delay and in making adjustments to address slippage. The lack of critical path analysis obscures understanding of true schedule status, what is driving delays, and where action can be taken to recover. The project’s status reported critical path information at a high level. We did not see indications of use of critical path analysis to assess analyze impacts or options for addressing schedule slippage. 6. Contract Management Contract management begins with creating a sound definition of the services to be acquired, and proceeds to establish the means for managing the provision of those services, and incorporates effective processes for measuring and reporting performance to support efforts to ensure the cost, time, and quality effectiveness of those services. Contract management assists in managing the key elements of contracting throughout the duration of contract execution. The next chart summarizes the phases of contract management. Contract Management Phases a. Contractor Selection Emera Maine applied appropriate procurement practices in contracting with AAC and Cayenta. Company management sought proposals in each case, obtained proposals from multiple vendors, and based the vendor selection decisions on a process under which it scored the proposals received. The selection followed applicable procurement policies and procedures. The board of directors authorized the agreements. The project team recognized value in seeking outside expertise in implementing the CU-CIS. Management AAC as the consultant to facilitate the definition of requirements for the project, and to assist in development, evaluation, and selection under the RFP that led to the selection of Cayenta. Contract planning for CIS software and services began by defining requirements and developing that RFP. The RFP contained reasonably described the software and professional services required, and provided information about functional and technical requirements. The RFP gave those responding detailed requirements, and sought fixed-fee pricing for the services identified. Fixed-fee contract has become the norm for CIS implementations. The bidders use the detailed information provided in the RFP requirements, respond in their initial proposal and if selected, conduct the analysis with the company to provide final pricing for the fixed fee contract. Using EDI as an example, the process is defined below. August 8, 2016 Page IV-11 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version A change request approved June 2013 indicated that the hourly settlement piece, the supplier fixed fee adder, and the forward ICAP was missed in the functional requirement definition. Management made cost a particularly strong evaluation factor in selecting the CIS vendor. The CIS vendor cost evaluation used total cost as the evaluation factor. Cayenta received the most evaluation points for being the lowest cost bid. Cayenta’s cost advantage came predominantly as a result of a far lower estimation of required hours when compared with the other competitive bidders. Management status reports issued during the project observe that Cayenta underbid the project. During the RFP process, each vendor provided estimated cost. Information available from the offers of those bidding confirms that Cayenta’s bid contained information enabling Emera Maine to determine that Cayenta anticipated a work effort of less than half of what the other vendors, did. The vendors also provided a blended rate per hour. The project team evaluation looked at total cost by vendor for project implementation services, basing scoring on the total dollar amounts bid. One can calculate the hours underlying bids from information supplied by the bidders (using fee quotes and average hourly rates). We calculated total hours using the RFP information. Cayenta bid a far lower number of hours than did the others - - by a factor of more than two. Cayenta’s derived hours were 25,938, with those of the second place finalist at 67,210 hours (a factor of over 2.5). The second-place bid offered hours in line with those of the other bids. Moreover, the second-place bid came from a first-tier firm in the business. Those other bids included a first-tier, market leading firm. While reputable, Cayenta falls into the second tier of providers, and in this case was bidding on work in a restructured marketplace, with which it did not have deep experience. August 8, 2016 Page IV-12 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version The following chart is confidential CIS Vendor Selection Hours Comparison Provided by EM Calculated Project Implementation Services Total Dollars Blended Rate Total Hours Time Bid Per Hour Outside counsel assisted with the development of the Cayenta contract. The Cayenta contract had a 30-month term and a cost of '''''''''''''''''''''''''''''' plus expenses. This amount would ultimately increase substantially, as a result of extending duration, providing resources to augment required Emera Maine staff, and adding scope. The contract provided for a fixed price, deliverable-based agreement for services and actual expenses as incurred. The approval documentation for the AAC contract, authorized on August 10, 2011, described it as “Fixed Price For Services, potential for travel to exceed estimates.” This contract also had a 30-month term, and listed a cost of '''''''''''''''''''''''''''plus expenses. Management later extended the contract duration and added a provision under which AAC provided staff to augment Company resources, which served to increase contract cost materially. b. Contract Administration Acceptance of deliverables comprised an important part of contract administration. Acceptance of the deliverables under the contract comes when they are determined to meet established acceptance criteria and secure Company approval. The AAC and Cayenta contracts and a “Project Charter” documented the deliverance acceptance process. The AAC contract gives the AAC Project Manager responsibility for managing overall deliverable review, and for facilitating Emera Maine’s acceptance of the Cayenta deliverables. These functions include oversight of the Cayenta contract and elevating variances as needed to Emera Maine’s project manager. Additionally, the project Quality Assurance Plan provides for AAC Project Manager review of and feedback to Emera Maine’s project manager on Cayenta deliverables associated with payments, vendor activities, and milestones. We did not find documentation addressing the performance of these AAC Project Manager roles. Emera Maine personnel we interviewed stated that AAC provided feedback verbally in weekly status meetings. We did not find regular reports addressing deliverable acceptance issues, including status, quality, and consequences for the Cayenta