Energex 2017 DAPR 2017/ /22. Energex Limited 2017 DAPR 2017/ /22

Transcription

1 Energex 2017 DAPR 2017/ /22 Energex Limited 2017 DAPR 2017/ /22

2 Version Control Version Date Description /09/2017 Initial Issue /11/2017 Amendment 1 Disclaimer Energex s Distribution Annual Planning Report is prepared and made available solely for information purposes. While care was taken in the preparation of the information in this report, and it is provided in good faith, Energex accepts no responsibility or liability (including without limitation, liability to any person by reason of negligence or negligent mis-statement) for any loss or damage that may be incurred by any person acting in reliance on this information or assumptions drawn from it, except to the extent that liability under any applicable Queensland or Commonwealth of Australia statute cannot be excluded. It contains assumptions regarding, among other things, economic growth and load forecasts which may or may not prove to be correct. The forecasts included in the document involve subjective judgements and analysis which are subject to significant uncertainties and contingencies, many of which are out of the control of Energex. Energex makes no representation or warranty as to the accuracy, reliability, completeness or suitability for any particular purpose of the information in this document. All information should be independently investigated, reviewed, analysed and verified, and must not be relied upon in connection with any investment proposal or decision. The information contained in this report is subject to annual review. Energex is obligated to publish future editions by 30th September, in accordance with the National Electricity Rules. GPO Box 1461 Brisbane QLD Reddacliff Street Newstead QLD 4006 Telephone Energex Limited ABN Energex Limited 2017 Energex and Energex Positive Energy are registered trademarks of Energex Limited ABN This work is copyright. Material contained in this document may be reproduced for personal, in-house or non-commercial use, without formal permission or charge, provided there is due acknowledgement of Energex Limited as the source. Requests and enquiries concerning reproduction and rights for a purpose other than personal, in-house or non-commercial use, should be addressed to the Group Manager Strategic Customer Interactions, Energex, GPO Box 1461 Brisbane QLD DAPR 2017/ /22

3 Contents 1 Introduction Foreword Background and Purpose Network Overview Peak Demand DAPR Enquiries Changes from 2016 DAPR Energex Overview Energex Corporate Overview Vision Purpose Energy Queensland Transformation Objectives Business Function Energex Electricity Distribution Network Network Operating Environment Physical Environment Economic Activity Social and Demographic Change Technological Change Shareholder and Government Expectations Community Safety Environmental Commitments Legislative Compliance Economic Regulatory Environment Customer Insights Overview Connecting With You Customer Engagement Strategy Energy Supply Performance Customer Insights DAPR customer engagement and insights Asset Management Overview Best Practice Asset Management Asset Management Policy Strategic Asset Management Plan Asset Management Key Objectives DAPR 2017/ /22

4 4.3.2 Asset Management Plans and Initiatives Asset Management System Network Investment Process Corporate Governance Network Risk Management and Program Optimisation Investment Guidance Asset Management Investment Process Program of Work Implementation Forecasting Forecast Assumptions Customer Behaviour Solar PV Systems Electric Vehicles Battery Storage Temperature Sensitive Load and Air-conditioning Growth Temperature sensitivity Economic Growth Population Growth Electricity Delivered Forecasts Electricity Delivered versus Electricity Consumption Electricity Delivered Forecast Methodology Electricity Delivered History and Forecast Substation and Feeder Maximum Demand Forecasts Substation Forecasting Methodology Transmission Feeder Forecasting Methodology Sub-transmission Feeder Forecasting Methodology Distribution Feeder Forecasting Methodology System Maximum Demand Forecast System Demand Forecast Methodology Planning Framework Background Joint Planning Joint Planning Methodology Role of Energex in Joint Planning Emerging Joint Planning Limitations Network Connection Proposals Joint Planning Activities and Interactions Joint Planning and Joint Implementation Register Joint Planning Results DAPR 2017/ /22

