SOUTHERN AFRICA ENERGY PROGRAM Y2.02.07.01.REG: DEVELOPMENT OF REGIONAL KEY PERFORMANCE INDICATORS (KPIS) FOR RERA FINAL REPORT
November 26, 2018
DISCLAIMER This report is made possible by the support of the American People through the United States Agency for International Development (USAID). The contents of this report are the sole responsibility of Deloitte Consulting LLP and do not necessarily reflect the views of USAID or the United States Government. This report was prepared under Contract Number AID-674-C-17-00002.
ACRONYMS
Acronym Definition
ARENE Energy Regulatory Authority of Mozambique (Previously CNELEC)
CAIDI Customer Average Interruption Duration Index
CNELEC National Electricity Council of Mozambique (Now ARENE)
DSCR Debt Service Cover Ratio
Dx Distribution
EAF Energy Availability Factor
EBIT Earnings Before Interest and Tax
ECB Electricity Control Board of Namibia
ERB Energy Regulation Board of Zambia
EWURA The Energy and Water Utilities Regulatory Authority of Tanzania
Gx Generation
IRSEA Institute for the Regulation of Electricity Services of Angola
KPAs Key Performance Areas
KPIs Key Performance Indicators
LEWA Lesotho Electricity and Water Authority
LTIR Lost Time Injury Rate
MERA Malawi Energy Regulatory Authority
MW Megawatt
MWh Megawatt Hour
NERSA National Energy Regulator of South Africa
O&M Operational and Maintenance Cost
PCLF Planned Capability Loss Factor
PEL Planned Energy Losses
RED Regional Electricity Distributor
REG Reference Energy Generation
RERA Regional Electricity Regulators Association of Southern Africa
ROCE Return on Capital Employed
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RSI Recordable Safety Incident
SADC Southern African Development Community
SAEP Southern African Energy Program
SAIDI System Average Interruption Duration
SAIFI System Average Interruption Frequency
SAPP Southern African Power Pool
SERA Swaziland Energy Regulatory Authority
Tx Transmission
UCLF Unplanned Capability Loss Factor
UEL Unplanned Energy Loss
USAID United States Agency for International Development
USD US Dollar
XEL External Energy Loss
ZERA Zimbabwe Energy Regulatory Authority
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TABLE OF CONTENTS LIST OF TABLES ...... 4 LIST OF FIGURES ...... 5 1 EXECUTIVE SUMMARY ...... 6 2 BACKGROUND ...... 14 2.1 Scope of Work...... 14 2.2 Using KPIs to Gauge Utility Performance ...... 15 2.3 The Role, Mandate and Membership of RERA ...... 15 2.4 Focus Area for Performance Monitoring in Southern Africa ...... 16 2.5 Factors to Consider When Interpreting KPIs ...... 17 3 METHODOLOGY ...... 17 3.1 Identification and Selection of KPIs ...... 17 3.1.1 Criteria for KPI Selection ...... 18 3.1.2 Process for Developing a KPI Set ...... 19 3.1.3 Expected Impact ...... 20 3.2 Key Performance Indicator Framework ...... 20 3.2.1 Utility Key Performance Areas ...... 21 3.2.2 Utility Key Performance Indicators ...... 22 3.3 Approach for Collection of Data for Quantification of KPIs ...... 25 3.3.1 Utilities Surveyed ...... 25 3.3.2 Process Followed for Data Collection ...... 26 4 RESULTS ...... 26 4.1 Phase 1 Results – Developing the Priority KPI Set ...... 27 4.1.1 Outcome from the KPI Ranking Process ...... 27 4.2 Phase 2 Results – Quantifying KPI Set...... 30 4.2.1 Financial ...... 30 4.2.2 Customer Services ...... 38 4.2.3 Technical ...... 44 4.2.4 Safety ...... 52 4.2.5 Socio-Economic and Environmental ...... 54 4.2.6 Efficiency and Sustainability ...... 57 5 PROCESS AND TOOLS FOR MANAGING AND PUBLICIZING KPI DATA ...... 64 5.1 Process for Updating Top 30 KPIs ...... 64
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5.1.1 Process Ownership ...... 64 5.1.2 Intervals ...... 64 5.1.3 Reevaluation of Selected KPIs ...... 64 5.1.4 Governance Process for Change ...... 64 5.2 Process for Continued Data Collection ...... 65 5.2.1 Process Ownership ...... 65 5.2.2 Intervals ...... 65 5.2.3 Reevaluation of Selected KPIs ...... 65 5.3 KPI Toolkit ...... 65 5.3.1 KPI Selection and Evaluation Tool ...... 65 5.3.2 KPI Data Processing Tool ...... 65 5.3.3 Maturity Curve ...... 65 6 KPI MATURITY CURVE ...... 66 6.1 Purpose ...... 66 6.2 Maturity Dimensions ...... 66 6.3 Draft Maturity Curve ...... 67 6.4 Assessment of Current Status ...... 68 7 RECOMMENDATIONS ...... 69 7.1 Methodology of Top 30 KPIs...... 69 7.2 Collection of Data ...... 69 7.3 Maturing KPI Utilization ...... 69 7.4 Capacity at RERA ...... 70 8 CONCLUSION ...... 70 9 REFERENCES ...... 72 APPENDIX A – KPI DEFINITIONS ...... 73 APPENDIX B – PARTICIPATING REGULATORS AND UTILITIES ...... 75 APPENDIX C – SURVEY QUESTIONNAIRES ...... 76
LIST OF TABLES
Table 1: Performance Areas and Selected KPIs ...... 7 Table 2: KPI Survey Response Summary ...... 8 Table 3: List of Utilities that took part in the Survey ...... 26 Table 4: Utility Source Document and Reporting Period ...... 27
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Table 5: KPI Collectability Results ...... 28 Table 6: Top 30 Selected KPIs ...... 29 Table 7: 25 Secondary KPIs ...... 30 Table 8: Data Availability for Financial KPIs per Utility ...... 30 Table 9: Data Availability for Customer Service KPIs per Utility ...... 38 Table 10: Data Availability for Technical KPIs per Utility ...... 44 Table 11: Data Availability for Safety KPIs per Utility...... 52 Table 12: Data Availability for Socio-Economic and Environmental KPIs per Utility ...... 55 Table 13: Data Availability for Efficiency and Sustainability KPIs per Utility ...... 58 Table 14: Maturity Curve for the Effective Application of Regional KPIs ...... 67 Table 15: Guidelines for Interpreting Maturity Levels for Listed Dimensions ...... 68
LIST OF FIGURES
Figure 1: Dimensions of Power Utility Management ...... 7 Figure 2: Utility Profit/Loss Margin and Gearing Ratio ...... 9 Figure 3: Percentage of Population with Access to Electricity in Southern African Countries ...... 11 Figure 4: The Results of Energy Losses ...... 12 Figure 5: Approach for Identifying and Selecting KPIs ...... 18 Figure 6: KPA Focus Areas ...... 21 Figure 7: Financial KPA ...... 22 Figure 8: Customer Service KPA ...... 23 Figure 9: Technical KPA ...... 23 Figure 10: Safety KPA ...... 24 Figure 11: Economic and Environmental KPA ...... 24 Figure 12: Efficiency KPA ...... 25 Figure 13: National, Urban and Rural Access to Electricity ...... 56
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1 EXECUTIVE SUMMARY The objective of the USAID Southern Africa Energy Program (known as “SAEP” or “the Program”) is to increase electricity availability and access in Southern Africa. This is to be done by facilitating transactions and strengthening the enabling environment for public and private sector investment in the power sector. Mr. Elijah C Sichone, the Executive Secretary for the Regional Regulators Association of Southern Africa (RERA) asked SAEP to develop a set of Regional Key Performance Indicators (KPIs) that can be used for measuring regional utility performance. RERA, established by the Southern Africa Development Community (SADC), is an association of national regulators from the SADC region. RERA’s mission is to facilitate the harmonization of regulatory policies, legislation, standards and practices and to be a platform for effective cooperation among energy regulators within SADC. The national regulators have the responsibility to protect customers and improve service quality. Currently, KPIs used for purposes of performance monitoring are purely based on national objectives and priorities. RERA, with its regional mandate, aims to define a set of KPIs that can be used within the region to advance the provision of reliable electricity within Southern Africa.
The context of Southern Africa power utilities African utilities are grappling with long-standing challenges such as: • Inadequate generation capacity • Poor transmission infrastructure • Unskilled or low numbers of skilled workforce • Poor maintenance of existing power stations • Poor metering and billing systems resulting in unreliable supply • Inefficient technical performance • Inadequate financial sustainability These challenges are intensified by the changes in the power sector internationally, such as economic growth, shift in energy mix, changing role of customers, market restructure, smart utilities and renewable technology. To this end, RERA embarked on this activity to define the most important KPIs to quantify a comparable data set. Activity Phases The scope of work included six activities : 1. Mobilize and develop a baseline set of regional KPIs for initial stakeholder engagement and define Key Performance Areas (KPAs) and top KPIs for comparative analysis 2. Have a kickoff meeting with RERA to align on scope and get agreement to participate 3. Align key stakeholders on scope and participation 4. Conduct data survey and analyze results for selected utilities to test recommendations 5. Develop process and tools for managing and publicizing KPI data 6. Deliver KPI recommendations report to RERA The activity was executed in two phases: • Phase 1: The development of a KPI set, identifying the top 30 KPIs according to the national regulators
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• Phase 2: The quantification of the top 30 KPIs
During Phase 1, the focus was on identifying KPIs that are relevant in measuring and monitoring regional progress in the power utility sector. Through the use of a survey questionnaire, the national regulators selected an initial set of 30 KPIs to be used as a starting point for the establishment of a process that will measure and monitor progress on achieving regional objectives, as it relates to the power sector. Financial These KPIs were selected from a list of 55 KPIs. National regulators completed the data questionnaire Efficiency & Customer and returned it to RERA and SAEP for review and Sustainability service compilation of a set of top 30 KPIs. Balance KPI Set A set of 30 KPIs were derived based on the voting of national regulators, taking into consideration the Economic & Technical regulators’ assessment of the availability of data to Environmental quantify the KPI. These selected KPIs cover six important dimensions of power utility management Safety (i.e. financial, customer service, technical, safety, socio-economic and environmental and efficiency) Figure 1: Dimensions of Power Utility and are listed in the below table. Management
SUMMARY OF PERFORMANCE AREAS AND SELECTED KPIS
Dimension Performance Areas KPI Selected Considered
Financial Liquidity, Profitability, Solvency, Gearing, Profit/Loss Margin, Return on Capital Sustainability Employed, Staff Cost to Total Cost, Debt Service Cover Ratio, Operational Revenue to Total Cost, Total Operating and Maintenance Cost to Revenue
Customer Service Billing, Collections, Connections, Collection Rate, Collection Period, Connection Quality of service, Responsiveness Time Targets, Outages Due to Short Supply, Field Staff Response Time
Technical Distribution, Generation, SAIDI, SAIFI, CAIDI, EAF, BCLF, UCLF, System Transmission Minutes Lost >1
Safety Prevention Fatalities, Lost Time Injury Rate
Socio-Economic and Electrification, Generation Capacity Access to Electricity, Generation Capacity to Environmental Adequacy, Public Health, Resource Demand Utilization
Efficiency and Cost Management, Asset Operating Cost per MWh, Operating Cost per Sustainability Reliability, Capital Expansion, MW, Operating Cost of Electricity per MWh Energy Loss Reduction, Sustainability Table 1: Performance Areas and Selected KPIs During Phase 2, the national regulators provided data to quantify the selected KPIs. SAEP then engaged with the national regulators, clarifying uncertainties, following up on outstanding data and verifying data. A consultation process was followed to engage both RERA and the national regulators on the results
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from the survey. The RERA portfolio committee was also engaged during their scheduled portfolio committee meeting, where the initial results were shared with the committee. Results from the Survey Interpretation of KPIs The outcome of the survey brought a realization that the availability of KPI-related information is limited, and that a structured process will need to be followed to mature the information to the point where maximum benefit can be derived from it. This led to the development of a maturity framework to guide the process subsequent to this activity. Eleven utilities were invited to participate in the survey of which nine responded. The below table gives an overview of responses received. A more detailed description of the responses follows in the main body of the report.
Number of utilities Number of KPIs for Number of missing Dimension measured that provided data dimension data points Financial 9 7 1 Customer service 9 5 14 Technical 7 7 11 Safety 6 2 3 Economic and environmental 7 2 1 Efficiency and sustainability 9 6 17 Table 2: KPI Survey Response Summary The KPIs within a performance area need to be interpreted as a set within that performance area to provide a balanced view of performance. It will also require an accumulation of data over time to show data trends that are needed to fully interpret performance results. Performance areas cannot be managed in isolation due to their interconnected nature. For example, lower capital investment can improve return on capital but compromise quality of supply; or a focus on cost reduction can improve profitability but compromise safety. It is also important to consider the geographic, political, socio-economic and environmental conditions within which a utility operates and its size when interpreting its performance relative to other utilities. Results Relating to Financial Dimension Nine of the utilities that were surveyed provided information. The responses and quality of information received for the Financial Dimension were the most complete of all six dimensions surveyed with 99% of required information being available. In addition, due to most information being published in the utilities’ annual reports, where necessary, SAEP was able to complement the data with information from these reports. An analysis of the data relating to the Financial dimension indicates that in most of the performance areas (i.e. liquidity, profitability, solvency and cost levels) there are utilities operating at levels that indicate a lack of financial sustainability. These findings are aligned with the 2016 World Bank Report which indicated that only two of the 39 utilities surveyed had cost reflective tariffs that will lead to challenges relating to the utilities’ financial sustainability and ultimately lead to an inability to fulfill their roles to supply electricity.
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The graphs below reflect the profit/loss margin and the gearing ratio, both indicators of financial sustainability, per utility. The reporting periods of the utilities differ. Section 4 of this report shows the reporting period for each utility used. Utilities with high gearing ratios and low profitability are at risk of not being able to meet their financial commitments.
Figure 2: Utility Profit/Loss Margin and Gearing Ratio Source: SAEP KPI survey and utility annual reports
Results Relating to Customer Services Dimension Nine of the utilities that were surveyed provided information. The availability of information for the Customer Services Dimension data inputs was 69%. SAEP was able to extract some additional information from the published utilities’ annual reports. The data points that were not reported mostly relate to a lack of systems to collect the data throughout the year. New technologies and customer experiences in different industries translates into customer expectation within the power utility industry demanding new and improved services. Utilities need to relook their business models to become more customer-centric. Therefore, monitoring customer service delivery on a continual basis becomes essential for meeting customer service expectations; a key focus “Technology push” and “customer pull” for regulators. The KPAs are billing, collections, are converging to reshape the way in connections, quality of service and responsiveness. which energy is supplied, consumed and Limited information is available with regards to managed. Companies are recognising that customer services performance areas. The strategies that worked historically are not measurement and monitoring of KPIs – leading to an likely to satisfy future requirements. appreciation of customers’ service experience – will Sasha Weintraub (Senior Vice President – require significantly more focus to raise it to a level Customer Solutions, Duke Energy) where regulators will be able to use customer feedback for utility regulation.