contract. AAC monthly Quality Project Management Reports from August 2012 to August 2014 made deliverable recommendations in a general manner, but only rarely detailed specific deliverables. August 8, 2016 Page IV-13 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version The Project Quality Management rating trended downward. The rating rarely dropped to the AAC “troubled” category. Deliverable Management Ratings The Cayenta contract made provision for a fee holdback provision for late deliverables. Change request # 054 on September 9, 2013 deferred invoking Cayenta holdback of '''''''''''''''''''''''''''''' for late deliverables. There is no evidence the holdback provision was used. 7. Scope Change/Order Management The scope management process needed for a project like the one at issue here should monitor and limit monitor scope creep. It requires documenting, tracking, and approving/disapproving requested project changes. Levels of authority for authorizing changes typically depend on the degree of change involved. The change control process as defined in the project charter required that requests affecting project scope, schedule or cost must receive the approval of the Project Steering Committee. A review of the approved change requests does not show evidence of approval by the ESC. The Project Sponsor approved the change orders. This project employed a well-documented change request process, which ultimately addressed 123 change requests. The next chart shows that the majority of the requests addressed staff augmentation or time extensions. August 8, 2016 Page IV-14 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version Change Request Causes The number of change requests for scope extensions created relatively small cost increases. They did, however, contribute to schedule delay. Progress slowed as a result of seeking approvals, revising the project plan, and documenting impact to deliverable numbers and dates. Starting a project with a planned change request is not ideal, but occurred here. Emera Maine decided to include MPD in the project after execution of the vendor contracts. A January 2012 change extended the schedule and added costs for discovery phase work associated with MPD. Recognizing the impracticability of keeping MPD on board, Company management decided to exclude it in February 2014; i.e., at the time when the second go-live date of April 2014 had been anticipated. Further work on MPD (Phase 2) was delayed until after completion of the BHD project.. 8. Project Phases The next chart depicts key elements of a project’s cycle, as depicted by the PMBOK. The planning and execution elements are the most critical to project success, and are closely intertwined. The planning phase determines the detailed aspects of the project, and provides for their coordination and documentation. The execution phase carries out these plans, with adjustments as needed to address emergent circumstances. There often exists temptation to abbreviate the planning phase, in order to get the project underway quickly. Emera Maine did not skip the planning phase but did fail to provide for the completion of design documents until the execution phase was well underway. Management observations reported during our fieldwork August 8, 2016 Page IV-15 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version indicated design documents frequently did not capture functionality. A reported problem was that while Cayenta provided a facilitator, they did not provide a note taker, causing errors in the information collected from the company. The Cayenta planning phase - Discovery/Analyze/Configuration – had an initially scheduled completion date in the fourth quarter of 2012. The Cayenta execution phase – Custom Development/Design and Develop – overlapped planning, starting in the third quarter of 2012. This approach leads to inefficiencies and delays in the execution phase. The quality and quantity of work completed during the planning phase is critical to project success. The plan to overlap phases became more complicated with the May 2014 recommendation of the PMO to start running phases in parallel. Work not completed in Discovery/Analyze/Configuration ran parallel to Custom Development/Design and Develop, creating additional integrated testing as new functionality was delivered and changes to training materials. Effective planning phase includes the creation of plans for managing all major aspects of the project, including communications, risk, resource, training and testing. The plans facilitate resource planning as well as document approach and expectations. The project originally planned for the creation of testing and training plans for the third quarter of 2012. Status reports indicate they remained under development until late 2014. 9. Cost Management Effective cost management requires a full understanding of what services and deliverables a contract includes and a plan for addressing those not included. When, as here, one bid proves far lower than the others received, caution dictates an understanding of the underlying reasons. Those circumstances existed here, with Cayenta offering a bid far lower than others considered in management’s evaluation. Our interview with AAC leadership disclosed a range of estimates for a CIS project of this type between $12.2 million on the low end and $22.1 million on the high end. AAC also offered 24 months as a reasonable schedule from project initiation to go live. While substantial, Cayenta’s price formed only about a '''''''''''''''''''' of the total original project budget of $18,875,079. The two largest contracts for the project were with Cayenta and AAC. Out of the $16.9 million the company paid to contractors for the project through December 2015, $13.3 (or roughly '''''' percent) was for payments to AAC and Cayenta. Cayenta’s original bid was '''''''''''''''''''''''''' plus expenses. Cayenta was paid '''''''''''''''''''''''''' (112 percent more including expenses). AAC’s original bid was '''''''''''''''''''''''''' plus expenses. AAC was paid '''''''''''''''''''''''''' (286 percent more including expenses). Information about project costs versus budget is typically reported to an oversight committee. Project costs were not part of the formal ESC reporting. Interviews indicated project costs were reviewed as part of the breakout meeting of company executives after the ESC meetings. 