5 6.3.2 Further Information on Joint Planning Distribution Network Planning Assessing System Limitations Overview of Methodology to Assess Limitations Key Assumptions Driving Investment Bulk and Zone Substation Analysis Methodology Assumptions Transmission Feeder Analysis Methodology Assumptions Sub-transmission Feeder Analysis Methodology Assumptions Distribution Feeder Analysis Methodology Assumptions Fault Level Analysis Methodology Assumptions Project Approval and Implementation Detailed Planning Consideration of Distribution Losses Overview of Network Limitations Network Limitations Adequacy and Security Connection Point and Substation Limitations Transmission Feeder Limitations Sub-transmission Feeder Limitations kv Distribution Feeder Limitations Network Limitations Voltage Voltage Levels Sub-transmission Network Voltage kv Distribution Network Low Voltage Network Network Limitations Fault Level kv Primary Overcurrent Protection Reach Limits Summary of Emerging Network Limitations Emerging Network Limitations Maps Demand Management Activities Non-Network Options Considered in 2016/ Key Issues Arising from Embedded Generation Applications Actions Promoting Non-Network Proposals Demand Management Results for 2016/ Connection Enquiries Received Applications to Connect Received Average Time to Complete Connection Demand Management Programs for 2017/18 to 2021/ DM programs being proposed for the next five years Other Demand Side Participation Activities Regulatory Investment Test (RIT-D) Projects DAPR 2017/ /22

6 9 Asset Life-Cycle Management Approach Safety and Compliance Asset Inspections and Condition Based Maintenance Vegetation Management Asset Condition Management Methodology Replacement Programs Poles Overhead Conductor Crossarms and Pole Top Structures Customer Service Lines Underground Cable Distribution Plant Air Break Switch Replacement Ring Main Unit (RMU) Replacement Obsolete and Aged Protection Relays Oil Filled Circuit Breakers Instrument Transformer Replacement Planned Battery Replacement Battery Charger Replacement LV Service Fuse Holder Replacement Replace Ageing Cable Terminations Overhead Network Clearance Basement Fire Systems Protection Schemes Reactive Asset Replacement Secondary Systems Asset Replacement Network Reliability Reliability Measures and Standards Reliability Performance in 2016/ Reliability Compliance Processes Reliability Non-Compliance Corrective Actions Service Target Performance Incentive Scheme (STPIS) STPIS Methodology STPIS Results and Forecast High Impact Weather Events Bushfire Management Flood Resilience Guaranteed Service Levels (GSL) DAPR 2017/ /22

7 Automated GSL Payment Worst Performing Feeders Safety Net Target Performance Power Quality Customer Experience Power Quality Supply Standards, Codes Standards and Guidelines Power Quality Performance in 2016/ Power Quality Performance Monitoring Steady State Voltage Regulation Voltage Unbalance Harmonic Distortion Voltage Sags Power Quality Non-Compliance Corrective Actions Risk Assessment Power Quality Compliance Processes Emerging Network Challenges Solar PV Solar PV Emerging Issue and Statistics Future Impacts of Solar PV on Asset Ratings V Low Voltage Standard Revised 0-30 kva Solar PV Connection Standard Electric Vehicles Battery Energy Storage Systems Land and Easement Acquisition Impact of Climate Change on the Network Information and Communication Technology (ICT) ICT Investments 2016/ Forward ICT Program Forward Financial Forecasting Metering Ageing Meter Population Metering Investments in 2016/ Metering Investments from 2016/17 to 2020/ Operational and Future Technology SCADA and Communications Systems SCADA and Communication Investments in 2016/ Data Centre Related Facilities Telecommunication Network Facilities DAPR 2017/ /22

8 SCADA and Automation Infrastructure Future Distribution Network Technologies Substation Secondary System Integration Appendix A Terms and Definitions... A2 Appendix B NER and DA Cross Reference... B2 Appendix C Network Security Standards... C2 Appendix D Network Limitations and Mitigation Strategies... D2 Appendix E Substations Forecast and Capacity Tables... E2 E.1 Supporting Notes... E2 E.2 Peak Load Forecast and Capacity Tables... E3 E.2.1 Calculation of Load at Risk... E6 E.2.2 Network Security Standards... E7 Appendix F Feeders Forecast and Capacity Tables... F2 F.1 Supporting Notes on Feeders... F2 F.2 Peak Load Forecast and Capacity Tables... F2 F.2.1 Transmission Studies... F3 F.2.2 Sub-Transmission Studies... F4 F.2.3 Distribution (11 kv) Feeder Studies... F4 F.2.4 Calculation of Load at Risk... F7 F.2.5 Network Security Standards... F8 F.2.6 Qualification on the Information Provided... F9 Appendix G Worst Performing 11 kv Feeders... G DAPR 2017/ /22