Results Relating to Technical Performance Dimension Seven of the utilities that were surveyed provided information. The availability of information for the Technical Performance Dimension data inputs was 78%. The data points that were not reported mostly relate to a lack of systems to collect the data throughout the year. The technical performance indicators such as System Average Interruption Duration (SAIDI), System Average Interruption Frequency (SAIFI), Customer Average Interruption Duration Index (CAIDI), Energy Availability Factor (EAF), Planned
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Capability Loss Factor (PCLF) and Unplanned Capability Loss Factor (UCLF) will reflect the adequacy of investment and asset maintenance practices of utilities. Regulators should find the optimal balance between investment required and maintenance spent, given the financial challenges that most Southern African power utilities experience due to the countries’ economic constraints. Plant and network performance are key in delivering reliable and cost-effective electricity. The manner in which the plant and networks are planned, designed, constructed and maintained directly impacts the quality and continuity of supply delivered by power utilities, which impact on the current state and future development of the economy. There is currently limited monitoring of technical performance and its impact on customers. The development of processes and systems to collect the data needed will require specific focus from both the regulators and the utilities. Results Relating to Safety Performance Dimension Six of the utilities that were surveyed provided information. The availability of information for the Safety Performance Dimension data inputs was 75%. The data points that were not reported mostly relate to a lack of systems to collect the data throughout the year. Safety is an important aspect of utility management. A focus on Power utility workplace risk safety performance indicators can contribute towards creating a Workplace risks are high and safer and healthier working environment. Currently, few utilities include factors such as: publish their safety indicators. • Working long hours under In managing the safety aspect of the utility, recordable safety harsh conditions incidents and the Lost Time Injury Rate (LTIR) are generally • Exposure to high voltage in accepted as leading indicators for fatalities and should therefore be handling power outages, monitored and analyzed for the development of safe work • Working from heights procedures. Requiring continuous management and regulatory focus on safety Utilities experience continuous pressure to reduce cost in a drive to become more efficient, together with a drive to reduce the duration of supply interruptions. Safety is an important aspect to measure when increased focus is placed on KPIs such as System Average Interruption Duration (SAIDI) and operating cost. Results Relating to Socio-Economic and Environmental Performance Dimension Seven of the utilities that were surveyed provided information. The availability of information for the Socio-Economic and Environmental Performance data inputs was 71%. The data points that were not reported mostly relate to a lack of systems to collect the data throughout the year. The KPAs in the socio-economic and environmental performance dimension are electrification, generation capacity adequacy, public health and resource utilization.
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It was reported in 2017 that 143 million Access to electricity (% of population) [Source: World households in Southern Africa do not have Bank, Sustainable Energy for all] access to electricity (International Energy Agency). Utilities in Southern Africa are already under financial pressure and efforts to Angola Malawi 11% 41% increase access to electricity will only add to Zambia 27% that pressure. As such, electrification plans Madagascar Zimbabwe 23% will require careful planning by national Namibia 38% 52% governments, and the regulators will have to Botswana Mozambique 61% consider electricity prices in the context of 24% affordability and the additional capital and eSwatini 66% maintenance requirements. In planning for South Africa increased access, solutions such as mini-grids 84% Lesotho 30% and off-grid electrification should be considered. Figure 3: Percentage of Population with Access to Electricity It is important to monitor progress with in Southern African Countries regards to electrification rates as it will indicate the additional generation and network capacity needed, future funding requirements and impacts on electricity prices. Results Relating to Efficiency and Sustainability Performance Dimension Nine of the utilities that were surveyed provided information. The availability of information for the Efficiency and Sustainability Dimension data inputs was 32%. The data points that were not reported mostly relate to a lack of systems to collect the data throughout the year. Although the percentage is low, it is largely due to the fact that the utilities are not segregating system losses between technical and non-technical losses. Efficiency in power utilities is an area that is under constant challenge from a wide range of stakeholders. Measuring and monitoring cost levels and cost trends are important focus areas for utilities and regulators respectively. Without clear indications about improved efficiencies and optimal performance levels both utilities and regulators will find it difficult to justify any price increases. Energy losses can easily become a major challenge leading to overloaded networks that result in damage to plants, causing disruptions of supply, unsatisfied customers and ultimately reduced profits through revenue losses and increased costs. Generation capacity planning requires long lead times. Monitoring the adequacy of generation – taking into consideration economic growth and the need for increased access to electricity – becomes important in ensuring that there is adequate supply to meet the electricity demand profile. The Southern Africa region recently experienced a period of generation supply shortage (in 2008) that led to
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load shedding in a number of the countries to a position today where surplus generation capacity is again available.
Loss of Energy Overloaded Damage to Disruption Dissatisfied revenue and losses networks plant of supply customers additional costs
Figure 4: The Results of Energy Losses The operating cost of electricity will vary between the different participating utilities due to the different parts of the value chain that they operate in and different technologies being used for power generation. Operating cost per MWh is available; however, utilities use different cost definitions and cost buckets. A manual that includes regionally agreed upon cost definitions and cost buckets should be developed to assist in having consistency of financial numbers. This will be particularly important for defining generation cost, transmission cost and distribution cost in a ring-fenced manner. Recommendations Methodology of Top 30 KPIs RERA should facilitate an annual process of reevaluation of the top 30 KPIs. The process should start by focusing on the role that electricity should play in the development of the region. This will guide the contribution that utilities should make and what national regulators should do to support utilities. The top 30 KPIs should then be assessed against the regional objectives to decide on which KPIs are the most appropriate for the next term. At the start of the reevaluation process, the key participants should be engaged in a workshop to be given an opportunity to align the KPIs to the regional focus of improving regionally sustainable electricity supply. This will also assist in onboarding participants through active participation and contribution. The workshop will facilitate an in-depth understanding for all participants on the rationale and objectives of the program. Furthermore, this will provide an opportunity through engagement to gain insights from other participants and draw on their experiences in their local environments. Collection of Data Once the top 30 KPI reevaluation process has been completed and national regulators have concluded on selecting utilities whose data will be submitted, a structured process should be followed to engage and onboard utility staff who will be responsible for providing required data. This process should start with a workshop where the regional objectives and the role that the monitoring of the selected KPIs will play in achieving these objectives are explained. A data collection manual should be developed prior to the start of the reporting period to ensure that the relevant processes and systems are in place at the utilities to collect the data. The responsible utility staff should be involved in setting up these processes and systems to ensure that data are compiled in a consistent manner in order to produce KPIs that are relevant and comparable.
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Improving the Effectiveness of Utilizing Selected KPIs The maturity framework as set out in this report should be used to guide and direct a holistic approach towards the further development and utilization of KPIs. This will serve as a basis for improved delivery and greater contribution from the electricity sector with a strong focus on achieving common regional goals. There are significant areas of process and system development that are required to mature the KPI process. New systems to measure and collect the underlying data should be developed and implemented at all the participating utilities, to ensure consistency and completeness of datasets. The system needs a complete business cycle before the benefit will be fully realized. The end goal of maturing the utility KPIs is (a) to develop benchmarked data, and (b) to understand the best practices which will result in greater regional performance and improved alignment of utilities, regulators and other stakeholders. Capacity at RERA It is recommended that RERA institutionalize the KPI data collection and reporting process and allocate resources to support this. In institutionalizing the process, RERA should consider the resource requirements (1) to support regulators and utilities in the application of the tools and processes required for data collection, (2) to mature the KPI process for maximum benefit, and (3) to coordinate the process of data collection and analysis, and the publishing of results and findings. Conclusion This RERA KPI activity initiated a process of standardizing a common comparative dataset that can be used within the region to measure and monitor agreed performance areas. This can be further used as a vehicle to cohesively work towards the achievement of common goals and objectives. During the delivery of this activity, an understanding was built of the available data processes and systems as well as the barriers to providing data for quantification of the KPIs. The understanding will be helpful during the next round of data collection to improve data consistency and availability. In order to sustain the work relating to the development and maturing of the KPIs, RERA should have a clear mandate and be supported by its members in this regard. Thereafter, it is recommended that RERA institutionalize the KPI data collection and reporting process and allocate resources to sustain this. National regulators and power utilities should also be supported by RERA in developing the necessary capacity to contribute and sustain the KPI development process. Support can be given through the facilitation of workshops that will assist to develop a greater understanding of the importance and benefit of KPIs, assist in increasing buy-in and participation from regulators and utilities and create a learning environment among participants. Additional support can be given through the development of a data collection manual. The manual will not only assist utilities in implementing the necessary and relevant processes and systems to collect the data but will serve to ensure that data are compiled in a consistent manner in order to produce KPIs that are relevant and comparable. In order to maximize the benefit from this work, it is recommended that a holistic approach be followed to mature the platform that is necessary to fully benefit from the KPIs and move towards benchmarking as a standard practice. The key steps to be taken should include:
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• An agreed set of regional KPIs that are accepted by the majority of the participants as important for industry progress monitoring • The development of an agreed regional regulatory framework within which regional industry development can be monitored • Build high level of trust amongst stakeholders, including participating utilities, national governments, SAPP and SADC and obtain alignment around the quantified KPIs • Ensure that the KPIs reflect a balanced view of the key sustainability areas for the region e.g. measure the management of financial, social and environmental risks, obligations and opportunities in a way that reflect long-term sustainability • For RERA as an association, to be effective, stakeholders should agree on a voluntary governance framework that will support the continued development and utilization of the KPIs for regional electricity supply industry development and monitoring Following through on the processes that have been started will benefit and contribute towards the success of the power utilities and regulators. This in turn will ultimately benefit the region by achieving regional/SADC goals. SAEP presented and discussed the results from this survey on 15 November 2018 at the RERA Conference that was held in Lilongwe, Malawi. The national regulators from Botswana and Zimbabwe indicated that although they have not participated in the survey this year, they want to be included and will work with RERA to provide comparative data. RERA will update the survey results once they have received the data.
2 BACKGROUND 2.1 SCOPE OF WORK One of SAEP’s objectives is to improve the commercial viability of utilities in targeted SADC countries. This activity falls within the ambit of improved commercial viability of utilities and addresses the need for technical assistance to support the design and implementation of KPIs for utilities in the Southern Africa region. The request for the development of a set of KPIs came from the Executive Secretary of the Regional Regulators Association of Southern Africa (RERA), Mr. Elijah C. Sichone, who is also the sponsor of the activity. The framework for the development of the KPIs and the targeted participants comprising the RERA members was discussed with Mr. Sichone to align on the approach and planned methodology. RERA will track the KPIs publicly and report KPIs across the region’s utilities. The objective of this task is to develop a set of regional KPIs for use by: • RERA and the national regulators within SADC for comparative utility performance • Utilities to identify areas for performance improvement A comparative view of performance will require a set of KPIs that are standardized and used throughout the region. The work under this activity will support the development of a set of relevant performance KPIs. The scope of work includes:
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• Mobilize and develop a baseline set of regional KPIs for initial stakeholder engagement and define KPAs and top KPIs for comparative analysis • Have kickoff meeting with RERA to align on scope and get agreement to participate • Align key stakeholders on scope and participation • Conduct data survey and analyze results for selected utilities to test recommendations • Develop process and tools for managing and publicizing KPI data • Deliver KPI recommendations report to RERA 2.2 USING KPIS TO GAUGE UTILITY PERFORMANCE RERA and national regulators have for some time expressed the need for the development of a comparative KPI set for implementation throughout the region. In this regard, the RERA Executive Secretary requested SAEP to assist RERA in the development of a comparative KPI set. The development of an agreed set of KPIs will serve as a tool to align stakeholders around goals, to create focus, and to provide a basis to quantify the measures of success and progress. KPIs can be defined and may vary, based on what is important at a company level, at national regulator level or at a regional level. This activity focuses primarily on what RERA defined as relevant at a regional level. The starting point for this activity was a discussion with RERA and a draft list of KPIs that was compiled by RERA. The relevance of KPIs is contextual. It needs to, from a utility perspective, link to what is important to the KPI owner/stakeholder and can change if the objective of the company changes. Some KPIs will usually remain relevant (e.g., profitability and solvency ratios). KPIs also enable organizations to assign clear accountabilities for performance that lead to overall improved performance within the organization. KPI information needs to be reliable, but not necessarily precise, as long as the users have an understanding of the assumptions made and the limitations relating to the data used. The context within which the data will be used needs to be understood by the data collectors and data processors, whilst the users of the results need to understand the data providers’ frame of reference. It is also important that the data definition and formula for calculating the KPI is clear. The source of the data needs to be known and auditable. Assumptions need to be communicated with an indication of the extent to which independent parties validated data. A KPI set, quantified by the use of credible data, provides a good basis for benchmarking performance and for the identification of best practices. For KPI’s to be relevant for stakeholders, it needs to focus on their goals and objectives. Visibility of cross-organizational KPIs provides for a learning environment where well-performing organizations can share their practices. 2.3 THE ROLE, MANDATE AND MEMBERSHIP OF RERA RERA was established in 2002 with the following objectives: • Capacity building and information sharing
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• Facilitation of electricity supply industry policy, legislation and regulations • Regional regulation cooperation RERA’s mission is to facilitate the harmonization of regulatory policies, legislation, standards and practices and to be a platform for effective cooperation among energy regulators within the SADC region. The following national regulators are RERA members: • Angola – IRSEA • South Africa – NERSA • Lesotho – LEWA • Tanzania – EWURA • Malawi – MERA • Zambia – ERB • Mozambique – CNELEC • eSwatini – SERA • Namibia – ECB • Zimbabwe – ZERA
Regulators are accountable for achieving intended outcomes such as protecting the consumers and improving service quality through the influence that they exert over the regulated utilities. A well- designed performance measurement framework is a framework that is aligned with the objectives that the regulator seeks to achieve. The performance measurement framework needs to be balanced to give a picture of what the utility achieves in all the important performance areas. The KPIs that were selected for the comparative dataset are aligned with what the national regulators saw as the most important measurements. The current activity focused on defining the most important KPIs and quantifying the dataset. The regulators are responsible to define the targeted performance levels against which the utilities will be measured. This will help stakeholders to understand what the regulator expects and the extent to which utilities are achieving the objectives. 2.4 FOCUS AREA FOR PERFORMANCE MONITORING IN SOUTHERN AFRICA Sustainable supply of electricity is a key issue in Southern Africa. This includes the capacity to generate, transmit and distribute electricity at a cost that is affordable for customers, yet financially viable for utilities. Access to electricity, in Southern Africa, remains low with a large number of households living without access to electricity. Continuous planning and monitoring of progress on how to achieve universal access remains important. Cost reflective tariffs is an important aspect in determining the financial sustainability of utilities. Cost reflective tariffs need to be based on prudent operations that include the effectiveness of the utility in both its investment decisions as well as its operations. KPIs that measure effectiveness of utilities and provide information relating to the cost of electricity are valuable in accessing a utility’s effectiveness. In the absence of cost reflective tariffs, funding new projects becomes problematic. Energy losses, both technical and non-technical losses, remain a challenge that, if not well-managed, will cause significant strain on the financial sustainability of the utility, causing damage to the plant due to overloading and lead to supply interruptions at a local level.