10. Project Quality Assurance Project Quality Assurance should provide a comprehensive, staffed program for the systematic monitoring and evaluation of the various aspects of a project to ensure that standards of quality August 8, 2016 Page IV-16 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version are being met. This role also should include monitoring vendor performance against contract terms and conditions. The quality audit function provides structured, independent processes to determine whether the project’s documented processes are being followed. AAC’s scope included the provision of quality management services. The Project Quality Management Report provided high-level ratings and summary comments for the ESC. A more detailed summary was provided for the Project Management Team. A narrative report was provided separately to the Project Sponsor. The Project Quality Management Report was not completed every month. Occasionally the Project Quality Auditor would assume other duties. Below is an example. AAC provided Project Management Quality Reports through December 2013. The report changed in 2014 to a Business Readiness Report. The high level summaries of the Project Management Quality Reports were presented to the ESC. The Project Quality Assurance Plan stated that project reviews by Emera Maine auditors would focus on ensuring the project was progressing as it should and was providing a quality final product. There is no evidence of reports or recommendations from Internal Audit. August 8, 2016 Page IV-17 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version 11. Risk Management Risks should be identified, addressed, and closed in a timely manner. The company’s project charter documented a risk management process for identifying and documenting risks. . Risks were identified and tracked. The number closed per month was not provided in the documents reviewed. Trending of closed risks was not possible. The critical project risks were documented and reported to the ESC on a monthly basis and when applicable, specific risks were discussed as topics at the monthly ESC Meeting. The AAC ratings defined above indicate that risk scoring rarely dipped into what AAC defined as the “challenged” category. 12. Post Go-Live CIS implementations typically involve the discovery of unanticipated problems, sometimes numerous and significant, post go-live. Utility industry response to these problems vary from continuous work across a period of years to correct errors and processes to launching a problem resolution phase within six months of go-live. Management took steps in October 2015 to address remaining defects and existing system problems. Management signed a contract with Modern Grid Partners in October 2015 to provide support for the post go-live management of outstanding issues and provide CIS Phase II planning. The principals of Modern Grid partners had been previously working for the Company through the firm of Woodward and Curran. Their primary responsibility was to take responsibility for staffing developer, tester, and project management roles. The Emera Maine COO became the new Project Sponsor and the ESC was actively involved in making recommendation regarding change requests, deliverable acceptance from Cayenta and approval of invoices. The total paid to Modern Grid Partners was ''''''''''''''''''''''. Project Katahdin was launched and aimed to lower the count of incidents, focusing on the highest impact fixes. The team quickly surveyed missing scope, incidents, and defects with a focus on regulatory, financial, customer-facing, and efficiency-gains. The team started with 369 issues on October 1, 2015. Phase II issues and system enhancements were excluded (144 items) while other incidents were added (181). August 8, 2016 Page IV-18 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version A number of items in the original CU scope were not completed at go-live, resulting in workarounds and missing functionality which affected operations and the customer experience following go-live. Project Katahdin has resolved many of these issues. Management made the decision to go-live with a less than perfect CIS. Eighteen months later than planned, the new system was put into production for the BHD. However, many of the features in the original scope of work were, for one reason or another, not present at go-live. In some cases, the need was no longer there. For others, the scope was deferred to Phase II because of complexity, a lack of time or resources, or the realization that it could be better deployed post go-live. Delayed scope aside, the Company was also faced with a long list of issues not resolved prior to go-live and still needing resolution. Management has had a significant number of issues to resolve while using the system to bill and support customers. Project Katahdin was successful, primarily because it used smaller teams and apportioned the work into short-sprint projects designed to achieve quick wins and build confidence. Additionally, the team was allowed and encouraged to work directly with the business to resolve complex issues. Teamwork was emphasized as was a work/life balance, and successes were celebrated to build team morale. The new external project manager (vendor) brought a clear strategy and approach for completing the work that instilled trust among team members. Most importantly, an executive steering committee was engaged and provided clear direction for the team. The following functionality was installed as a result of Project Katahdin:  Fixed a flaw that prohibited accounts closed with open payment arrangements to be picked up by the write-off process  Reduced unapplied credits, allowing the matching of certain unapplied credits with the appropriate accounts and ensuring that the aging balances reflect these applied credits  Accomplished more than 40 EDI fixes to improve the quality of EDI transactions sent to marketers  Corrected several customer letters, sent by Kubra, to communicate Commission-required information including the winter warning letters, seasonal connects, and Lifelight  Enabled enrollment of customers into the Low Income Assistance Program (LIAP)  Built a new Finance Portal to ease reconciliation between CU and Oracle General Ledger  Addressed a GIS logging transaction to keep the systems up to date and current regarding meter changes  Created a work flow popup for RPSD with alerts/confirmations of work flow steps in the new business process to provide status of a request  Reduced runtime of PowerOn interface from 20 hours to five (daily operation to monitor, update data so that dispatchers have data for system operations, power outages, and customer details)  Enabled cancellation and setting of payment arrangements on certain accounts that had payment arrangements that could not be cancelled  Created a program to compare invoice from CU and the number sent to Kubra to ensure that missing bill prints can be identified and acted upon August 8, 2016 Page IV-19 The Liberty Consulting Group Public Utilities Commission State of Maine     Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version Developed an automated process to