9 Table of Figures Figure 1 Typical Electricity Supply Chain... 4 Figure 2 Energy Queensland Vision, Purpose and Values... 8 Figure 3 Energex Distribution Hubs Figure 4 SAMP translates Corporate Objectives to Asset Management Objectives Figure 5 Asset Management Objectives Figure 6 Energex s Asset Management System Figure 7 Program of Work Governance Figure 8 Network Investment Process Figure 9 Energex System Demand Solar PV Impact, 18 January Figure 10 Solar PV Impact on Arana Hills AHL 12A on the Peak Day Figure 11 Solar PV Impact on Lota Substation on a Peak Day Figure 12 Number of Days at Amberley > Standard Temperature (30.65 C) Figure 13 Number of Days with Maximums > 30 C at Amberley Figure 14 Summer Demand Temperature Sensitivity Figure 15 Mango Hill Zone Substation Temperature Sensitivity Figure 16 Peak Demand and Temperature Range at Amberley Figure 17 Energex System Demand Variations by Average Temperature and Season Figure 18 Air-Conditioning Connected Load Forecast Figure 19 Queensland GSP Growth Forecasts Figure 20 Queensland Population Projections Figure 21 Average Number of Persons per Household in SEQ Figure 22 New Metered Customer Number Growth Figure 23 Number of Solar PV Installations Figure 24 Solar PV Impacts on Electricity Delivered Figure 25 Growth of Total Electricity Delivered DAPR 2017/ /22

10 Figure 26 Electricity Delivered by Category (GWh pa) Figure 27 Zone Substation Growth Distribution Figure 28 Energex Peak Demand Forecast Figure 29 Previous Demand Forecast Comparison Figure 30 Distribution Annual Planning Report Process Figure 31 Concepts of Health Indices Figure 32 CBRM Health Index and Probability of Asset Failure Figure 33 Process to Create Asset Investment Plan Figure 34 - Pole Replacement and Nailing Contributions from all Programs Figure 35 STPIS Urban SAIDI / SAIFI Forecast Figure 36 STPIS Rural SAIDI / SAIFI Forecast Figure 37 STPIS CBD SAIDI / SAIFI Forecast Figure 38 Normalised Count and Causes of Urban Outages Figure 39 Normalised Count and Causes of Rural Outages Figure 40 Power Quality Voltage Enquiries Figure 41 Power Quality Voltage Categories Figure 42 Solar Related Voltage Enquiries Figure Month Voltage Profile of Distribution Transformer Measurements Figure Month Voltage Profile of LV Circuit Monitors Measurements Figure Month Voltage Profile of Customer Premise Monitors Measurements Figure 46 99th Percentile Voltage Profile of all Monitored Transformers Figure 47 50th Percentile Voltage Profile of all Monitored Transformers Figure 48 1st Percentile Voltage Profile of all Monitored Transformers Figure 49 99th Percentile Voltage Profile of all monitored LV circuits Figure 50 50th Percentile Voltage Profile of all monitored LV circuits Figure 51 1st Percentile Voltage Profile of all monitored LV circuits Figure 52 99th Percentile Voltage Profile of all monitored customers DAPR 2017/ /22

11 Figure 53 50th Percentile Voltage Profile of all monitored customers Figure 54 1st Percentile Voltage Profile of all monitored customers Figure 55 Voltage Unbalance Factor Profile of Distribution Transformer Measurements Figure 56 Total Harmonic Distortion Profile of Distribution Transformer Measurements Figure 57 Sag Severity Indicator Profile of Distribution Transformer Measurements Figure 58 Systematic Approach to Voltage Management Figure 59 Grid Connected solar PV System Capacity by Tariff Figure 60 Impacts of Solar PV on Currimundi CMD15A (2nd Tuesday in November) Figure 61 Distribution Transformers with Solar PV Penetration > 25% of Nameplate Rating Figure 62 Distribution Feeders with Solar PV Penetration > 1000 kva Figure 63 Number of customers with Solar PV by Zone Substation Figure 64 Installed Capacity of Solar PV by Zone Substation Figure 65 Impact of Controlled and Uncontrolled EV Charging on a Residential Feeder Figure 66 Digital Building Blocks Figure 67 Historical Meter Usage July 2012 to June Figure 68 Energex Meters Age Profile Figure 69 Energex Electronic Meter Age Profile DAPR 2017/ /22