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Given the nature of the power utility business, safety will also be an important focus in considering a utility’s effectiveness. Attention needs to be given to implicit trade-offs being made between safe operations and cost reduction programs. 2.5 FACTORS TO CONSIDER WHEN INTERPRETING KPIs There are three main approaches that can be taken to interpret KPIs: 1. Approximations based on generally accepted norms – Although the “general accepted norms” offer simplicity, it is not necessarily applicable when applied to the specific environment in which is it used. 2. Peer group benchmarking – Using industry ratios can provide meaningful insight in company performance in relation to its competitors/peers. It does not, however, give recognition to justifiable deviations from industry norms due to locational variations. Therefore, KPIs will not necessarily indicate industry inefficiencies. 3. Observe trends in ratios over time – Trends provide the valuable insight of company performance over time and indicate whether the company is improving or deteriorating on specific aspects of its business. Given the above, the KPI sets can be selected and then used for regional decision-making or for understanding the relative performance of a utility in relation to its peers or the performance trends within a utility. When comparing KPIs amongst utilities, cognisance of differences between utilities due to factors such as utility size, national objectives, geographical markets and climate is required. Furthermore, the utilities may participate in different parts of the value chain based on their specific mandate, e.g. a transmission company will not include the cost of distribution whilst a distribution company will include all the upstream cost in the supply of electricity. The KPIs were selected based on the national regulators’ view of which aspects of performance need to be measured. However, the resultant measurements will be dependent on the availability of data. In some cases, financial indicators are mostly readily available, while in the other cases the selected KPIs will require the implementation of systems and processes to collect the data. The development of these systems and processes will require additional time for completion and until then the actual data points will be completely available. This does not, however, distract from the fact that these are important performance measurements.
3 METHODOLOGY 3.1 IDENTIFICATION AND SELECTION OF KPIS The overall approach was to first identify an initial set of KPAs and secondly identify the relevant KPIs for each KPA. After an initial meeting with RERA to obtain alignment on the initial KPAs and KPIs, RERA introduced SAEP members and the KPI activity to all the national regulators.
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The assistance was conducted in two phases and four steps. Phase 1 was to align with RERA and the national regulators on the KPIs. Phase 2 included the data survey, data validation and data publication. The overall approach is set out below:
•Identify an initial set of potential regional performance indicators. This includes an assessment of current KPIs used as well as additional KPIs that are required to give a more Develop KPI comprehensive performance overview set
•Comparative data will be collected through participation of RERA, regional regulators and utilities •Data for the development of the KPI set will be collected through the use of a survey. An Do data appropriate comparative performance survey system will be selected and formatted for data survey collection
•Data will be validated and normalized on a consistent basis through participation of RERA before being included in the comparative performance results report Validate data
•The final results will be published by way of a quantified comparative KPI data set Publish quantified data set
Figure 5: Approach for Identifying and Selecting KPIs The methodology to implement the approach was as follows: • Step 1: Develop a comparative performance questionnaire that is aligned with RERA and participating utilities • Step 2: Standardize the KPIs and data definitions • Step 3: Collect the comparative data through interfacing with the respective regulators and utilities • Step 4: Provide a comparative performance report that reflect the comparative performance results and recommendations regarding performance KPIs
3.1.1 CRITERIA FOR KPI SELECTION The criteria for the selection of KPIs included:
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• KPIs must be relevant to Southern African regulators and utilities – this was determined by initial discussions with RERA • The set of KPIs must provide a holistic view of the utility performance • Good quality data must be available for the selected KPIs based on confirmable facts • The KPI set should support regional regulatory decision-making and improved utility performance
3.1.2 PROCESS FOR DEVELOPING A KPI SET SAEP identified an initial set of 55 KPIs through discussion with RERA and a review of available KPI reports. The process for the development of the KPI set included a review of KPIs currently used by utilities and regulators in Southern Africa. KPIs that are reflective of a balanced performance monitoring approach were selected and discussed with RERA. The outcome of this process produced the initial KPI set. SAEP conducted a survey through the use of a survey tool that the SAEP team developed. RERA distributed the survey questionnaire (Appendix C) – including the initial KPI set – to the ten national regulators that are members of RERA. The national regulators ranked the KPIs on the following scale: • Critical • Very Important • Important • Nice to Have The national regulators also indicated for each KPI whether the data required for quantification of the KPI is available or not available and, if not available, whether it can be obtained. The ratings from the national regulators were weighted according to the following values:
Rating Weighting Critical 3 Very Important 2 Important 1 Nice to Have 0
Based on the weighted responses from those surveyed, the initial 59 KPIs were divided to form: • A primary KPI set that consists of the top 30 KPIs • A secondary KPI set consisting of KPIs ranked as either “Critical” or “Very Important” by the majority of the respondents, but were not amongst the top 30 KPIs
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3.1.3 EXPECTED IMPACT KPIs are used to align and focus stakeholders on specific targeted outcomes through the quantification of this outcome that then allows for measuring and monitoring of progress. The stated regional regulatory objectives of improving the regional reliability of electricity will directly benefit from a well- defined set of KPIs that can be used to monitor progress holistically. The selected KPIs represent a set of measures that focus on those aspects of utility performance that the regional regulators collectively considered to be the most critical for the current and future success of the region. Through the utilization of these KPIs, RERA will be able to create a regional focus that is aligned with the priority areas of the national regulators. In addition, KPIs can create a type of peer benchmarking within the region. It will allow regulators to see the present quality of performance from national utilities and with the use of KPIs, they can envision the performance that should be targeted. Regulators can guide utilities to become what they deem to be efficient through the process of managing, monitoring and analysis. Performance dashboards can be set up to facilitate the effective monitoring of regional progress relating to reliability of supply. This will facilitate in getting the right information to the right users at the right time to optimize decision-making, enhance efficiency and to accelerate results. 3.2 KEY PERFORMANCE INDICATOR FRAMEWORK The good practice guide for performance measurement by regulators, developed by the British National Audit Office, was used as a reference in developing the KPI framework. According to the National Audit Office (2015), characteristics of a good performance measurement framework include:
CHARACTERISTIC DESCRIPTION
Focused On the regulator’s aims and objectives. Any performance measures used should clearly map onto the regulator’s objective and priorities.
Appropriate To, and useful for, decision-makers within the organization, and meeting the needs of stakeholders outside the organization.
Balanced Giving a picture of what the organization is doing, covering all significant areas of work.
Robust For example, to withstand organizational and personnel changes.
Integrated With the organization’s business planning and management processes
Cost effective Balancing the benefits of performance information against the costs
The KPI framework, developed in conjunction with RERA, sets out the top 30 KPIs that were collectively considered the most critical within the six strategic KPAs of power utility management. The framework will assist regulators to monitor and evaluate the performance of utilities as well as to drive decisions in line with national and regional objectives.
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3.2.1 UTILITY KEY PERFORMANCE AREAS Six KPAs within power utilities were identified in order to guide a balanced KPI framework. The KPAs, which RERA agreed to, include important dimensions of power utility management, namely: • Financial • Safety • Customer Service • Social, Economic and Environmental • Technical • Efficiency and sustainability Specific focus areas were agreed on for each KPA as indicated in the diagram below. These guided the identification of the initial KPI set.
Figure 6: KPA Focus Areas
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3.2.2 UTILITY KEY PERFORMANCE INDICATORS National regulators were requested to prioritize the KPIs which they deemed the most critical. They were provided with KPIs that measured different performances for each KPA. However, when prioritizing, the regulators compared all KPIs across the board and were not restricted to prioritization within a particular category. Set out below is the initial KPI set that formed the basis for the national regulators to prioritize the KPIs:
Figure 7: Financial KPA
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Figure 8: Customer Service KPA
Figure 9: Technical KPA
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Figure 10: Safety KPA
Figure 11: Economic and Environmental KPA
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Figure 12: Efficiency KPA Together with the ranking of KPIs, national regulators indicated the availability of data required for quantification. Based on the weighted responses from those surveyed, a primary KPI set containing the top 30 KPIs was developed.
3.3 APPROACH FOR COLLECTION OF DATA FOR QUANTIFICATION OF KPIS The quantification of KPIs formed part of Phase 2 of this assistance. National regulators provided data to quantify the selected KPIs, after which SAEP worked together with the national regulators to clarify and verify the data.
3.3.1 UTILITIES SURVEYED The national regulators that form part of RERA had to select utilities from their respective country to be surveyed. The table below contains the selected utilities together with their role in the value chain as well as their size in terms of sales and revenue:
Utilities Role in Size (MWh Regulator Country Selected by Revenue (USD) Value Chain Sales) Regulator ECB Namibia NamPower Tx 4 157 000 435 953 100 ECB Namibia Erongo RED Dx 457 458 84 344 375 ECB Namibia CENORED Dx 216 420 41 188 352
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NERSA South Africa Eskom Gx, Tx, Dx 214 121 000 13 151 020 347 EWURA Tanzania TANESCO Gx, Tx, Dx Not available Not available ERB Zambia ZESCO Gx, Tx, Dx 14 770 000 868 245 660 LEWA Lesotho LEC Gx, Tx, Dx 410 724 72 833 930 MERA Malawi ESCOM Gx, Tx, Dx N/A 116 603 439 SERA eSwatini SEC Gx, Tx, Dx 1 058 000 134 174 121 Table 3: List of Utilities that took part in the Survey
3.3.2 PROCESS FOLLOWED FOR DATA COLLECTION The data collection process was designed with the national regulators as the primary sources of data from utilities.
The following steps were taken during the data collection process: 1. Data questionnaires were sent to the national regulators via the RERA office 2. National regulators completed the data questionnaire and returned it to RERA and SAEP 3. A database was compiled based on the information received. Regulators and utilities were engaged to provide missing information and to clarify uncertainties 4. The data was analyzed and data points that were outside of the norm were referred to the regulators to check on the accuracy of the data 5. The outcome was presented to the RERA portfolio committee for input. Information was updated based on portfolio committee feedback 6. The updated information was circulated to national regulators for review together with requests for specific comment 7. The information received was analyzed and compiled in a draft report for discussion at a RERA workshop 8. The final report was completed taking into consideration the outcome of the RERA workshop
Even though KPIs were selected based on priority and data availability, some of the data was not available for this report as systems were not in place within the utilities to gather the underlying information. Regardless, every effort was made to quantify the KPI set as thoroughly as possible. The process culminated in the analysis of the quantified KPI sets which are presented in Section 4 of this report.
4 RESULTS The quantified KPI measures that are set out in this section reflect information that was available at the time of drafting this report. Recommendations on how RERA and the national regulators can address the missing KPI data are set out in Section 6 of this report. The results in this section are based on information provided by the various regulators and utilities, as well as information obtained from the various utilities’ Integrated Reports and Annual Financial Statements. The quantification of the data set was not for a specific period as the participating utilities have different reporting periods. Rather, the information used was based on each utilities’ latest financial
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year-end for which annual financial statements were available. The table below indicates the reporting period from which information was provided: Utility Source Document For the Financial Year Ending on NamPower Annual Report 30 June 2017 Erongo RED Annual Financial Statements 30 June 2017 CENORED Annual Financial Statements 30 June 2017 SEC Annual Financial Statements 31 March 2017 Eskom Integrated Report and Annual Financial Statements 31 March 2017 LEC Annual Report 31 March 2017 ESCOM Annual Financial Statements 30 June 2017 TANESCO Reports not available 30 June 2017 ZESCO Integrated Report 31 December 2016 Table 4: Utility Source Document and Reporting Period 4.1 PHASE 1 RESULTS – DEVELOPING THE PRIORITY KPI SET Following the structure of the scope, this section sets out the results from Phase 1 and Phase 2 of the activity.
4.1.1 OUTCOME FROM THE KPI RANKING PROCESS The section below presents the results from the ranking process as performed by the national regulators surveyed. The regulators scored the KPIs in terms of importance, and assessed their ability to obtain the data required to quantify the KPI. Through this process the top 30 KPIs were identified and are shown below as “Primary KPIs” whilst the remaining 25 KPIs are shown as “Secondary KPIs”.
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4.1.1.1 Ranking of KPIs in Terms of Collectability An assessment of the collectability of the data for the selected KPIs formed part of the first survey of national regulators. The collectability results were as follows:
Ranking the KPIs in Terms of Collectability % of Votes
Available 60% Can be Collected 36% Cannot be Collected 4% None of the KPIs had more than 1 vote indicating that the KPI “cannot be collected”. Table 5: KPI Collectability Results
4.1.1.2 Primary KPIs Selected The KPI ranking process identified the following set of KPIs as the primary KPIs (i.e. top 30 KPIs by the national regulators surveyed).
Index Name Unit Financial 1 Gearing % 2 Profit/Loss % 3 Return on Employed Capital % 4 Staff Cost/Total Cost Ratio 5 Debt Service Cover Ratio 6 Operational Revenue to Operational Cost Ratio Total Operational and Maintenance Cost (O&M) 7 % Cost/Revenue Customer services 8 Customer Bill Collection Rate % 9 Average Debt Collection Period days 10 Number of Outages per Year Due to Supply Shortage # p.a. 11 Connection Installations Exceeding Time Targets % 12 Average Field Staff Response Time Hours Technical 13 System Average Interruption Duration (SAIDI) Minutes 14 System Average Interruption Frequency (SAIFI) Index 15 Customer Average Interruption Duration Index (CAIDI) Minutes 16 Energy Availability Factor (EAF) % 17 Planned Capability Loss Factor (PCLF) % 18 Unplanned Capability Loss Factor (UCLF) % 19 Number of Major Incidents >1 Minute # Safety 20 Number of Fatalities # 21 Lost Time Injury Rate Ratio
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Efficiency and sustainability Operating Cost of Electricity per MWh (Excl. 23 USD/MWh Depreciation, Excl. Finance Cost) Operating Cost per Megawatt Installed (Excl. 24 USD/MW Depreciation, Excl. Finance Cost) Operating Cost of Electricity per MWh (Incl. 25 USD/MWh Depreciation, Excl. Finance Cost) 26 System Losses % 27 Distribution Technical Energy Losses % 28 Distribution Non-Technical Energy Losses % Socio-Economic and Environmental 29 National, Urban and Rural Access to Electricity % 30 Generation Capacity/Demand Ratio Table 6: Top 30 Selected KPIs
4.1.1.3 Secondary KPIs Remaining The KPI ranking process identified the following set of KPIs as the secondary KPI set (i.e. those ranked as either “Critical” or “Very Important” by the majority of the respondents, but were not amongst the top 30 KPIs).