transfer refund payment files back to BoA and pick up the daily reconciliation files to save time and eliminate the risk of pulling files manually Created ability to process return checks and fees for the applicable reason Allowed all work orders to show a meter serial number to improve field efficiency and validate that work is completed on the correct meter Eliminated a step when resolving a meter exchange to save time for the billing group. Since go-live, 80 items have been identified as “delayed scope” and 12 were categorized as “Phase II”. Key delayed scope items are listed in the following table, as well as the items categorized for Phase II. Delayed Scope Address Corrections Interface Supplier Hourly Pricing Ledger/Bill History Report Activity on Employee Account Alert Auto release of guarantor Unable to access location Customer Self Service (website) Real-time pricing configuration Guarantor Portal Use of MDM estimates for hourly pricing EDI Marketer Maintenance Portal for Rate update Planner work assignment and tracking using tasks Net metering Dashboard Customer Service More search fields EDI PENDMI Alert Phase II Asset Inventory for CT and PT Service Order Performance Enhancement EDI Pend/Paid AR Item Types (2 items) Patch for efficient LITE billings Meter type CC915 Change meter type CC948 to CC942 EDI separation of files/marketers by region MPD scope (4 items) The Katahdin Project created a CIS communications plan to guide communications and to build confidence in the quality and accuracy of CU within the user community. C. Conclusions A broad range of gaps led to significant negative impacts on schedule, cost, customer experience and employee satisfaction resulting from the CU-CIS project. 1. The Project management team approach, focusing overly on consensus-based decisionmaking, diminished the ability to make timely, effective decisions. The project lacked a single point of contact to administer and control the entire project. By default, the Project Sponsor filled this role, while remaining responsible for broad and critical executive leadership of other critical functions. Management tried to remedy the problem by bringing in a Senior Project Manager in mid-2013. Status reports indicate improvement with August 8, 2016 Page IV-20 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version project management. However, roles were not realigned to move deliverable acceptance and change request approval to the Senior Project Manager. The company’s Project Manager was responsible for directing the work of the company’s project team. Status reports and interviews indicated that direction came received from multiple project managers, resulting in confusion and conflicting priories for the project team. 2. Use of the AAC Project Manager to co-manage with the company’s Project Manager contributed to a lack of cohesive project direction. A typical project management approach encourages the entire project team to operate as one cohesive unit to get the work done. An ideal working environment requires teamwork, as everyone works toward the same goal of implementing a quality system. The AAC contract states the AAC PM was responsible for assisting the company’s Project Manager in overseeing both the company and Cayenta project teamwork activities. If teamwork activities are defined as tasks, accountability, and completion of work, that indicates co-project managers managed Cayenta. As defined, the Cayenta Project Manager was required to take direction from both AAC and the company. Cayenta thus did not have a single point of contact. In interviews, Cayenta management reported this approach created a barrier. 3. Lack of experienced resources affected cost, quality, and schedule. Before agreeing to proposed vendor staff, the company should have understood how experienced the proposed staff was in proposed positions. In most cases, resources on the project were not screened for equivalent experience. For instance, if a resume review for a Cayenta developer indicated no Cayenta CIS experience, project management would have the opportunity to accept that risk, or not. Emera Maine leadership eventually requested that both the Cayenta and AAC project managers be replaced in early 2013 because the project plan they were responsible for was not a predictive tool. It is unclear if either project manager had ever developed a project plan for a project this size. Status reports documented high Cayenta turnover. The reason for turnover was not documented. 4. The lack of company resources delayed the project and increased costs. AAC and Cayenta estimated for Emera Maine the numbers of Company staff required to implement the project. Cayenta estimates were not fully developed beyond their Discovery Phase and did not take into account the overlap between the phases. The Company should have committed to staff the minimum number of staff as defined by Cayenta. As the project continued to miss go-live dates, the Company needed to produce more full time resources. It eventually turned to AAC and Cayenta to supplement them. We did not find documentation identifying Company resourcing as an issue during project planning. Management should have fully planned for staff augmentation including the back filling of full time positions. We did not see evidence of the exploration of staff augmentation options before contract signing. Resources for areas such as training and organizational change management do not require specific knowledge of the Cayenta product. These disciplines require good method, planning, tools and the ability to direct team members through implementation. August 8, 2016 Page IV-21 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version 5. Change requests created a drain on resources, and affected quality and schedule. Including MPD in scope shortly after the project began had unintended resource consequences. Removing MPD from scope in early 2014 recognized, albeit tardily, the risks of taking on an additional operation. Many scope changes occurred, but those addressing development work missed in the planning or requiring rework did not impose material costs when compared to the cost for time extensions and staff augmentation. The changes did produce schedule drag, however, bringing additional work for a team already overloaded with tasks and for a project management approach premised on consensus building, rather than prompt execution. The no dollar change orders to add functionality created more work for the company developers. These change orders, with the known problems of the Company’s lack of resources and Cayenta’s late or unacceptable deliverables, contributed to project delays. 