12 Table of Tables Table 1 Summary of Network and Customer Statistics Table 2 Actual Maximum Demand Growth Table 3 Maximum Demand Forecast (MW) Table 4 Solar PV Contribution to Summer System Peak Demand Table 5 Electric Vehicle Contribution to Summer System Peak Demand Table 6 Battery Storage Systems Impact on Summer System Peak Demand Table 7 Joint Planning Activities and Interactions Table 8 Joint Planning Activities Covering 2017/18 to 2021/ Table 9 Standard Ambient Air Temperatures for Plant Ratings Table 10 Standard Atmospheric Conditions for Conductor Ratings Table 11 Standard Environmental Conditions for Cable Ratings Table 12 Summary of Substation Limitations Table 13 Summary of 132 kv and 110 kv Transmission Limitations Table 14 Summary of 33 kv Sub-transmission Limitations Table 15 Summary 11 kv Feeders > TMU Table 16 System Operating Voltages Table 17 Maximum Allowable Voltage Table 18 Steady State Maximum Voltage Drop Table 19 Energex Fault Level Limits Table 20 Demand Management Strategies Table 21 DMIA projects undertaken in 2016/ Table 22 Embedded Generator Enquiries Table 23 Embedded Generator Applications Table 24 Embedded Generator Applications Average Time to Complete Table 25 Performance Compared to MSS DAPR 2017/ /22

13 Table /17 STPIS Results Table /17 STPIS Uncapped Revenue Table 28 STPIS SAIDI / SAIFI Forecast Table 29 STPIS SAIDI / SAIFI Targets Table 30 STPIS SAIDI / SAIFI Forecast Performance Comparison Table 31 Reliability GSLs Table 32 Reliability GSLs Claims Paid 2016/ Table 33 Worst Performing Feeder SAIDI Performance Comparison Table 34 Worst Performing Feeder SAIFI Performance Comparison Table 35 Worst Performing Feeder Performance Criteria Table /18 Worst Performing Feeder List Current Performance (2016/17) Table 37 Allowable Variations from the Relevant Standard Nominal Voltages Table 38 Allowable Planning Voltage Fluctuation (Flicker) Limits Table 39 Allowable Planning Voltage Total Harmonic Distortion Limits Table 40 Allowable Voltage Unbalance Limits Table 41 Summary of Power Quality 2017/18 Initiatives Table 42 Network Solutions for Varying Levels of solar PV Penetration Table 43 ICT Investments 2016/ Table 44 Total Potential ICT Investment Table 45 Contribution to Meter Usage (5 years) Table 46 Metering Investments 2016/ Table 47 Metering Capex Replacement Cost 2017/ Table 48 Operational and Future Technology Investments 2016/ Table C1 Customer Outcome Standard Safety Net Targets... C3 Table E1 Definition of Terms Peak Load Forecast and Capacity Tables... E4 Table F1 Definition of Terms Feeder Capacity and Forecast Tables... F DAPR 2017/ /22

14 Executive Summary Energex Limited (Energex) and its predecessor organisations have provided electricity to homes and businesses in South East Queensland since the late 19th Century. Energex distributes electricity to over 1.4 million residential, commercial and industrial customers across a population base of around 3.4 million in South East Queensland. With a Vision to energise Queensland communities, Energex s main Purpose is to safely deliver secure, affordable and sustainable energy solutions with our communities and customers. Key business priorities include the provision of reliable, safe and secure electricity supply; continue proactive customer engagement to deliver valued services; support the continued growth of solar PV, support and drive energy agility and innovation; and influence and adapt to regulatory and market reform. Energex and Ergon Energy are currently in the advanced stages of implementing the Queensland Government s electricity industry reforms. The centrepiece of this reform has been the creation of Energy Queensland through the merger of Ergon Energy Corporation Limited, Energex Limited and SPARQ Solutions. Energex is pleased to present the 2017/18 to 2021/22 Distribution Annual Planning Report (DAPR). This DAPR represents the outcomes of the annual planning processes required under section 5.13 and Schedule 5.8 of the National Electricity Rules (NER). The key outcomes of this planning process represent Energex s intentions for the next five years in relation to load forecasting, demand management, new capacity investments, asset replacement and refurbishments, reliability and supply power quality. The changes to the operating environment in which the DAPR has been produced is characterised by moderate changes in patterns of network use, stabilising demand growth and customer reliability safety net obligations. This plan has been developed consistent with the outcomes of Energex s AER determination with a focus on meeting customer s energy needs with cost effective solutions. Key investment decisions will be based on meeting safety obligations and community expectations and supporting the continued expansion of renewable energy growth. Solar PV The Queensland Government continues with its policy commitment to increasing the contribution of renewable energy to Queensland s energy mix. This includes the establishment of a 50 per cent renewable energy target for Queensland by 2030, a one million rooftops or the equivalent of 3,000 megawatts solar PV target by 2020 and a commitment to providing long-term financial support to parties installing large-scale solar generation. Energex continues to ensure the safety of the public and its employees by managing the risks associated with operating the electricity network. These factors take high priority in Energex s pursuit of the National Electricity Objective (NEO) to promote efficient investment in, and operation and use of, electricity services for the long term interests of customers. - i DAPR 2017/ /22