Index Name Unit Financial 1 Free Funds from Operations as % of Gross Debt % 2 Free Funds from Operations as % of Total Capital % 3 Quick Ratio Ratio 4 Tariff Settings and Adjustments Times p.a. 5 Cash Interest Cover Ratio (Before Capitalisation) Ratio 6 Gross Debt/EBITDA Ratio 7 Average Capital Expenditure to Net Asset Value Ratio Customer services 4 Meters per Meter Reader Ratio 5 Percentage of Bills Estimated % 6 Time Lag Between Meter Reading and Bill Dispatch Days 7 Unmetered Customers % 8 Replacement of Faulty Meters Days 9 Customers on Pre-Paid Metering % 10 Number of Transformer Failures per Year # p.a. 11 Connection Quotations Exceeding Time Targets % 12 Time to Quote - Run of Line Days 13 Customer Complaint Resolution Rate % 14 Complaints Escalated to the Regulatory Authority # Technical 15 Number of System Minutes Lost <1 Minute Minutes Safety 16 Number of High Potential Near Misses per Employee Ratio 17 Recordable Case Incident Severity Index Index
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Efficiency and sustainability 18 Replaced Transformers as % of Installed Transformers % 19 Replace Meters as a % of Installed Meters % 20 Meeting Project Time Commitments Weighted % project on time Weighted % project within 21 Build Within Project Budget budget 22 Transmission Non-Technical Losses % Socio-Economic and Environmental 23 Connectivity Potential # 24 Off-grid/On-Grid Demand Ratio 25 Specific Water Usage L/kWh Table 7: 25 Secondary KPIs 4.2 PHASE 2 RESULTS – QUANTIFYING KPI SET Set out below are the results from the data collection process. The results are documented for each of the six KPAs. An SAEP analysis of the results is added at the end each KPI sub-section.
4.2.1 FINANCIAL The key areas to monitor within the financial dimension of utility performance management are profitability, liquidity, solvency and financial sustainability. National regulators selected KPIs to measure the performance of these areas based on what they consider to be most important. The table below shows for which utilities and KPIs data was available for quantification of the KPIs.
DATA AVAILABILITY FOR FINANCIAL KPIS PER PARTICIPATING UTILITY
OPERA- RETURN STAFF TIONAL DEBT TOTAL PROFIT/ ON COST/ REVENUE/ GEARING SERVICE O&M COST/ UTILITY COUNTRY LOSS CAPITAL TOTAL OPERA- COVER REVENUE EMPLOYED COST TIONAL COST NamPower Namibia Erongo RED Namibia CENORED Namibia SEC eSwatini Eskom South Africa LEC Lesotho ESCOM Malawi TANESCO Tanzania ZESCO Zambia Data not available Data available Table 8: Data Availability for Financial KPIs per Utility
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4.2.1.1 Gearing
What is Gearing? 'Gearing' ratio refers to the fundamental analysis ratio of a company's level of long-term debt compared to its equity capital/capital employed. Why should it be measured?
This ratio serves as an indicator regarding the level of risk associated with the business.
How is the KPI calculated? Unit
Gearing = Long term liabilities / (Total Shareholders' Equity + Long Term Liabilities) %
Gearing %
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED Erongo RED NamPower -30% -20% -10% 0% 10% 20% 30% 40% 50% 60% 70% 80%
Interpretation
The Gearing Ratio should be considered in the context of return on assets, as returns are required to service debt including interest. Gearing provides an indication of the aggressiveness of the utilities' growth strategy funded through debt. LEC and ESCOM did not utilize gearing as the cash reserves exceeded their debt. Both ZESCO and Eskom has relatively high Gearing Ratios. In the absence of cost reflective tariffs, Gearing Ratios should be kept to a minimum. The norm for acceptable gearing ratios varies per industry, with heavy capital investment industries such as utilities traditionally being acceptable at higher levels. This was based on the notion that utilities are regulated monopolies and that the debt is less risky. Equity capital in the utility funding model is a critical element to provide a safety net to ensure that debt principle and interest can be repaid in events such as reduced sales volumes, lower sales prices, higher operating cost and worse plant technical performance. Gearing ratios higher than 50% is considered highly geared, between 25–50% considered the norm for well-established companies and less than 25% is typically considered low-risk by investors and lenders.
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4.2.1.2 Profit Margin
What is Profit/Loss Margin? 'Profit/Loss Margin' indicates to what extent the utility can have cost reflecting tariffs and keep control of investments, costs and bill payment.
Why should it be measured?
The profit/loss margin indicates how good a company is at converting revenue into profits available for shareholders.
How is the KPI calculated? Unit
Profit/Loss Margin = Net Profit After Tax and Interest/Total Revenue %
Interpretation The KPI measures the utility's ability to generate profit and value for shareholders. An indicator above zero, shows that the utility generated profit. The profitability of the utility will be limited through regulation. The profit/loss margin should be analyzed as a trend in utilities, rather than across industry. A lower profit/loss margin could not only be the result of tariff regulation or expense inefficiencies, but can vary significantly as a result of capital investment (reflected in depreciation and maintenance) and cost of debt (financing costs).
From a sustainability perspective, the utility's tariffs should allow for cost reflectivity. Given the asset intensity of utilities, they are vulnerable to tariffs that are set to cover mainly operating cost and not their fixed sunken cost.
Although the ZESCO profit margin is shown at 16% it is attributable to an income tax credit. The results for the year show a loss before tax of US $11.5 million that represent a margin of -1.7%
4.2.1.3 Return on Capital Employed
What is Return on Capital Employed?
'Return on Capital Employed' (ROCE) measures the profitability of the organization in relation to capital invested.
Why should it be measured ROCE gives an indication of how well a company is using its money to generate returns.
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How is the KPI calculated Unit ROCE = EBIT/(Total Assets - Current Liabilities) %
Interpretation ROCE compares earnings before interest and tax and capital employed, which is the capital employed by the company to generate profits. ROCE is especially useful when comparing the performance of companies in capital-intensive sectors. This is a good indicator of the financial performance for companies with significant debt. A higher ROCE indicates more efficient use of capital, whereas a lower ROCE indicates that the utility is not employing its capital effectively and is not generating shareholder value.
ROCE needs to be set at a level that compensates for borrowed as well as equity capital, as the return on borrowed capital is required to repay interest, while the return on equity compensates for the effect of inflation on the provision of funding for replacement of assets. The return on equity also allows for the accumulation of the required equity funding for expansion of capacity.
4.2.1.4 Staff Cost/Total Cost
What is Staff Cost/Total Cost? 'Staff Cost/Total Cost' measures the weight of staff costs in the cost structure of the utility. Staff costs are a major factor of utility profitability.
Why should it be measured? Staff costs are one of the major expenses in power utilities and therefore should be monitored carefully as it impacts profitability. This ratio can be used as a productivity indicator.
How is the KPI calculated? Unit Staff Cost/Total Cost = Total cost for permanent and contracted staff/Total operating cost, Ratio excluding primary energy cost
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Interpretation
Staff cost in relation to total cost can be used as a productivity indicator of the utility. A high percentage may indicate either staff inefficiencies or not enough finances are allocated to other operational expenditure. Variances among utilities may be attributable to technologies used, capital insensitivity and role within the value chain. Therefore, the trend should be monitored over time within each utility.
4.2.1.5 Debt service cover
What is Debt Service Cover? 'Debt Service Cover' (DSCR) refers to the amount of cash flow available to meet annual interest and principal payments on debt, including sinking fund payments.
Why should it be measured?
The DSCR is a measure of the cash flow available to pay current debt obligations. Lenders will assess a borrower's DSCR before making finance available or extending payment terms.
How is the KPI calculated? Unit
DSCR = Net Operating Income/Annual Debt Obligation (i.e. finance cost + principle Ratio payments)
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No data available for TANESCO
ESCOM has no long-term debt – ratio therefor not applicable
Interpretation
The DSCR is a measure of the cash flow available to service current debt obligation. A DSCR less than one indicates a negative cash flow, which means that the lender will not be able to service the debt without drawing on outside sources. Ratios above one, indicate that the operating income is greater than the debt obligation. The higher the DSCR, the less risk the utility has in defaulting on payment.
4.2.1.6 Operational Revenue to Operational Cost
What is Operational Revenue to Operational Cost? 'Operational Revenue to Operational Cost' measures the sustainability of cost levels and is indicative to the extent to which tariffs are cost reflective. Why should it be measured? This ratio will give insights into the profitability of the business. Calculating this ratio over a number of years, will give insight as to the trends in operational costs. Comparing this ratio to that of industry norms can potentially highlight inefficiencies. How is the KPI calculated? Unit
Operational Revenue to Operational Cost = Revenue (sales) generated from a company's day- Ratio to-day business activities excluding sale of assets/cost to generate the revenue
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Interpretation
This KPI measures the profitability of the utility. By comparing operational revenue with operational cost, it measures how the utility is able to cover its operational cost at the existing consumption and tariff levels. A ratio lower than one indicates that revenue does not cover operational cost. Calculating this ratio over a number of years, will give insight as to the trends in operational costs.
The World Bank Report (2009) used a Cost Recovery Ratio as a KPI that is similar to the Operational Revenue to Operational Cost Ratio, indicating a cost recovery ratio of between 33% and 174%, with only six of the 21 countries that responded, have tariffs that recover total cost.
4.2.1.7 Total O&M Cost/Revenue What is Total O&M Cost/Revenue? 'Total O&M Cost/Revenue' indicates the percentage of revenue reserved for operating and maintaining a plant.
Why should it be measured? If the allocation for plant operations and maintenance is inadequate, it may lead to under-maintained assets or under-resourced plant operations. Under-maintained assets will result in costly repairs in future. Under- resourced plant operations could lead to operating losses and/or safety compromises. How is the KPI calculated? Unit Total O&M/Revenue = Total cost to operate and maintain the plant/total revenue from the sale % of electricity
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Interpretation
The absolute amount allocated for operations and maintenance depends largely on the plant mix, the age of the plant, external environment proximity to coastal areas and the complexity of operations. This KPI should be monitored within the utilities with the focus on trends.
4.2.1.8 Observations Relating to Financial Dimension Utility financial information is generally available and credible due to the requirement to have audited annual financial statements. However, the annual financial statements are not prepared on a common basis across the region and the end of the financial year differs between utilities. Utilities’ published and audited financial statements do not disclose all the information required to populate the selected financial KPI data sets. Complementary processes will be required to obtain the missing data elements, especially for those numbers that are not included in the financial statements and that are therefore not freely available. Some utilities state their assets at revalued values, affecting some of the financial ratios. This impacts the financial ratios significantly and needs to be taken into consideration in the interpretation of KPIs. ROCE is a critical measure of financial sustainability. This survey reflects returns that are inadequate for financial sustainability. Although ROCE ratios are generally low within capital-intensive industries, such as power utilities, the low level of profitability with some utilities indicate a lack of cost-reflective pricing. This is not a financial sustainable manner to operate power utilities. From the Gearing Ratios it can be seen that whilst some utilities hardly use gearing in their funding approach, other utilities are over indebted leading to high financial risk. The DSCR – especially in highly geared utilities – is an important indicator of the utilities ability to meet its financial commitments. Given that some of the utilities are over extended in their borrowing capacity, this indicator should be monitored carefully.
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4.2.2 CUSTOMER SERVICES The areas within the scope of the customer services dimension of utility performance management are billing, collections, connections, quality of service and responsiveness, from which KPIs were selected to focus the utilities on what is currently considered most important. The table below shows for which utilities and KPIs data was available for quantification of the KPIs.
DATA AVAILABILITY FOR CUSTOMER SERVICE KPIS PER PARTICIPATING UTILITY
CUSTOMER AVERAGE # OF OUTAGES CONNECTION AVERAGE BILL DEBT PER YEAR DUE INSTALLATIO FIELD STAFF UTILITY COUNTRY COLLECTION COLLECTION TO SUPPLY NS EXCEEDING RESPONSE RATE PERIOD SHORTAGE TIME TARGETS TIME NamPower Namibia Erongo RED Namibia CENORED Namibia SEC eSwatini Eskom South Africa LEC Lesotho ESCOM Malawi TANESCO Tanzania ZESCO Zambia Data not available Data available Table 9: Data Availability for Customer Service KPIs per Utility
4.2.2.1 Customer Bill Collection Rate
What is Customer Bill Collection Rate? The 'Customer Bill Collection Rate' measures revenues that are considered collectable in relation to total electricity billed.
Why should it be measured?
The effectiveness of bill collection is critical to ensure adequate cash flow and the management thereof.
How is the KPI calculated? Unit
Collection Rate = (Revenue-Impairment of Debt)/Revenue %
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Customer Bill Collection Rate %
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED Erongo RED NamPower 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Interpretation The Customer Bill Collection Rate measures the effectiveness of the utility to collect payment of the amount that was billed to customers. Efficient customer bill collection is necessary to ensure adequate cash flow and financial management. This KPI should be used in conjunction with the average debt collection period KPI.
World Bank Report (2009) recommends that to improve billing and collections, estimated billings should be reduced through increased meters and the enforcement of disconnection for non-payment. This should be accompanied by setting targets and monitoring improvement over time.
Due to the ability of utilities to disconnect non-paying customers, combined with the customers’ dependency on continued supply, the collection rates for utilities are expected to be in the higher nineties.
4.2.2.2 Average Debt Collection Period
What is Average Debt Collection Period?
The 'Average Debt Collection Period' measures the time that it takes to collect revenue from electricity sales
Why should it be measured? The Average Debt Collection Period represents the average number of days between the date that the bill is issued and the date payment is received. Managing the number of days will be critical for cash flow management purposes.
How is the KPI calculated? Unit
Average Debt Collection Period = (Amount Owed by Trade Debtors/Annual Credit Sales) x 365 days
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Average Debt Collection Period Days
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED Erongo RED NamPower - 20 40 60 80 100 120
Interpretation
The Average Debt Collection Period measures the average number of days between the date a bill is issued and the date payment is received. Efficient customer debt collections are necessary to ensure adequate cash flow for financial management purposes. The fewer the number of days, the greater the collection efficiency.
Where debt collection periods were provided per customer category, the debt collection period was calculated by SAEP based on outstanding debtors at year-end divided by revenue per day as an approximate.
The World Bank Report (2009) shows the days to collect debt to vary between six days and 476 days with a mean collection time of 78 days for sub-Saharan countries.