6. Lack of a strong project approach and plan, combined with the variable quality of status reporting, complicated efforts to identify and resolve problems in a timely manner. Problems with development of the project plan started with the lack of detail in the plan delivered in January 2012. Despite numerous changes and adding hours for AAC to develop the project plan, it did not become a predictive tool. AAC Project Management Quality Reports frequently identified the issue of late and incomplete updates of the project plan by Cayenta. Comments included observations like “no visibility into the detailed planning and progress.” In 2013, a four-month effort took place to create a realistic project plan to meet a new go-live date. It was followed, however, by numerous go-live date changes extending to mid-2015. The first QA report after the extension of the timeline in September 2013 indicated, “The schedule has been baselined and the team is driving to the new dates.” However, by the end of September, some needed updates remained and several tasks were late. The schedule showed 160 late tasks. Commentary indicated that, “The PM team is confident that this is more the result of missing schedule updates than of actual late items, although all agree that there are indeed some late items – just not sure how many.” Planning is not possible with missing and vague information. Moving go-live dates resulted in work that had to be redone after dates were missed. Training was affected, as the team trained the stakeholders, refreshed the stakeholder training after missed go-live dates, and trained with materials that were not updated. For Company personnel already tasked with substantial non-CIS project responsibilities, the lack of credible CIS-project scheduling cannot have encouraged dedication to CIS schedule dates when balancing conflicting work requirements. AAC rated the project each month in the Project Management Quality Reports. The next reproduction summarizes the AAC rating key. August 8, 2016 Page IV-22 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version The chart trends ratings over time for three areas measured: Overview, Deliverable Management and Training, based on Project Management Quality Assurance reports through August 2014. Testing is not reported as a separate category. The ratings appear optimistic, given a succession of missed schedule dates. The overall ratings never fell into the “Troubled” category, despite a schedule that would eventually be overrun by 75 percent and a budget by 50 percent. Particularly significant is the observation of AAC leadership that a 24-month schedule was reasonable and that the high end of an expected cost range was in the range of $22 million. Management either fundamentally misunderstood where the project was, or was unable to tackle the challenges presented. 7. Deliverables were accepted before work completion. Include In reviewing the deliverable acceptance sheets, it is apparent that Emera Maine accepted deliverables that were incomplete. One example is testing deliverables, summarized as follows:  Deliverable #404, Testing Strategy Document – Cayenta will create a testing strategy roadmap for planned testing phases including relationships to other project activities – accepted 7-27-12. August 8, 2016 Page IV-23 The Liberty Consulting Group Public Utilities Commission State of Maine      Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version Deliverable #406, Functional test scenarios and expected results for each business process in the functional matrix - accepted 10-30-12. Business process functionality developed through 2015. Deliverable #407, Integrated Test Plan - accepted 5-5-13. Full time AAC test lead developed the Integrated Test Plan. Deliverable #408, Integrated Test Schedule – accepted 5-30-2013. AAC test lead and consultants planned test schedule through 2015. Deliverable #409, Integrated Test Scripts – accepted 5-8-14. AAC test manager and consultants wrote test scripts through 2015. Deliverable #801, Functional Test Plan Execution - The deliverable confirmed that functional testing had been successfully completed with no P0 or P1 Level Defects accepted 5-5-2013. A project plan dated 3-24-15 indicated functional testing was completed 3-31-15. Another deliverable example is training. The AAC 7-11-13 Quality Project Management Report indicated the Cayenta Training Plan did not contain all of the components required by the SOW and recommended the deliverable be rejected as non-compliant. The company accepted Deliverable #205 on 3-21-12. Documented in CR # 50, AAC waived '''''''''''''''''''' to provide a training plan template and development since the Cayenta deliverable did not meet minimum requirements. Cayenta training materials were built for an earlier version. Since it was dated, project management had to rely on another Cayenta customer to share their documents and paid AAC to provide the training plan and training lead. AAC was paid to create a training assessment. The training assessment was a Cayenta deliverable per the SOW. D. Summary of Management’s Performance in CU-CIS Project Management The level of management performance exhibited in a range of categories central to effective management of the CU-CIS project justifies holding management accountable for 12 months of schedule delay, which unreasonably increased project direct costs by approximately $2 million and AFUDC by an amount to be determined. Management began the CIS project without substantial internal experience in the implementation of complex information systems. It also conducted the project across a time period that brought many sources of competition for the internal resources necessary to manage and participate in the project in ways designed to make it successful. We believe that management’s inability to recognize and respond timely to project performance issues caused unnecessary delay in reaching go-live date. These issues also led to significant exclusions from the scope of the capabilities delivered at go-live date, as management was forced to delay the inclusion of a significant number of capabilities to a time well after both the initially planned December 2013 and the eventually accomplished June 2015 go-live dates. A lack of awareness of the size of project needs led to underdevelopment of the project’s management structure, methods, and practices, and an inability to provide the Company resources necessary to maintain schedule caused significant delay. This delay caused material cost impacts by extending the period of time across which Emera Maine had to sustain Cayenta, AAC, and internal project management and administrative resources. Finishing the work materially sooner, as should have been the case, would have shortened the period of time across August 8, 2016 Page IV-24 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version which these resources were