15 Market Reform Substantial reforms to the National Electricity Market (NEM) are continuing as outcomes of the Australian Energy Market Commission s Power of Choice (PoC) review are progressed. The PoC program is being implemented in Queensland with the aim of providing power users with additional options in the way they use electricity, better access to power consumption data and to expand competition in metering and related services. Energex will continue to work closely with Government from both a regulatory and network planning perspective to ensure beneficial price and customer service outcomes for the Queensland community. Peak Demand Because the network must have sufficient capacity to deliver power to meet the needs of every customer at any one time, growth in peak demand is a critical aspect that drives expansion and the operation of the electricity system. Peak demand occurs at different times in different locations, and this has different implications at different levels of the network. Whilst the average demand growth across the Energex network is slow, there are areas across the Energex network that still have strong growth, particularly where new property development is occurring, which requires the network to be upgraded or non-network solutions implemented. The Energex system maximum native demand for 2016/17 was recorded at 4,814 MW on Wednesday 18 January 2017 at 4:30pm. This peak native demand exceeded the previous highest recorded demand by 49 MW (4,765 MW in 2009/10). Energy usage patterns are also changing due to changes in customer behaviour, price, energy efficiency initiatives and the continued rapid deployment of distributed generation such as solar photovoltaic (PV). Solar PV presents a number of technical challenges such as power quality and voltage management. Approximately 23% of customers now source alternate energy supply from solar PV for some period of the day. Energex is progressing a range of innovative solutions such as changing operating times for hot water systems to ensure its network is able to cost effectively manage this challenges. Energex s operating environment is dynamic, reflecting customers responses to economic pressures, rising electricity prices, technology, and the availability of new service offerings. Customers now have more choice in energy sources, which is enabling them to reduce reliance on the network, manage their own energy needs and engage with new providers in the energy value chain. Customers have an ongoing expectation of quality service at a competitive cost. Energex needs to continue to provide an efficient, effective and valued service to support the broader community and business sector economy. Energex will continue to deliver network price rises below CPI that are fair and reasonable, and facilitate choice and control through new tariffs and services to keep its customers connected. Energex is also focussing on how it can maximise value from its existing assets to the benefit of its customers. This will be achieved by optimising life cycle costs, engaging with stakeholders and customers to further develop appropriate and sustainable demand side management solutions. - ii DAPR 2017/ /22