4.2.2.3 Number of Outages per Year Due to Supply Shortage
What is Number of Outages Per Year Due to Supply Shortage? The 'Number of Outages per Year Due to Supply Shortage' measures continuity of power supply. Consumer dissatisfaction with service is often related to high level of outages. Outages can be caused by generation or network failures. Why should it be measured? This measures the performance and service quality of the utility from the perspective of the customer. Dissatisfied customers will seek alternative power solutions or show discontentment through delaying account settlements. How is the KPI calculated? Unit
# Outages Per Year Due to Supply Shortage = Recorded number of times where customers # p.a. were disconnected to keep the electricity network frequency stable
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Number of Outages per Year Due to Supply Shortage #/Yr.
ZESCO TANESCO ESCOM LEC No outages due to a lack of Eskom supply was reported by SEC respondents. CENORED Erongo RED NamPower 0 0 0 0 0 1 1 1 1 1 1
Interpretation A significant shortage of supply was experienced in Southern Africa during the period 2009 to 2013. Primarily driven by a shortage of supply from Eskom due to underperforming plants and delayed commissioning of new generation capacity – the shortage of supply also affected neighboring countries. Generation capacity has increased significantly over the last few years and will continue to increase due to aggressive renewable generation programmes and Eskom's new built program that have led to supply exceeding demand. This accounts for the absence of load shedding due to short supply.
It is known from media reports that there were outages during the reporting period, but it was not reported by the respondents. This is a critical KPI to measure and report as it reflects a significant aspect of the core deliverable of the power utility.
4.2.2.4 Connection Installations Exceeding Time Targets
What is Connection Installations Exceeding Time Targets? 'Connection Installations Exceeding Time Targets' measures the percentage of connections that exceeds the target that was set for time to connect. Why should it be measured?
This measure can highlight process and system inefficiencies for new installations.
How is the KPI calculated? Unit
Connections Installations Exceeding Time Targets = Connections Commissioned Later Than % Commitment Date/Total Connections Planned for the Year
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Connection Installations Exceeding Time Targets %
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED No data available for Erongo RED ZESCO, ESCOM NamPower 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Interpretation Connection times that exceed the targeted connection period causes significant customer dissatisfaction. Meeting contracted connection times are important for developers and new customers in planning their operations. Regulators will use this KPI to ensure service standards are met.
The World Bank Report (2009) acknowledges the importance of connecting customers within an agreed time. Although that report does not state the percentage of customers exceeding the agreed connection standard, it does give the time range for delayed connections, reporting delays to be between 7 to 98 days.
4.2.2.5 Average Field Staff Response Time
What is Average Field Staff Response Time? 'Average Field Staff Response Time' measures the average time that it takes from the field staff to respond to outages and start to work. Why should it be measured? High response times can be indicators of resource shortages or system inefficiencies. Furthermore, this measures the performance and service quality of the utility from the perspective of the customer.
How is the KPI calculated? Unit Average Field Staff Response Time = Total time from reporting of incident to time that field Hours staff arrives at site /Total number of field staff response requests
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Average Field Staff Response Time Hours
ZESCO TANESCO ESCOM Only data available for LEC Erongo RED and Eskom TANESCO SEC CENORED Erongo RED NamPower
0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Interpretation
This KPI measures the performance and service quality of the utility from the perspective of the customer. Average Field Staff Response Time measures the average time it takes from when the customer reports the incident to the time a field staff arrives on site. Slow response times may be impacted by factors such as resources available to respond to the challenge and the remoteness or the distance to travel.
4.2.2.6 Observations Relating to Customer Services Dimension There is a lack of data and insufficient information with regards to customer services and customer experiences available: • Technical team response times are measured by three utilities, of which one uses a differently defined indicator. An appreciation of the service delivery as experienced by customers is critical for regulatory purposes. To gain a stronger understanding of the customer service experience will require significantly more focus if it is to be raised to a level where regulators will be able to use customer feedback for utility regulation. • During the recent past, the shortage of generation supply caused extensive supply disruption that impacted customers’ perception of service delivery. The risk of national load shedding due the generation shortages decreased over the last few years due to increased generation capacity. It is expected that the generation capacity will continue to increase in relation to electricity demand, eliminating this as cause of customer dissatisfaction. • Debt collection is an important aspect of working capital management and also impacts customer relationships. Once out of control, it becomes difficult to normalize. The reported average debt collection appears high in relation to normal credit terms of between 15 and 30 days.
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• The ability of utilities to execute new connections within the contracted time is an important aspect in achieving the SADC regional development goals. The underlying causes for late connections should be understood and rectified through the involvement of all role players. • The supply restoration impacts significantly on customer satisfaction level. The lack of measurement of response times for field staff indicates a lack of customer focus. New technologies and customer experiences in different industries translates into customer expectation within the power utility industry demanding new and improved services. There are multiple technological developments that converge towards a different customer expectation including: • An expectation to be digitally connected via mobile connectivity and smart metering • To be offered greater choice of energy supply, products, services, payment options and ‘green’ choices • The ability to self-manage energy use through self-service, access to information and tools and guidance to manage energy usage • Better overall experience through one-on-one engagements With empowered consumers, utilities need to relook its business model to become more customer- centric. Therefore, monitoring customer service delivery on a continual basis becomes essential for meeting customer service expectations, a key focus for regulators.
4.2.3 TECHNICAL The areas within the scope of the technical dimension of utility performance management are generation plant performance, transmission network performance and distribution network performance. National regulators selected KPIs to measure the performance of these areas based on what they consider to be most important. The table below shows for which utilities and KPIs data was available for quantification of the KPIs.
DATA AVAILABILITY FOR TECHNICAL KPIS PER PARTICIPATING UTILITY
NO OF UTILITY COUNTRY SAIDI SAIFI CAIDI EAF PCLF UCLF MAJOR INCIDENTS > 1 MINUTE
NamPower Namibia Erongo RED Namibia CENORED Namibia SEC eSwatini Eskom South Africa LEC Lesotho ESCOM Malawi TANESCO Tanzania ZESCO Zambia Data not available Data available Not applicable Table 10: Data Availability for Technical KPIs per Utility
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4.2.3.1 System Average Interruption Duration (SAIDI)
What is 'System Average Interruption Duration (SAIDI)'?
SAIDI is defined as the average duration of interruptions for customers served during a specified time period.
Why should it be measured? SAIDI is a key component for measuring the non-availability of supply to customers. Non-availability of supply indicates the time, in minutes per annum, that customers on average did not have access to electricity from the grid. How is the KPI calculated? Unit
SAIDI = (Restoration time, minutes x Total number of customers interrupted)/Total number Minutes of customers served
System Average Interruption Duration (SAIDI) Minutes
ZESCO TANESCO No data available for ESCOM, ESCOM Erongo Red, CENORED LEC Eskom SEC CENORED Erongo RED NamPower 0 1000 2000 3000 4000 5000 6000 7000 8000
Interpretation Continuity of supply is an important aspect in measuring the quality of service to customers and SAIDI is a key measurement in this regard. The lack of continuity of supply data from the surveyed utilities might indicate a lack of regulatory focus on this important aspect in utility management. The measurement of trends in the regulated utility is therefore recommended. SAIDI may vary significantly from utility to utility depending on the network configuration and capital invested in the networks. The measurement of SAIDI requires that the customer's network link is accurately maintained and measured to reflect supply disruptions. Where these customers' network links are not in existence, establishing network connectivity and databases and systems to measure SAIDI will require long lead times.
The norm for SAIDI will vary depending on the network design for example, whether it is a radial line or constructed as a ring-feed and whether there is contingent capacity such as additional backup transformers built into the network.
4.2.3.2 System Average Interruption Frequency (SAIFI)
What is 'System Average Interruption Frequency (SAIFI)'? SAIFI describes the average number of times that a customer’s power is interrupted during a specified time period.
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Why should it be measured?
SAIFI is a reliability index and is measured in units of interruptions per customer.
How is the KPI calculated? Unit
SAIFI = Total Number of Customers Interrupted/Total Number of Customers Served Index
System Average Interruption Frequency (SAIFI) Index
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED No data available for ESCOM, Erongo RED Erongo Red, CENORED NamPower 0 5 10 15 20 25 30 35
Interpretation The reliability of supply is an important aspect in measuring the quality of service to customers and SAIFI is a key measurement in this regard. The frequency of interruptions of supply data from the surveyed utilities might indicate a lack of regulatory focus on this important aspect in utility management. The measurement of trends in the regulated utility is therefore recommended. SAIFI may vary significantly from utility to utility depending on the network configuration and capital invested in the networks. The measurement of SAIFI requires that the customer's network link is accurately maintained and measured to reflect supply disruptions. Where these customers' network links are not in existence, establishing network connectivity and databases and systems to measure SAIFI will require long lead times.
The World Bank Report (2016) shows that sub-Saharan countries' outages range from six to 407 per annum.
4.2.3.3 Customer Average Interruption Duration Index (CAIDI)
What is 'Customer Average Interruption Duration Index (CAIDI)'?
CAIDI is the weighted average length of an interruption for customers affected during a specified time period.
Why should it be measured?
CAIDI is a reliability index that calculates the average outage duration that any given customer would experience. Alternatively, CAIDI can be viewed as the average restoration time.
How is the KPI calculated? Unit
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CAIDI = Sum of Customer Interruption Durations p.a. / Total Number of Customer Minutes Interruptions
Customer Average Interruption Duration Index (CAIDI) Minutes
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED No data available for ESCOM, Erongo RED Erongo Red, CENORED NamPower 0 100 200 300 400 500 600 700
Interpretation CAIDI indicates the average duration of a sustained interruption that only the customers affected would experience per annum. The index differs from SAIDI in that only the total number of customer interruptions is used and not all the customers served. The interruption of supply to customers is an important aspect in measuring the quality of service to customers and CAIDI is a key measurement in this regard. The average length of interruptions to customers that were affected by a supply disruption is measured. The lack of supply data from the surveyed utilities might indicate a lack of regulatory focus on this important aspect in utility management. The measurement of trends in the regulated utility is therefore recommended. CAIDI may vary significantly from utility to utility depending on the network configuration and capital invested in the networks. The measurement of CAIDI requires that the customer's network link is accurately maintained and measured to reflect supply disruptions. Where these customers' network links are not in existence, establishing network connectivity and databases and systems to measure CAIDI will require long lead times.
4.2.3.4 Energy Availability Factor (EAF)
What is 'Energy Availability Factor (EAF)'? 'Energy Availability Factor' measures power station availability, taking account of energy losses not under the control of plant management and internal non-engineering constraints Why should it be measured? The availability of a power plant varies greatly depending on the type of fuel, the design of the plant and how the plant is operated. The EAF measurement is an efficiency measurement.
How is the KPI calculated? Unit EAF (%) = (REG - PEL - UEL - XEL) / REG x 100: ((Reference energy generation for the period - Total planned energy losses - Total unplanned energy loss - Total external energy losses % (beyond the plant management control))/ Reference energy generation for the period) x 100
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Energy Availability Factor (EAF) %
ZESCO TANESCO ESCOM LEC Eskom SEC No data available for SEC CENORED Erongo RED Data not applicable to ESCOM, Erongo RED, CENORED NamPower 0% 20% 40% 60% 80% 100% 120%
Interpretation EAF is the percentage of time the plant is able to produce electricity over a certain period. Energy availability is expected to vary between technologies, and utilities with different technology mixes can therefore not necessarily be compared. Energy availability is influenced by the age of the plant. It is therefore recommended that trends in EAF be the focus rather than the absolute percentage. In interpreting the EAF, due consideration is required regarding the percentage of planned maintenance to sustain the production capacity of the plant.
EAF varies by technology and age of plant. The International Atomic Energy Agency reported an average EAF of 84% over a two-year period for nuclear reactors over 30 countries and 460 reactors, whilst the World Energy Council reported an average of 86% EAF for North American coal utilities over a five-year period.
4.2.3.5 Planned Capability Loss Factor (PCLF)
What is 'Planned Capability Loss Factor (PCLF)'? 'Planned Capability Loss Factor' measures energy losses due to outages that are considered planned when a power station unit has to be taken out of service and it is scheduled at least four weeks in advance.
Why should it be measured?
PCLF measures energy loss during the period because of planned shutdowns.
How is the KPI calculated? Unit PCLF (%) = PEL / REG x 100: (Total Planned Energy Losses for the Period /Reference Energy % Generation for the Period) x 100
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Planned Capability Loss Factor (PCLF) %
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED No data available for ZESCO, SEC Erongo RED Data not applicable to ESCOM, Erongo RED, CENORED NamPower 0% 2% 4% 6% 8% 10% 12% 14%
Interpretation
Planned maintenance is an important aspect of sustaining power plant production capacity. The level of planned maintenance is often linked to the plant maintenance life cycle that requires major maintenance outages on a cyclical basis. In assessing the adequacy of planned maintenance, due consideration should be given to maintenance policies and procedures. The key consideration should be the execution of adequate maintenance that will vary from utility to utility. The measurement is therefore planned maintenance executed versus planned maintenance required.
4.2.3.6 Unplanned Capability Loss Factor (UCLF)
What is 'Unplanned Capability Loss Factor (UCLF)'?
'Unplanned Capability Loss Factor' measures energy losses due to outages that are considered unplanned when a power station unit has to be taken out of service and it is not scheduled at least four weeks in advance.
Why should it be measured?
UCLF measures the lost energy due to unplanned energy losses resulting from equipment failures and other plant conditions. The measurement will highlight plant and operational inefficiencies.
How is the KPI calculated? Unit UCL (%) = UEL / REG x 100: (Total Unplanned Energy Losses for the Period /Reference % Energy Generation for the Period) x1 00
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Unplanned Capability Loss Factor (UCLF) %
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED No data available for ZESCO, SEC Erongo RED Data not applicable to ESCOM, Erongo RED, CENORED NamPower 0% 2% 4% 6% 8% 10% 12%
Interpretation
Unplanned capability losses indicate the level of plant and operational inefficiencies. This measure will focus management's attention on aspects of plant operations and maintenance to increase the availability of the plant and thereby contribute towards the overall effectiveness of the utility. Unplanned capability losses put continuity of supply at risk and should therefore be a key focus area for regulators.
4.2.3.7 Number of Major Incidents >1 Minute What is 'Number of Major Incidents >1 Minute'?
A major incident is an interruption with a severity ≥ 1 system minute.
Why should it be measured? 'Number of Major Incidents >1 Minute' measures the performance and service quality of the utility from the perspective of the customer.
How is the KPI calculated? Unit
Number of Major Incidents > 1 minute = (Duration of Outage x Customer Capacity Affected) / # Total Customer Capacity
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No. of Major Incidents >1 Minute #
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED No data available for ZESCO, Erongo RED ESCOM, LEC, SEC, CENORED NamPower 0.00 1.00 2.00 3.00 4.00 5.00
Interpretation This measure is often used at a transmission level; however, it can also be applied at a distribution level. One system minute lost is equivalent to switching off the entire supply area for one minute, due to a singular event. Major transmission failures do not only disrupt customer operations, but also pose a risk to the stability of the power system. The lack of data from the surveyed utilities might indicate a lack of regulatory focus on this important aspect in utility management. The measurement of trends in the regulated utility is recommended.