required. Doing so would also have reduced AFUDC accruals for two reasons: (a) eliminating the excess project management costs, and (b) shortening the period over which the other, reasonable costs would have accumulated. We estimate the avoided project management costs at approximately $2 million. We have not calculated alternative AFUDC costs, which we believe, however, are amenable to calculation jointly by the Company and Commission Staff, applying their knowledge of the necessary inputs and prior rate treatment of CIS costs. In planning the project, Company management understood the need for substantial implementation work to be performed by experienced vendor resources. Management was also given to understand by both Cayenta and AAC that owner personnel would need to play a very substantial role in the early stages of the project, contributing to a comprehensive and robust identification of needs, underlying processes, data capabilities and limitations, and data conversion requirements. The very large and comparatively very late emergence of change requests to address system needs underscores the apparent inability of management to support a fully comprehensive performance of the early stage work supplying the foundation for Cayenta’s development work. Interestingly, the extra, compensated hours it took to accomplish this portion of late-identified work was not particularly large. To the extent that this work was necessary in any event, and as Cayenta appears to have absorbed a significant share (i.e., not get compensated for the hours identified), we did not find the scope changes associated with development work to have caused the incurrence of unreasonable costs. However, the inability to recognize, assess, and approve work on them earlier contributed to delay that more appropriate management and better early needs identification would have mitigated. To a material degree, the need for added work should have been apparent (and may well have been) from as early as the vendor bidding process, from which Cayenta emerged as the winner. Management could have determined from the bid information that Cayenta estimated the required effort at less than half the hours that the other bidders appear to have contemplated. That the second-place bidder was a first-tier, very highly experienced provider in the investorowned utility business, should have signaled to management the need for a stronger and tighter management approach. Cayenta, although a reputable and capable provider, operates in a lower tier of the marketplace and was recognized as lacking in experience with marketplaces requiring accommodation of a complex array of competitive alternatives for customers in choosing energy suppliers. That Cayenta would be building a staff to perform what amounted to half the work of others (on an hours required basis) makes it all the more difficult to justify the inability to create a structure that would have identified needs better, observed lagging performance earlier, and compelled stronger vendor performance earlier. In short, even if adding hours to enable Cayenta to get the development work would still leave its hours (and direct costs) comparable or better to what others offered, the risk of schedule loss would still leave Emera Maine exposed to significant cost penalties. What began as a roughly $5 million advantage over the first rated alternative to Cayenta became a loss of a similar magnitude, measured nominally by comparing the project’s estimated cost at inception versus its August 8, 2016 Page IV-25 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version costs at go-live. Moreover, considerable post-go-live costs remain, given the amount of work still to be performed to create capabilities excluded from initial go-live to save schedule time. Already underestimating the balance between its internal capabilities and project needs, management increased risks early in the project by including MPD in scope. This addition produced a recognized delay early, and its continuing drag on progress is evidenced by the decision early in 2014to remove MPD, and place it in a second project phase. Taken alone, this risk cannot be considered unreasonable, but it shows more generally management’s inability to come to grips with risks already considerable given the need to manage a second-tier firm, operating in market conditions where it had short experience, and believing it could deliver for half the effort that other, more experienced vendors thought would be required. Thus, taken in combination with other circumstances, adding the risks of MPD can be considered an unwise course. MPD operated under a different system, using different business processes, operating under different resources, managing data whose different data structure imposed unique transfer and conversion needs, for example. Addressing MPD’s circumstances contemporaneously with those of BHD would stretch an already challenged project management structure and set of internal resources. The elimination of MPD very late into the project to get to go-live sooner amply demonstrates that, even though the project was measured as approaching completion, MPD’s needs continued to impose great strain on resources. Senior executive leadership at Emera Maine noted during our field work that the level of criticality as between BHD and MPD needs involving CIS replacement were very different. BHD needs were much more critical (expressed in terms of a system collapse from which recovery would prove impracticable) when compared with those of MPD (improved effectiveness and efficiency). This difference made combining the two risky for more than schedule reasons. Lagging performance began to manifest itself fairly early, but management persisted in holding to the original December 2013 go-live date for a long time. During that time, planning and ensuring adequate owner staffing for the coming stages (e.g., testing, delivery acceptance, and training in new business processes and use of the system to support them) did not appear to be needs on which management attention focused. It is of particular note that a far greater number of change orders came after the originally proposed December 2013 go-live date than before it. This phenomenon underscores a number of observations:  Management observations about how far along the project was were misplaced  Concern about Cayenta’s ability to deliver after having planned for comparatively smallscale work efforts was valid, but did not lead to the flushing out of problems early  There was a failure to recognize until fairly late the need to push schedule out, to sequence work without undue overlap, and to staff up for what would in any event prove a more complex than anticipated testing and acceptance phase. The pattern