16 Changes in Technologies Technology advances, especially in regards to battery energy storage, electric vehicles and home energy management systems, have already seen a preliminary shift in customer interactions with distributors and a growing number and range of new service providers. Customers have demonstrated a willingness to actively engage in the energy market in a bid to access technologically advanced systems that provide value for money and innovative products. Customer behaviour is driven by economic considerations as well as choice, values, environmental concerns, self-sufficiency and desire to set and forget. The number of competitors and market participants in the energy industry continues to increase. As the uptake of Battery Energy Storage Systems (BESS) increases, Energex s systems and processes will continue to evolve to efficiently integrate these new customer technologies into the network. Once BESS reaches significant penetration levels, further challenges will include identifying how these systems can be incorporated into planning and forecasting functions. In order to meet and overcome some of these challenges, Energex has commissioned a range of projects under the BESS Trial. The uptake of solar, trends in home management systems and the affordability of batteries will continue to consolidate the market. The pace of technological change is not expected to slow in the foreseeable future. Grid-side and interface technologies are fostering the evolution of data and communication capability integrated with the grid to improve network utilisation and to interface with customers. Energex will continue to seek efficiencies to deliver on price, quality, safety, reliability and security of supply objectives. Energex will also ensure its investment plans appropriately account for the impacts of new customer energy needs such as solar PV and electric vehicles; and also the adoption of new network technologies such as smart grid technologies and emerging battery storage technologies. In managing the network, Energex will also continue to identify customer and community expectations through various customer engagement programs. Environmental Effects The effects of ex-tropical Cyclone Debbie were felt throughout Queensland and impacted the South East of the State on 30 March 2017 for over a week. The severe weather system brought with it winds of more than 120 km/h and torrential rain causing significant flooding, landslides and affected power to 214,855 homes and businesses on the Energex network. Energex crews worked around the clock on vast sections of the network to repair more than 1,800 fallen powerlines and flood-affected equipment as a result of Debbie. All this work was carried out while facing challenging conditions and issues such as flooding, debris, damaged roads and bridge collapses, all of which hampered their efforts. The dedicated work of Energex staff paid off with all affected customers having their power restored within six days. - iii DAPR 2017/ /22

17 Purpose The National Electricity Rules (NER) and Queensland s Electricity Distribution Network Code require Energex to publish this DAPR to explain how Energex is continuing to safely and efficiently manage the electricity distribution network for South East Queensland. Accordingly, the DAPR contains the results from annual network planning, asset performance and asset condition assessments to identify emerging network limitations. The publication of this DAPR is in compliance with Queensland s Electricity Distribution Network Code clause 2.2 and Distribution Authority. The aim of the document is to inform network participants and stakeholders about the Energex network, including potential opportunities for non-network solutions particularly for large investments where the AER s Regulatory Investment Test for Distribution (RIT-D) applies. Changes to 2017 DAPR The following changes have occurred as compared to the 2016 DAPR: A rule change for the DAPR came into effect 1 July 2017 requiring DNSPs to submit a Distribution System Limitation template (DAPR template); Energex is currently in the advanced stages of implementing the Queensland Government s electricity industry reform with the creation of Energy Queensland; Review and update of maximum demand forecasts over the next five years based on the ACIL Tasman model using three weather stations weighted data and the 2016/17 summer results; Economic growth was experienced in some areas of the Energex network, particularly where new property development is occurring; Under system normal conditions, there is one substation with load at risk in 2017/18; Under contingency conditions, there are seven zone substations with load at risk in 2017/18; Under contingency conditions, there are ten 33 kv feeders with load at risk in 2017/18; No potential RIT-D projects were identified to address emerging network limitations as there were no projects approved with credible options having an estimated cost of the augmentation component greater than $5 million; Energex s metering investment due to implementation of Power of Choice on 1 December 2017 and the AER reclassification of metering services from Standard Control Services to Alternative Control Services; Energex s information and communication technology investment as detailed in Section 13.2; Following feedback the Energex 2017 DAPR has network capacity, load forecasts and reliability data available in spreadsheet format via the hyperlinks in the appendices and Energex website; Following feedback from customers, interactive maps are available on the Energex website; Inclusion of solar PV heat map across Energex network based on zone substation supply areas in chapter 12; The first stage of the Market Based Battery Energy Storage Trial has commenced with the installation of the first 15 sites nearing completion; Australia s first local government 15 MW solar farm was connected onto the Energex 33 kv network in Sunshine Coast; - iv DAPR 2017/ /22

18 Improvements to Asset Management Overview chapter relating to the implementation of the ISO 5500 standard. This transition is a significant undertaking and will span several years to ensure best practice Asset Management; Update of Asset Management Overview chapter to align with Energy Queensland Strategy; Update of Energex s Overview chapter to align with Energy Queensland vision, purpose and objectives; Update of Customer Insights chapter to align with customer interactions and engagement activities; and Review and update on Energex s demand side management policy, strategy and initiatives. - v DAPR 2017/ /22

19 Chapter 1 Introduction Foreword Background and Purpose Network Overview Peak Demand DAPR Enquiries Changes from 2016 DAPR DAPR 2017/ /22