The norm for major incidents is largely determined by the system design, for example, the availability of transmission circuit lines that allows for back feed and backup transformers, together with the operational environment, for example, severity if weather conditions.
4.2.3.8 Observations Relating to Technical Performance Dimension The observations relating to the technical performance of the utilities have been limited by either the role that the utility fulfils within the value chain or the information available for the KPI. • Some of the utilities surveyed are transmission and/or distribution utilities only and, as such, will not necessarily be measured on all the aspects of the value chain. • There is limited monitoring of network performance and its impact on customers. This is a critical aspect to measure in order to understand the customer service experience. The development of processes and systems to collect the data required for the monitoring of technical network performance will require specific focus from both the regulators and the utilities. It will also require an allocation of resources. The development of the processes and the systems will require time to mature, as in addition to the development of systems, network configuration and customer network connection details need to be in place in order to produce the KPIs. • There is insufficient technical monitoring to have a holistic understanding of the utilities’ technical performance. Technical performance should be measured and monitor to ensure utilities fulfill their mandates. The quality and continuity of supply delivered by power utilities have an impact on the current state and future development of the economy.
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4.2.4 SAFETY The areas within the scope of the safety dimension of utility performance management are fatalities and injuries, from which KPIs were selected to focus the utilities on what is currently considered most important. The table below shows for which utilities and KPIs data was available for quantification of the KPIs.
DATA AVAILABILITY FOR SAFETY KPIS PER PARTICIPATING UTILITY
NUMBER OF LOST TIME UTILITY COUNTRY FATALITIES INJURY RATE NamPower Namibia Erongo RED Namibia CENORED Namibia SEC eSwatini Eskom South Africa LEC Lesotho ESCOM Malawi TANESCO Tanzania ZESCO Zambia Data not available Data available Table 11: Data Availability for Safety KPIs per Utility
4.2.4.1 Number of Fatalities What is 'Number of Fatalities'? 'Number of Fatalities' is the number of employees that died during the business year while performing work- related activities.
Why should it be measured?
The power utility industry is a high-risk work environment and unless safety standards are focused on and managed could lead to fatalities.
How is the KPI calculated? Unit
Number of Fatalities = # of Work-Related Deaths recorded during the business year #
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Number of Fatalities #
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED No data available for Erongo RED ESCOM, SEC, CENORED NamPower 0 2 4 6 8 10 12
Interpretation
Health and safety are a key concern of power utilities given the nature of the work. The monitoring of the rate of fatalities will inform safety standards and practices or could highlight specific areas of concern.
4.2.4.2 Lost Time Injury Rate
What is 'Lost Time Injury Rate' (LTIR)? LTIR measures the number of incidents where an employee, as result of the injury or disease during the execution of work-related activities, is unable to continue with all the normal duties on the next day or shift, as verified by a medical practitioner in relation to total hours worked for the period. Why should it be measured?
Monitoring the rate of lost time injury will highlight possible inefficiency and can inform safety standards and practices.
How is the KPI calculated? Unit
LTIR = (Recordable Cases x 200 000)/Number of Employee Hours Worked Ratio
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Lost Time Injury Rate Ratio
ZESCO TANESCO ESCOM LEC Eskom No data available for ZESCO, TANESCO, SEC ESCOM, LEC, SEC, CENORED, Erongo RED CENORED Erongo RED NamPower 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00
Interpretation
The LTIR is an important indicator relating to safety management. The lack of information on safety performance might indicate a lack of management attention to this important aspect of utility management.
The UK Association for Energy Suppliers and Generators reported the LTIR results for the period 2010 to 2016 with a high of 0.15 and a low of 0.06 per 100,000 hours during the period. The statistics include between 37 and 61 stations and cover all technologies.
4.2.4.3 Observations Relating to Safety Performance Dimension Safety is an important aspect of utility management. A focus on safety performance indicators can contribute towards creating a safer and healthier working environment. Currently, few utilities published their safety indicators. In managing the safety aspect of the utility, Recordable safety incidents (RSIs) and the LTIR are generally accepted as a lead indicator for fatalities and should therefore be monitored and analysed for the development of safe work procedures. Some of the participating utilities published the number of RSIs, but do not express it as a ratio of hours worked. It will be helpful in interpreting safety trends if it is expressed in terms of total hours worked. Utilities experience continuous pressure to reduce cost in a drive to become more efficient, together with a drive to reduce the duration of supply interruptions. Safety is an important aspect to measure when increased focus is placed on KPIs such as SAIDI and operating cost.
4.2.5 SOCIO-ECONOMIC AND ENVIRONMENTAL The areas within the scope of the socio-economic and environmental dimension of utility performance management are electrification, generation adequacy, public health and resource utilization, from which KPIs were selected to focus the utilities on what is currently considered most important. The table below shows for which utilities and for which KPIs data was available for quantification of the KPIs.
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DATA AVAILABILITY FOR SOCIO-ECONOMIC AND ENVIRONMENTAL KPIS PER PARTICIPATING UTILITY
NATIONAL, URBAN UTILITY COUNTRY AND RURAL ACCESS GENERATION TO ELECTRICITY CAPACITY/DEMAND NamPower Namibia Erongo RED Namibia CENORED Namibia SEC eSwatini Eskom South Africa LEC Lesotho ESCOM Malawi TANESCO Tanzania ZESCO Zambia Data not available Data available Not applicable Table 12: Data Availability for Socio-Economic and Environmental KPIs per Utility
4.2.5.1 National, Urban and Rural Access to Electricity
What is 'National, Urban and Rural Access to Electricity'? 'National, Urban and Rural Access to Electricity' measures household electrification rate, including connection to the main grid and a local grid. This indicator might take into account off-grid connections. Why should it be measured?
This is an important indicator in the planning for future growth and universal access.
How is the KPI calculated? Unit 'National, Urban and Rural Access to Electricity' = (Total Households in the Country - Total Households Not Connected to the National or a Local Grid) / Total Households in the % Country) x 100
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Access to Electricity
ZESCO TANESCO ESCOM No data available for ZESCO, Eskom LEC Not applicable to NamPower (Namibia covered by REDs) Eskom SEC CENORED Erongo RED NamPower
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%
Access (% of population) World Bank 2016 % National, Urban and Rural Access to Electricity %
Figure 13: National, Urban and Rural Access to Electricity
Interpretation
'National, Urban and Rural Access to Electricity' gives an indication of future capital and operating cost to provide universal access to electricity. The financial impact of universal access should be considered in determining pricing policies and price levels. The comparative access percentage as published by the World Bank does not relate to the supply area of the utility but rather the country in which the utility is based. The KPI can be applied at a country level or to the supply area of a specific electricity distribution utility.
The World Bank online data indicates globally a 39% availability of electricity in low income households and a 99.4% availability in upper middleclass households. Malawi has one of the lowest rates at 11%. Given that access to electricity is of utmost importance for Africa's socio-economic development and that a lack of access is still dominant in SADC, this KPI needs to be carefully monitored and actions taken where progress is lacking.
4.2.5.2 Generation Capacity/Demand
What is 'Generation Capacity/Demand'?
'Generation Capacity/Demand' measures to what extent installed capacity meets demand. Demand equals actual demand plus demand from connected customers who cannot be served.
Why should it be measured?
This KPI will give an indication of unserved demand in relation to total supply available.
How is the KPI calculated? Unit
Generation Capacity/Demand = Total MW Installed Capacity / Total Country Peak Demand Ratio
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Generation Capacity/Demand Ratio
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED No data available for ZESCO Erongo RED Not applicable to ESCOM, CENORED, Erongo RED NamPower - 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6
Interpretation This KPI provides information about the level at which a country is self-sufficient in regards to generation or the level at which a utility is self-sufficient in providing electricity to meet the demand within its supply area. In utilizing this KPI, due consideration should be given to the difference between installed capacity and nominal capacity as well as capacity that should be reserved for operating safety margins, planned maintenance and unplanned outages. The quantum to be set aside for these factors will depend on the plant mix and the condition of the plants as well as the operating conditions.
This measure is similar to the measure that was reported in the World Bank Report (2009) that found that African countries' utilization of generation plants ranges between 23% and 94%.
4.2.5.3 Observations Relating to Socio-Economic and Environmental Performance Dimension The saturation of electrification connections provides an indication of future capital and operating funding requirements to provide universal access. As such, access to electricity is seen as an important KPI to monitor as it will influence future growth, future costs and indicate whether the drive for universal access to electricity in Southern Africa is progressing. The “Generation Capacity to Peak Demand” provides an indication of generation adequacy for the country and collectively for the region. This will need to be complemented with an indication of adequacy against the electricity demand profile.
4.2.6 EFFICIENCY AND SUSTAINABILITY The areas within the scope of the efficiency and sustainability dimension of utility performance management are cost management, capital expansion, asset reliability, energy loss reduction and sustainability, from which KPIs were selected to focus the utilities on what is currently considered most important. The table below shows for which utilities and KPIs data was available for quantification of the KPIs.
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DATA AVAILABILITY FOR EFFICIENCY AND SUSTAINABILITY KPIS PER PARTICIPATING UTILITY
DISTRIBU- DISTRIBU- OPERATING OPERATING OPERATING TION TION NON- COST OF COST PER COST OF SYSTEM TECHNICAL TECHNICAL UTILITY COUNTRY ELECTRICIT MEGAWATT ELECTRICIT LOSSES ENERGY ENERGY Y PER MWH INSTALLED Y PER MWH LOSSES LOSSES NamPower Namibia Erongo RED Namibia CENORED Namibia SEC eSwatini Eskom South Africa LEC Lesotho ESCOM Malawi TANESCO Tanzania ZESCO Zambia Data not available Data available Not applicable Table 13: Data Availability for Efficiency and Sustainability KPIs per Utility
4.2.6.1 Operating Cost of Electricity per MWh (Excluding Depreciation and Finance Cost)
What is 'Operating Cost of Electricity per MWh (Excl. Depreciation, Excl. Finance Cost)'?
'Operating Cost of Electricity per MWh' measures the cost efficiency of the organization
Why should it be measured?
Operating Cost of Electricity per MWh measures efficiency. It should include the cost of power generated internally and procured externally by the utility.
How is the KPI calculated? Unit
Operating Cost of Electricity per MWh = (Total operating cost - Depreciation)/MWh Sold USD/MWh
Operating Cost of Electricity per MWh (Excl. Depreciation, Excl. Finance Cost) USD/MWh
ZESCO TANESCO No data available for ESCOM ESCOM LEC Eskom SEC CENORED Erongo RED NamPower 0 20 40 60 80 100 120 140 160 180 200
Interpretation
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'Operating Cost of Electricity per MWh' measures the cost (in USD) of generating and/or procuring electricity by the utility. The absolute cost level per MWh will be influenced by the technology mix. Trends across the industry will give an indication whether the cost of electricity to the utility is relatively high or low. Furthermore, if the trends per utility are monitored over a period of time, changes in efficiencies may be detected.
4.2.6.2 Operating Cost per Megawatt Installed (Excluding Depreciation and Finance Cost)
What is 'Operating Cost per Megawatt Installed (Excl. Depreciation, Excl. Finance Cost)'? 'Operating Cost per MW Installed (Excl. Depreciation, Excl. Finance Cost)' measures the cost efficiency of the organization.
Why should it be measured? Distinct ways of generating electricity incur significantly different costs. Calculation of these costs can be made at the point of connection to a load or to the electricity grid.
How is the KPI calculated? Unit
Operating Cost per Megawatt Installed (Excl. Depreciation, Excl. Finance Cost)' = (Total USD/MW Operating Cost - Depreciation)/MW Installed
Operating Cost per Megawatt Installed (Excl. Depreciation, Excl. Finance Cost) USD/MW
ZESCO TANESCO ESCOM LEC Not applicable to ESCOM, LEC, Eskom CENORED, Erongo Red SEC CENORED Ring-fenced data for generation not Erongo RED available for ZESCO, SEC, NamPower NamPower
0 50000 100000 150000 200000 250000 300000 350000 400000 450000
Interpretation This KPI measures the cost efficiency of generation companies. The cost efficiency to generating electricity will vary significantly based on the technologies employed and the availability and condition of resources. This calculation is based on the total cost of the vertically integrated utility, as ring-fenced generation cost is not published nor made available. It is recommended that ring-fenced generation cost be used in this calculation in order for it to be more meaningful.
Trends need to be monitored per utility to measure efficiency changes over time.
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4.2.6.3 Operating Cost of Electricity per MWh (Including Depreciation, Excluding Finance Cost)
What is 'Operating Cost of Electricity per MWh (Incl. Depreciation, Excl. Finance Cost)'? 'Operating Cost of Electricity per MWh (Incl. Depreciation, Excl. Finance Cost)' measures the delivered cost of 1 MWh of electricity. Should include the cost of power generated internally and procured externally by the utility. The total operating cost is divided by the total number of energy units sold. Why should it be measured?
This KPI reflects the delivered cost of energy for consumers.
How is the KPI calculated? Unit Operating Cost of Electricity per MWh (Incl. Depreciation, Excl. Finance Cost) = Total USD/MWh Operating Cost/MWh Sold
Operating Cost of Electricity per MWh (incl. Depreciation, Excl. Finance Cost) USD/MWh
ZESCO TANESCO Data not available for ESCOM ESCOM
LEC Eskom SEC CENORED Erongo RED NamPower - 20 40 60 80 100 120 140 160 180 200
Interpretation
This KPI measures the cost per MWh of electricity delivered to consumers and reflects the overall competitiveness of the utility. The competitiveness of the utility will be influenced by the technology mix used in generation of electricity or the import price of electricity. The overall cost of electricity is an important input cost for consumers. It also sets a benchmark for cost recovery via tariffs
Trends need to be monitored per utility to measure efficiency changes over time.
4.2.6.4 System Losses
What is 'System Losses'? 'System Losses' measures the total losses and combined technical i.e. naturally occurring losses depending on system design and system usage and non-technical losses i.e. losses due to factors such as electricity theft, illegal connection, incorrect metering and inefficient collection processes. Why should it be measured? System losses represent a major cost factor and loss of revenue for a utility and even marginal improvements in system losses will contribute towards increased revenue and the profitability of the utility.