of acknowledging many short schedule extensions indicates an approach characterized by “bulling ahead,” rather than carefully considering the most logical way of regrouping in order to develop an objectively, carefully determined optimum path to completion. August 8, 2016 Page IV-26 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version Changes eventually made did succeed in bringing go-live to fruition, but the schedule cost was high and the exclusions of capabilities needed to get there were significant. This approach suggests that even the wisely added work associated with scope changes likely caused some inefficiency in its execution. Countering this cost-increasing factor, however, were some concessions by the contractors, which tended to mitigate some inefficiencies. Moreover, a stronger, earlier created project management organization would have also caused costs to be incurred earlier. There is no practicable way to calculate how the interplay among these counterbalancing factors net out. We are inclined to the judgmental view that the change requests directly associated with additional development work did not on a net basis add costs that would have been avoided had management been more effective earlier. Apart from efficiency impacts from late identification, the work would have had to have been performed anyway. More active engagement up front may have taken greater use of outside versus inside (and therefore moderately more expensive) talent. Absent an ability to address the balance between these two factors quantitatively, we look at them as effectively canceling each other. The far greater impact of late identification of project work needs is schedule-related. The number and timing of the changes required should have given management substantial grounds for questioning schedule viability. Management lacked visibility into what was happening on the project and suffered an inability to grasp the schedule implications. A more robust and earlier recognition of schedule risk would have made clearer to management the importance of the back-end integration process and its resource needs. Management, however, permitted a diminution in internal resources to occur, as personnel having CIS roles, but already assigned to non-CIS work suffered even greater diversion of effort to address emergent priorities. Whether or not other work caused total removal from CIS activities, the time spent on them diminished as other priorities tugged. The loss of “hours” dedicated to CIS work was noted in project reports and cited commonly as a material problem during our field work. Apart from the matter of resource application, problems in work identification and planning existed as well. Management had reason well in advance of testing and acceptance work to expect those activities to prove more demanding than originally expected. Planned overlaps with development work would clearly require a nimble, fast-responding test group, whose activities in general would become more schedule critical. The continuing requests for changes to address development needs gave ample reason for concern about the ability to provide for testing deliverables demonstrating high quality and completeness. Cayenta by now certainly had to be viewed as clearly underestimating its required work and not having created and applied a staff optimized for the actual amounts of work required. These recognitions further emphasized the likelihood that acceptance of its work would likely not be characterized by a comparatively high level of once-through test passes. Faced with a need for strong planning of the phase including testing, project management entered it with a plan that proved weak. The integrated test plan required of Cayenta was accepted in May 2013. Much later a change order acknowledged that the plan already accepted August 8, 2016 Page IV-27 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version plan actually did not meet minimum requirements. Emera Maine then compensated AAC to prepare an effective integrated test plan. Ultimately recognizing that it could not provide the internal resources needed to support testing and training, management eventually turned to AAC and to Cayenta to provide the bodies management could not. Thus, having already approached the project’s late stages with a static view of resource needs (based on estimates provided at project initiation, not re-estimates based on what had happened since then), management further failed even to supply from its resources the initially defined needs. Executive management acknowledged during our field work that schedule length was problematic, but also observed that going faster would have cost the same, because more expensive outside resources would have been required. We take a different view. Management did turn extensively to outside resources late in the project to compensate for the inability to provide the internal resources needed. We believe that in performing work necessary in any event, that their costs were appropriately incurred. The penalty arose not from their use, but from the fact that a shorter project schedule would have saved Emera Maine ongoing project management costs (from other than the testing and training resources) that are strictly a function of project duration. Turning to the matter of project duration, a number of reference points exist to help identify what would, under normal performance, comprise a reasonable schedule. The vendors who responded to the RFP for the Emera Maine CIS project proposed schedules in the range of 23-27 months. A senior AAC executive who worked on the project stated during our audit field work that he viewed a schedule of 24 months as reasonable, with a resulting cost ranging from about $12 to $22 million. Applying our experience would also call for 24 months, but we consider it appropriate to begin from a somewhat more generous 27months, in order to begin our analysis from a reasonably conservative base in assessing the consequences of management’s failure to meet a reasonable schedule. The actual go-live date of June 2015, versus the initial schedules date of December 2013, produces a schedule of 45 months, measured from signing of the Cayenta Statement of Work. These dates produce a schedule delay of 18 months, using the baseline from which we chose to start our analysis. Our experience teaches that projects like the CU-CIS can be expected to produce customer affecting problems immediately after go-live dates, even when well managed. While that was the case here, we did observe that management here delayed go-live in order to help mitigate such problems. The kinds of system-related problems experienced post go-live here were moderate by comparison to what we have seen. Many of the problems that did occur were a function of staffing levels, rather than system “glitches.” The sound (under the circumstances existing in the first half of 2015) decision to defer go-live would thus tend to shorten from 18 months the schedule delay attributable to the management issues we found. However, it is also the case that the June 2015 go-live date was supported by excluding a number of capabilities one would have expected a reasonably complete CIS to offer. Work and costs continued therefore to accrue post go-live on a number of these capabilities, for example:  Group Billing August 8, 2016 Page IV-28 The Liberty Consulting Group Public Utilities Commission State of Maine      Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version Customer Self-Service Web Portal Mobile Service Orders Performance Dashboards Batch Processing Supplier Hourly Pricing. A wise go-live delay and a reduced scope CIS cut in opposite directions in terms of deciding whether and by how much to move from the 18 months set as our starting point. We settled on allowing a third (six months) as appropriate under the circumstances. This time block leaves a 12-month delay period for which we believe management should take cost responsibility. Delay costs include those attributable to continuation of the structure required to support the management and oversight of the project, not costs associated with: (a) the direct work performed on the project for additional scope to develop functionalities, and (b) the staff augmentation that AAC and Cayenta provided to replace Emera Maine resources in areas such as testing and training. These costs rise in four areas: The first area consists of monthly costs of Cayenta project management. Our review of change orders so far has identified project management costs associated with schedule extension of about ''''''''''''''''''''''''. We continue to examine change orders to verify this amount. Should it remain correct, applying 12/18th produces about ''''''''''''''''''''. The second area consists of the monthly costs of the AAC project consulting team. That wellidentified group of individuals appear to have created monthly costs of '''''''''''''''''''' per month fairly steadily throughout the project. We are, however, continuing to review project documentation to verify the continuation of this monthly amount into late project stages. Applying ''''''''''''''''''' for 12 months generates costs of ''''''''''''''''''''''''''''''''''''''''. The third area consists of costs charged by those persons on the Emera Maine team whose principal role was to manage or oversee the work of others. We did not include the costs of the internal resources who performed direct work on the project, for reasons similar to our logic in excluding Cayenta and AAC resources performing direct work. We identified the positions covered by reviewing organization charts, job titles, and discussions with management about roles. These information sources produced what we consider a reasonably clear distinction between project managing and direct roles. We received monthly charges made by those holding those positions during the project. We observed that the total of their monthly charges ran the highest (averaging $82,500 per month) during the last months of the project, leading to go-live (the first six months of 2015). Even had delay attributable to management not occurred, one would have expected highest monthly “burn rates” during the last months. We therefore considered burn rates for 2014 more representative of the costs that would have been avoided in the absence of a 12-month delay attributable to management. Applying the average 2014 monthly burn rate of $67,200 produces a total of $800,000. The monthly personnel costs provided included payroll adders. CU-CIS project accounting also tracked overhead costs (termed “AO”), which include the payroll adders already August 8, 2016 Page IV-29 The Liberty Consulting Group Public Utilities Commission State of Maine Audit of Emera Maine Docket 2015-00360 Implementation of the New CIS System Final Report-Public Version captured. We continue to work with management to determine whether and how to capture any other costs associated with the internal personnel engaged in CU-CIS project management roles. Recognizing the continuing need to verify the numbers for the reasons cited, our analysis so far has identified $2 million in costs for delay that we attribute to management. Delay also affected AFUDC charged to the project. We recognize that some of the approximately $30 million in CUCIS costs is not affected, given earlier recognition of some portion of project costs in rates. What remains to be calculated has two parts:  Calculating AFUDC after exclusion of the $2 million in direct costs for 12 months of delay  Calculating AFUDC on the basis of a modeled yearly flow of remaining expenditures that has an end date 12 months earlier than actual. Management has expressed the view, which we find reasonable, that it should be possible to construct, with Staff participation, a model suitable for making this AFUDC calculation. Management has expressed a willingness to do so, recognizing that it may choose to disagree with the underlying conclusions leading to the need for making the calculation. Much work remained after go-live to incorporate features and capabilities intentionally deferred in order to accelerate the go-live data. For reasons similar to those we applied to pre-go-live work, we do not challenge the wisdom of those deferrals under the circumstances. The direct work required to introduce those capabilities would have been required in any event, thus making the costs of that work appropriate, to the extent that it is eventually performed prudently. Nevertheless, a similar analysis of project management will eventually be appropriate, because post-go-live costs for capabilities excluded to advance go-live would have been avoided had the work been performed within the schedule that we determined ultimately supportable. We close with a number of observations about the net cost results that our conclusions support. First, even after assigning $2 million plus associated AFUDC to management’s responsibility, the remaining costs after netting from an essentially $30 million project still well exceed the top end of the range ($22 million) set forth by senior AAC leadership. Second, our approach effectively allowed a 36-month schedule, which is between 22 and 38 percent longer than the markers we used to set a reasonable baseline schedule. Third, we acknowledge the appropriateness (subject to their reasonable performance) of significant activities that remain to be performed due to their exclusion to support the go-live date that occurred in June 2015. August 8, 2016 Page IV-30 The Liberty Consulting Group