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How is the KPI calculated? Unit
System Losses = (((Total MWh measured at the Power Station Yard Outgoing Feeder + Total MWh Measured at Import point - Total MWh Measured at Export Point) - Total MWh % Sold)/Total MWh Measured at the Power Station Yard Outgoing Feeder + Total MWh Measured at Import Point - Total MWh Measured at Export Point)) x 100
System Losses %
ZESCO TANESCO ESCOM LEC Eskom SEC CENORED Erongo RED NamPower 0% 5% 10% 15% 20% 25% 30%
Interpretation This KPI reflects utilities' success in managing theft/illegal connections together with losses relating to system configuration and design. Total losses combine technical and non-technical losses. Energy losses will result in lost energy and revenue, decreasing the profitability and efficiency of the utility, and causing damage to plant due to overloading.
According to the World Bank Report (2009), the implementation of energy accounting has proven useful in reducing system losses. This should be accompanied by setting targets and monitoring improvement over time. According to this report, system losses typically range between 7% – 10% in developed countries, while they are about 30% – 50% in developing countries, with the most efficient utilities in the region reporting total system losses below 20%.
4.2.6.5 Distribution Technical Energy Losses
What is 'Distribution Technical Energy Losses'?
'Distribution Technical Energy Losses' measures losses that are naturally occurring losses that depend on the power systems used.
Why should it be measured? Technical losses are caused by network characteristics and the nature of the load flow during the delivery of electric energy. This KPI is an important indicator for a utility in considering alternatives to its current network characteristics and load flow.
How is the KPI calculated? Unit
Technical losses are determined through a calculation by the power system engineers taking % into consideration network design and network load
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Distribution Technical Energy Losses %
ZESCO TANESCO ESCOM LEC Eskom SEC Data not available for ZESCO, LEC, CENORED Eskom, SEC, CENORED, Erongo RED Erongo RED NamPower 0% 2% 4% 6% 8% 10% 12% 14% 16%
Interpretation
Technical losses are caused by network characteristics, the nature of the load flow during the delivery of electric energy and equipment (i.e. energy dissipated in the conductors and equipment used for distribution of power). Technical losses can be accurately calculated or estimated using load flow studies as long as network configuration and load flow data is available. An understanding of the quantum of technical losses can be valuable as a criterion in deciding on the total investment cost in order to minimize the net present value of the net investment in power systems.
4.2.6.6 Distribution Non-Technical Energy Losses
What are 'Distribution Non-Technical Energy Losses'? 'Distribution Non-Technical Energy Losses' measures losses that are due to causes other than naturally occurring losses that depend on the power systems used.
Why should it be measured?
This KPI indicates the quantum of energy losses that is under management's control.
How is the KPI calculated? Unit 'Distribution Non-Technical Energy Losses' = ((Total MWh Measured at the Point of Purchase - Total MWh Measured at the Point of Purchase x Technical Energy Loss %) - MWh Sold)/Total % MWh Measured at the Point of Purchase
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Distribution Non-Technical Energy Losses %
ZESCO TANESCO ESCOM LEC Eskom Data not available for ZESCO, LEC, Eskom, SEC, Erongo RED SEC
CENORED Erongo RED NamPower
0% 2% 4% 6% 8% 10% 12% 14% 16% 18% 20%
Interpretation
Non-technical losses relate to internal process issues (inaccurate billing information, defective meters, etc.) and external issues (electricity theft, tampering, etc.) and cannot always be directly measured but can be calculated. It is an important indicator of effectiveness in managing illegal connections, electricity theft and billing accuracy.
Special legislation to reduce electricity theft together with strict enforcements of laws has been found to be a very effective means to reduce system losses (World Bank Report, 2009).
4.2.6.7 Observations Relating to Efficiency and Sustainability Performance Dimension Efficiency in power utilities is an area that is under constant challenge from a wide range of stakeholders. Measuring and monitoring cost levels and cost trends are important focus areas for utilities and regulators respectively. Without clear indications about improved efficiencies and optimal performance levels, both utilities and regulators will find it difficult to justify any price increases. Energy losses, both technical and non-technical losses, remain a challenge. The impact of energy losses is not just limited to efficiency and financial sustainability of the utility. Energy losses can easily become a major challenge leading to overloaded networks resulting in damage to plants, causing disruptions of supply, unsatisfied customers and ultimately reduced profits through revenue losses and increased cost. Generation capacity planning require long lead times. Monitoring the adequacy of generation, taking into consideration economic growth and the need for increased access to electricity, becomes important in ensuring that there is adequate supply to meet the electricity demand profile. The Southern Africa region comes from a period of generation supply shortage in 2008 that led to load shedding in a number of the Southern African countries to a position where surplus generation capacity is again becoming available. The operating cost of electricity will vary between the different participating utilities due to the different parts of the value chain that they operate in and different technologies being used for power generation. Operating cost per MWh is available. However, utilities use different cost definitions and cost buckets.
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SAEP recommends that a regionally agreed manual for cost definitions and cost buckets be developed to assist in having consistency of financial numbers. This will be particularly important for defining generation cost, transmission cost and distribution cost in a ring-fenced manner.
4.2.6.8 General Comments Aspects such as customer satisfaction and network performance measure important dimensions of utilities. At this point there is inadequate measurement of these two aspects and therefore it will be worth the effort to collect the required data.
5 PROCESS AND TOOLS FOR MANAGING AND PUBLICIZING KPI DATA The purpose of this section is to set out a proposed process for sustaining the KPI data set and to describe the toolkit that is available to support the KPI selection and data collection process. 5.1 PROCESS FOR UPDATING TOP 30 KPIS
5.1.1 PROCESS OWNERSHIP RERA will be the process owner and will have the overall responsibility for the implementation of the regional comparative KPI data set as well as to work collaboratively with the national regulators. Successful application of the regional KPIs will require active support from the national regulators.
5.1.2 INTERVALS Given the nature of the information, it is recommended that the KPIs be collected on an annual basis. This will allow for a complete business cycle including the preparation and quality checks associated with the annual reporting process.
5.1.3 REEVALUATION OF SELECTED KPIS The KPIs should be reevaluated by taking into account: • The information regulators need to focus role players on the improvement of the electricity system reliability • The alignment between the KPIs, national priorities and regional priorities which will change from time to time • The assessment and benchmarking of utilities in SADC The abovementioned factors may require a change to the top 30 KPIs. Any changes to KPIs should be well-managed within a structured governance process.
5.1.4 GOVERNANCE PROCESS FOR CHANGE It is recommended that a structured governance process be developed within RERA to ensure continuity of data collection and continued relevance of the KPIs. This process should include the
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procedures to be followed in case of changes to the selected KPIs, and should also cover the quality control processes related to data collection and processing. 5.2 PROCESS FOR CONTINUED DATA COLLECTION
5.2.1 PROCESS OWNERSHIP Although RERA will have an important coordinative function, the key responsibility for the collection and submission of data lies with the national regulators. The national regulators will have the responsibility to interface with the utilities and to ensure that the data submitted is complete and accurate.
5.2.2 INTERVALS It is recommended that the regional publishing of comparative data be done on an annual basis. However, regional regulators may benefit from collecting the data on a more regular basis for own use and to ensure that the necessary processes and systems are developed and implemented.
5.2.3 REEVALUATION OF SELECTED KPIS The process of collecting data for newly selected KPIs needs to be considered by the national regulators. The affected utilities should be consulted as to ensure that the data can be collected, that the data is collected in a consistent manner and that the data can be published, when required. 5.3 KPI TOOLKIT Set out below are various tools to ensure KPI selection and evaluations are sustainable.
5.3.1 KPI SELECTION AND EVALUATION TOOL A database was created in Microsoft Excel to capture the results from the KPI selection survey and the collectability survey. Once the data provided by the regulators is captured in the database, reports are automatically generated to score the KPIs to provide a ranking from the highest to the lowest ranked KPI and also indicate the collectability of the corresponding data.
5.3.2 KPI DATA PROCESSING TOOL A database was created in Microsoft Excel to capture the information provided by the national regulators as well as data developed and collected by the activity office. Each KPI has a separate worksheet that draws the information from the database so as to generate the necessary graphs for interpretation of data. The sheets also contain definitions, formulas and provides space to capture commentary.
5.3.3 MATURITY CURVE A maturity curve was developed by SAEP. The purpose of the maturity curve is to set out a time-based framework to assist in setting up a platform to guide and support the development of sustainable KPIs under RERA. The following section sets out more detail on the structure of the maturity curve.
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6 KPI MATURITY CURVE 6.1 PURPOSE Based on the review and discussion of the KPI activity report at the RERA portfolio committee meeting on 30 May 2018 and follow-up discussions with the RERA Secretary, Mr. Elijah Sichone, it was decided to develop what is called a maturity curve, to indicate how the use of KPIs can be developed over time. The maturity curve for KPIs indicates a development path that allows for the progressive development of a KPI platform, moving from a position where the KPIs reflect national priorities, to a position where there is a fully matured set of KPIs that underpins efforts to improve regionally sustainable electricity supply. The KPI set will be considered fully matured once the systems and processes for collecting and processing the data are fully developed, implemented and produce credible information that enable decision making. The matured state will support the production of benchmark information and discovery of best practices. The development of a KPI set as an initiative on its own, without the platform required for sustainability, will not survive in the long-term. The maturity curve is intended to serve as a reference framework for RERA, national regulators and other stakeholders in developing the supporting platform. Based on the work done under the KPI activity, it is clear that there is a need for system and process development at utility level. This will take time and will require continued focus and stakeholder alignment. The maturity curve will be a useful reference document to keep the process on track and for the development of implementation milestones. 6.2 MATURITY DIMENSIONS For KPIs to be used effectively in monitoring progress in the industry, the platform within which the KPIs are applied should be conducive for such use. The key dimensions of such a platform include: • Regional KPIs – There should be an agreed set of KPIs that are accepted by the majority of the participants as important for industry progress monitoring. • Regional Regulation – The stakeholders should agree on the importance of developing a regional regulatory framework within which regional industry development can be monitored. • Stakeholder Perspective – Stakeholders should have a high level of trust in and alignment around the quantified KPIs, both as to the aspects that are monitored and the accuracy of the quantified KPIs. Stakeholders include participating utilities, national governments, SAPP and SADC. • Sustainability Focus – The KPIs should reflect a balanced view of the key sustainability areas for the region for example, measure the management of financial, social and environmental risks, obligations and opportunities in a way that reflect long-term sustainability. • Process Development Monitoring – For RERA as an association, to be effective, stakeholders should agree on a voluntary governance framework that will support the continued development and utilization of the KPIs for regional electricity supply industry development and monitoring.
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National regulators are mandated to collect data when a decision was taken to include a particular KPI. This requirement can also be included in the utilities’ license conditions. Based on the current survey, certain data points for regionally standardized KPIs are absent because of the lack of development and implementation of systems to collect the data. KPIs that require extensive data processing, such as the calculation of network performance KPIs, will only have full data sets available once the systems have been operationalized for a full year, as seasonal variations require actual data to be recorded throughout a full calendar year. 6.3 DRAFT MATURITY CURVE A draft concept for a regional maturity curve on the use of performance indicators is set out below. To interpret the maturity curve, the reader should look at the different dimensions in the far left column of the table which need to develop over time, and then to consider the level of maturity for each dimension that is required to be successful. The maturity curve table sets lists five dimensions and states the conditions for each dimension at each maturity level.
Table 14: Maturity Curve for the Effective Application of Regional KPIs
The following can be used as guidelines in interpreting the maturity levels for the listed dimensions:
Regional KPIs Diverse KPI Set Each regulator defines KPIs to be reported based on focus for the utility or the country Standardized National regulators agree on a common KPI data set to monitor industry progress for the region Credible Systems Credible systems are developed and implemented for capturing of KPI data input Consistent Data Credible processes exist to ensure that data are consistently classified and captured Benchmarked Data Consistent data sets are utilized do identify top performing organizations and assess best practices
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Regional Regulation National Focus National regulators focus exclusively on national objectives Regionally Aligned National regulators are aligned on the need to monitor regional industry progress Regional process Regulatory processes are calibrated to produce regionally agreed KPIs KPIs Linked to National regulators incorporate regionally agreed KPIs in regulated utilities performance Tariff Applications measures Monitored A regional regulatory process exists through the use of regionally agreed KPIs, to monitor Industry Progress and report on regional industry progress Stakeholder Perspective Misaligned with Stakeholders question the need for regional KPI and express reservations around selected Low Trust focus areas and accuracy of quantified KPIs Alignment on Stakeholders align on the regionally selected KPIs for monitoring industry progress Measures Trust in Systems Stakeholders view the systems used for data collection as credible Trust in Data Stakeholders view the data collected as credible Alignment with Stakeholders are aligned on the need for regional industry monitoring, the focus area for High Trust monitoring and have trust in the accuracy of the reported industry progress Sustainability Focus Ad Hoc Industry progress monitoring do not incorporate all key aspects of sustainability Balanced Key areas of regional industry sustainability are agreed on by national regulators and Sustainability Focus included in the areas to be monitored Systems Supported The methodology for assessing sustainability is agreed and systemized Data Supported The assessment of the level of sustainability is supported by credible data Long Term Industry progress monitoring incorporate all key aspects of sustainability Sustainability Process Development Monitoring Basic No specific governance process in place for regional industry progress monitoring Agreed National regulators agreed on a framework for governing regional industry progress Framework monitoring Annual Routines Fully developed annual routines to ensure continued governance are operational Regional Reviews Regional industry progress-related KPIs trends are periodically review and acted on by participating regulators Regional Sign-Off Full acceptance of the governance process and process output by all participating regulators Table 15: Guidelines for Interpreting Maturity Levels for Listed Dimensions 6.4 ASSESSMENT OF CURRENT STATUS This KPI activity focused on the development of the “Regional KPI-dimension” and has moved regional KPIs to Level 2 on the maturity curve and has quantified the data that is currently available. Although some processes are in place for data collection, based on the feedback from the national regulators, there is, in some cases, a need for utilities to implement new systems and processes to provide data. The remaining four dimensions namely Regional Regulation, Stakeholder Perspective, Sustainability Focus and Process Development Monitoring are assessed as being at Level 1. RERA will need to address these various dimensions through the implementation of agreed remedies. A maturity path needs to be agreed between the regulators and affected stakeholders. The role that national regulators will play in this is to support the process of maturing the KPI platform through active participation in the RERA technical and portfolio committees where this process will be governed.
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7 RECOMMENDATIONS Based on this assistance, which has provided a prototypical and robust approach to gauging regional utility performance, a number of recommendations have emerged which will impact the sustainability of the process as set out below: 7.1 METHODOLOGY OF TOP 30 KPIS It is recommended that RERA facilitate an annual process of reevaluation of the top 30 KPIs. It is further recommended that the process starts by focusing on the role that electricity should play in the development of the region. This will guide the contribution that utilities should make and what national regulators should do to support utilities. The top 30 KPIs should then be assessed against the regional objectives to decide on which KPIs are the most appropriate for the next term. At the start of the reevaluation process, key participants should be engaged in a workshop so as to be given an opportunity to align the KPIs to the regional focus areas. This will also assist in onboarding participants through active participation and contribution. The workshop will facilitate in- depth understanding for all participants on the rationale and objectives of the program. Furthermore, this will provide an opportunity, through engagement, to gain insight from other participants and draw on their experiences in their local environments. 7.2 COLLECTION OF DATA Once the top 30 KPI reevaluation process has been completed and national regulators have concluded on selecting utilities whose data will be submitted, a structured process should be followed to engage and onboard utility staff who will be responsible for providing the data. This process should start with a workshop where the regional objectives, and the role that the monitoring of the selected KPIs will play in achieving these objectives, are explained. It is recommended that a data collection manual be developed prior to the start of the reporting period to ensure that the relevant processes and systems are in place at the utilities to collect the data. Responsible utility staff should be involved in setting up these processes and systems to ensure that data is compiled in a consistent manner in order to produce KPIs that are relevant and comparable. 7.3 MATURING KPI UTILIZATION It is recommended that the maturity framework, as set out in this report, be used to guide and direct a holistic approach towards the further development and utilization of KPIs. This will serve as a basis for improved delivery and greater contribution from the electricity sector with a strong focus on achieving common regional goals. There are significant areas of process and system development that are required to mature the KPI process. It is recommended that new systems to measure and collect the underlying data be developed and implemented at all the participating utilities, to ensure consistency and completeness of data sets. These systems will need funding and will take time to develop. Once the systems are implemented, data
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sets collected through the system need a complete business cycle before the benefit will be fully realized. The end goal of maturing KPIs is to develop benchmarked data for the SADC region and to have a greater understanding of the best practices. This will result in greater regional performance and improved alignment of utilities, regulators and other stakeholders. 7.4 CAPACITY AT RERA RERA’s role in ensuring the sustainability of the KPI measurement and reporting process is crucial. RERA will need to develop the capacity and commitment to continue with the process of updating of KPIs and annual data collection. It is recommended that RERA institutionalize the KPI data collection and reporting process and allocate resources to support this. In institutionalizing the process, RERA should consider the resource requirements (1) to support regulators and utilities in the application of the tools and processes required for data collection, (2) to mature the KPI process for maximum benefit, and (3) to coordinate the process of data collection, processing the data and publishing the results.
8 CONCLUSION The objective of this assistance was, in collaboration with RERA and the national regulators, to define a KPI set that can be used to monitor progress in developing reliable electricity supply in the Southern African region and to collect data to quantify the selected KPIs. The activity resulted in an agreed KPI set consisting of 30 indicators, prioritized by the national regulators. This RERA KPI activity commenced as a process of standardizing a common comparative data set that can be used within the region to measure and monitor agreed performance areas. This can be a vehicle to cohesively work towards the achievement of common goals and objectives. During this activity, an understanding was developed among national regulators of the available data processes and systems and the barriers to provide KPI data for quantification of the KPIs. This will be helpful during the next round of data collection to improve data consistency and availability. The data required to quantify these KPIs is not available for some of the KPIs. Systems and processes will need to be implemented at some of the utilities to collect and process the data. In order to maximize the benefit from this work, it is recommended that a holistic approach be followed to establish the platform that is necessary to fully benefit from the KPIs and move towards benchmarking as a standard practice. In this regard, SAEP has developed a framework by way of a ‘maturity curve’ that can be used by RERA to put a platform in place for the further development of the KPI set. This will be done by RERA and national regulators focusing on key dimensions that need to be in place for sustaining the KPIs, such as ensuring that there are credible systems for data collection, the active utilization of the KPIs by national regulators, stakeholder alignment, a sustainability focus and adequate focus on developing the KPI process. In order to sustain the work relating to the development and maturing of the KPIs, RERA should be capacitated with adequate resources and skills to coordinate and drive this process. RERA should also have a clear mandate in this regard.
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National regulators and power utilities should also be supported in creating the necessary capacity to contribute and sustain the KPI development process. The robust and comprehensive process that has commenced under this SAEP assistance needs to move forward. It will benefit and contribute towards a more transparent and consistent measurement of the regional utility performance. It is also a vital input for national regulators. This in turn will ultimately benefit the region through achievement of regional (SADC) goals.
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9 REFERENCES CENORED Annual Report. 2017. Erongo RED Annual Report. 2017. ESCOM Malawi Annual Financial Statements. 2017. Eskom Integrated Report. 2017. International Energy Agency. 2017. Special Report: Energy Access Outlook. From Poverty to Prosperity. Lesotho Electricity Company Annual Report. 2017. Marr, B. 2014. 25 Need to Know Key Performance Indicators. Financial Times. Pearson. NamPower Annual Report. 2017. National Audit Office, 2016. Good practice guide. Performance measurement by regulators. Available online: www.nao.org.uk. Swaziland Electricity Company Annual Financial Statements. 2017. Energy UK, Health and Safety Statistics, 2017 Weintraub, S. in PWC. 2016. Customer Engagement in an Era of Energy Transformation. World Bank Report. 2007. Benchmarking Analysis of the Electricity Distribution Sector in Latin America and Caribbean Region. World Bank Report. 2016. Regulatory Indicators for Sustainable Energy. World Bank. 2009. Reducing Technical and Non‐Technical Losses in the Power Sector. World Bank, Sustainable Energy for All (SE4ALL) database from the SE4ALL Global Tracking Framework led jointly by the World Bank, International Energy Agency, and the Energy Sector Management Assistance Program. Access to Electricity (% of population). [Online] World Bank. 2009. Monitoring Performance of Electric Utilities: Indicators and Benchmarking in Sub-Saharan Africa. World Energy Council, Performance of Generating Plant: New Metrics for Industry in Transition, 2010 ZESCO Integrated Report. 2016.
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APPENDIX A – KPI Definitions
Index Name Unit Broad Definition Financial Gearing % Gearing ratio refers to the fundamental analysis ratio of a company's level of long-term debt compared to its equity capital/capital employed. Profit/Loss Margin % Indicates to what extent the utility can have cost reflecting tariffs and keep control of investments, costs and bill payment. Return on Employed Capital % Return on capital employed measures the profitability of the organisation in relation to capital invested. Staff Cost/Total Cost Ratio Measures the weight of staff costs in the cost structure of the utility. Staff costs are a major factor of utility profitability. Debt Service Cover Ratio DSCR refers to the amount of cash flow available to meet annual interest and principal payments on debt, including sinking fund payments. Operational Revenue to Ratio Measures the sustainability of cost levels and is indicative to Operational Cost the extent to which tariffs are cost reflective. Total O&M Cost/Revenue % Indicate the percentage of revenue reserved for operating and maintaining plant. Customer services Customer Bill Collection Rate % Measures revenues that are considered collectable in relation to total electricity billed. Average Debt Collection Period days Measures the time that it takes to collect revenue from electricity sales. Number of Outages per Year Due # p.a. Measures continuity of power supply. Consumer to Supply Shortage dissatisfaction with service is often related to high level of outages. Outages can be caused by generation or network failures. Connection Installations Exceeding % Measures the % of connections that exceed the target that Time Targets was set for time to connect. Average Field Staff Response Time Hours Average field staff response time measures the average time that it takes from the field staff to respond to outages and start to work. Technical System Average Interruption Minutes SAIDI is defined as the average duration of interruptions for Duration (SAIDI) customers served during a specified time period. System Average Interruption Index SAIFI described the average number of times that a Frequency (SAIFI) customer’s power is interrupted during a specified time period. Customer Average Interruption Minutes CAIDI is the weighted average length of an interruption for Duration Index (CAIDI) customers affected during a specified time period. Energy Availability Factor (EAF) % Energy availability factor (EAF) Measure of power station availability, taking account of energy losses not under the control of plant management and internal non-engineering constraints.
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Planned Capability Loss Factor % Planned capability loss factor (PCLF) measures energy losses (PCLF) due to outages that are considered planned when a power station unit has to be taken out of service and it is scheduled at least four weeks in advance. Unplanned Capability Loss Factor % Unplanned capability loss factor (UCLF) measures energy (UCLF) losses due to outages are considered unplanned when a power station unit has to be taken out of service and it is not scheduled at least four weeks in advance. Number of Major Incidents >1 # A major incident is an interruption with a severity ≥ 1 Minute system minute. Safety Number of Fatalities # Count the number of employees that died during the execution of work-related activities. Lost Time Injury Rate Ratio Measures the number of incidents where an employee as result of the injury or disease during the execution of work- related activities is unable to with all the normal duties on the next day or shift, as verified by a medical practitioner in relation to total hours worked for the period. Efficiency and Sustainability Operating Cost of Electricity per USD/MWh Operating cost of electricity per MWh measures the cost MWh (Excl. Depreciation, Excl. efficiency of the organisation. Finance Cost) Operating Cost per Megawatt USD/MW Operating cost per MW installed measures the cost Installed (Excl. Depreciation, Excl. efficiency of the organisation. Finance Cost) Operating Cost of Electricity per USD/MWh Measures the delivered cost of 1 MWh of electricity. Should MWh (Incl. Depreciation, Excl. include the cost of power generated internally and procured Finance Cost) externally by the utility. The total operating cost is divided by the total number of energy units sold. System Losses % System losses measures the total losses and combine technical i.e. naturally occurring losses depending on system design and system usage and non-technical losses i.e. losses due to factors such as electricity theft, illegal connection and incorrect metering. Distribution Technical Energy % Technical losses measures losses that are naturally occurring Losses losses that depend on the power systems used. Distribution Non-Technical Energy % Non-technical losses measures losses that are due to causes Losses other than naturally occurring losses that depend on the power systems used. Socio-Economic and Environmental National, Urban and Rural Access % Measures household electrification rate, including to Electricity connection to the main grid and a local grid. This indicator might take into account off-grid connections. Generation Capacity/Demand Ratio Measures to what extent installed capacity meets demand. Demand equals actual demand plus demand from connected customers who cannot be served.
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APPENDIX B – PARTICIPATING REGULATORS AND UTILITIES
KPI Quantification Participants List:
Regulator Country
ECB Namibia
NERSA South Africa
EWURA Tanzania
ERB Zambia
LEWA Lesotho
MERA Malawi
SERA eSwatini
Participating Utilities List:
Country Utilities selected by regulator
Namibia NamPower
Namibia Erongo RED
Namibia CENORED
South Africa Eskom
Tanzania TANESCO
Zambia ZESCO
Lesotho LEC
Malawi ESCOM
eSwatini SEC
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APPENDIX C – SURVEY QUESTIONNAIRES First Survey - Selection of Top 30 KPIs
KPIs Available for Selection Criticality of KPI Collectability of KPI
Cannot Very Nice to Can Be Index Name Unit Critical Important Available Be Important Have Collected Collected
Financial Free Funds From Operations As % of Gross % Debt Gearing % Free Funds From Operations As % of Total % Capital Quick Ratio Ratio Tariff Settings and Times/Yr. Adjustments Profit/Loss % Return on Capital Invested % Staff Cost/Total Cost Ratio Debt Service Cover Ratio Cash Interest Cover Ratio Ratio (Before Capitalization) Gross Debt/EBITDA Ratio Average Capital Expenditure Ratio to Net Asset Value Operational Revenue to Ratio Operational Cost Total O&M Cost/Revenue % Customer Services Meters per Meter Reader Ratio Percentage of Bills % Estimated Time Lag Between Meter Days Reading and Bill Dispatch Customer Bill Collection % Rate Average Debt Collection Days Period Unmetered Customers % Replacement of Faulty Days Meters Customers on Pre-Paid % Metering
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Number of Outages per Year Due to Supply #/yr. Shortage Number of Transformer #/yr. Failures per Year Connection Quotations % Exceeding Time Targets Connection Installations % Exceeding Time Targets Time to Quote - Run of Days Line Average Field Staff Response Hours Time Customer Complaint % Resolution Rate Complaints Escalated to the # Regulatory Authority Technical System Average Interruption Duration Index (SAIDI) System Average Interruption Frequency Index (SAIFI) Customer Average Interruption Duration Index Index (CAIDI) Energy Availability Factor % (EAF) Planned Capability Loss % Factor (PCLF) Unplanned Capability Loss % Factor (UCLF) Number of System Minutes Minutes Lost <1 minute Number of Major Incidents # >1 Minute Safety Number of High Potential Ratio Near Misses per Employee Recordable Case Incident Index Severity Index Number of Fatalities # Lost Time Injury Rate Ratio Efficiency and Sustainability Operating Cost of USD/ Electricity per MWh (Excl. MWh Depreciation)
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Operating Cost per USD Megawatt Installed Cost of Electricity USD/ Generation MWh Replaced Transformers as % % of Installed Transformers Replace Meters as a % of % Installed Meters Meeting Project Time Weighted % Project Commitments On-Time Weighted % Project Build Within Project Budget Within Budget % of System Losses Supply Distribution Technical % Energy Losses Distribution Non-Technical % Energy Losses Transmission Non-Technical % losses Socio, Economic and Environmental National, Urban and Rural % Access to Electricity Connectivity Potential # Generation Ratio Capacity/Demand Off-grid/On-Grid Demand Ratio Relative Particulate kg/MWh Emissions sent out Specific Water Usage L/kWh
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Second Survey - Quantification of Top 30 KPIs
Name of Utility:
Year-End Date:
Name of Regulator:
Prepared by:
Reviewed by:
Please indicate whether involved in: Yes/No
Generation
Transmission
Distribution Index Name Unit Data Financial 1 Gearing % 2 Profit/Loss % 3 Return on Capital Invested % 4 Staff Cost/Total Cost Ratio 5 Debt service Cover Ratio 6 Operational Revenue to Operational Cost Ratio 7 Total O&M Cost/Revenue % Customer Services 8 Customer Bill Collection Rate % 9 Average Debt Collection Period days 10 Number of Outages per Year Due to Supply Shortage #/yr. 11 Connection Installations Exceeding Time Targets % 12 Average Field Staff Response Time Hours Technical 13 System Average Interruption Duration (SAIDI) Index 14 System Average Interruption Frequency (SAIFI) Index Customer Average Interruption Duration Index 15 Index (CAIDI) 16 Energy Availability Factor (EAF) %
17 Planned Capability Loss Factor (PCLF) %
18 Unplanned Capability Loss Factor (UCLF) %
19 Number of Major Incidents >1 Minute #
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Safety 20 Number of fatalities # 21 Lost Time Injury Rate Ratio Efficiency and Sustainability Operating Cost of Electricity per MWh (Excl. 23 USD/MWh Depreciation) 24 Operating Cost per Megawatt Installed USD 25 Cost of Electricity Generation USD/MWh
26 System Losses % of supply
27 Distribution Technical Energy Losses % 28 Distribution Non-Technical Energy Losses % Socio, Economic and Environmental 29 National, Urban and Rural Access to Electricity % 30 Generation Capacity/Demand Ratio
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