20 1 Introduction 1.1 Foreword This Distribution Annual Planning Report (DAPR) explains how Energex is continuing to safely and efficiently manage the electricity distribution network in South East Queensland (SEQ). In the release of this fifth edition, the DAPR aims to provide information to assist interested parties to: Identify locations that would benefit from significant electricity supply capability or demand side and non-network initiatives; Identify locations where major industrial loads could be located; Understand how the electricity supply system supports customer and participant needs; and Provide input to the future development of the network. For readers seeking to learn of planning outcomes since the 2016 DAPR, they are referred to section 6.3 for joint planning outcomes, to section for upcoming RIT-Ds, and to Appendix D for committed projects and proposed opportunities. Energex understands that as cost of living pressures increase for many South East Queenslanders, prudent investment plans are required in order to maintain required performance targets whilst minimising operating and capital costs. In addition, Energex must continue to ensure the safety of the public and its employees by managing the risks associated with the electricity network. These factors take high priority in Energex s pursuit of the National Electricity Objective (NEO) to promote efficient investment in, and operation and use of, electricity services for the long term interests of customers. This report captures the results of planning activities mandated by National Electricity Law (NEL), including forecasts of emerging network limitations for the purposes of market consultations. Importantly, customer supply risks are assessed through ongoing planning activities, and in conjunction with market participants, appropriate future investments are scheduled to ensure risks are addressed in accordance with obligated service standards. Energex s operating environment is dynamic, reflecting customers responses to economic pressures, electricity prices, technology, and the availability of new service offerings. Customers now have more choice in energy sources, which is enabling them to reduce reliance on the network, manage their own energy needs and engage with new providers in the energy value chain. The traditional electricity network was characterised by centralised generation and one directional flow. This is now evolving to a connected network of decentralised generation, multi directional flow, many market participants and new products (including renewables and storage). This plan has been developed consistent with the outcomes of Energex s AER determination with a focus on meeting customer s energy needs with cost effective solution. Key investment decisions will be based on meeting safety obligations and community expectations and supporting the continued expansion of renewable energy growth. This includes supporting the continued growth of domestic solar PV, which is already regarded as among the highest penetration rates in the world. To efficiently and safely manage the SEQ electricity network, it is critical to rigorously analyse data to identify emerging community and industry trends. In the 2016/17 year a total of 26,557 new customers DAPR 2017/ /22

21 were connected to the Energex network. A large proportion of these new 2016/17 connections were for multi-tenancy buildings, highlighting the surge in new apartment complex developments especially in central and greater Brisbane and on the Gold and Sunshine Coasts. Energex will continue to seek efficiencies to deliver on price, quality, safety, reliability and security of supply objectives. Energex will also ensure its investment plans appropriately account for the impacts of new customer energy needs such as solar PV and electric vehicles; and also the adoption of new network technologies such as smart grid and battery storage technologies. In managing the network, Energex will also continue to identify customer and community expectations through various customer engagement programs. The feedback from these programs will be used as input to network investment and management plans to ensure an appropriate balance between service and price. In addition to reviewing capital investments, Energex is focussing on maximising value from its existing assets to the benefit of its customers. This DAPR has been prepared with this focus, and Energex is delivering on these objectives by optimising life cycle costs, engaging with stakeholders and customers, developing appropriate and sustainable demand side management solutions, refining capital investment criteria via new customer consultation mechanisms, and adopting best practice Asset Management consistent with the recently released International Standard. 1.2 Background and Purpose This DAPR has been prepared to comply with National Electricity Rules (NER) clause and clause Clause is a rule change that came into effect 1 July 2017 requiring DNSPs to submit a Distribution System Limitation template (DAPR template). The publication of this DAPR is also in compliance with Queensland s Electricity Distribution Network Code clause 2.2 and Distribution Authority. The forward planning horizon covers from 2017/18 to 2021/22. The aim of this document is to inform network participants and stakeholder groups about development of the Energex network, including potential opportunities for non-network solutions particularly for large investments where the AER Regulatory Investment Test for Distribution (RIT-D) applies. 1.3 Network Overview Electricity is a commodity that is generated when it is required because the bulk of electricity consumed is not readily stored. Large generators located outside SEQ are connected to Powerlink s transmission network. In turn, Powerlink delivers this electricity to the Energex distribution network in order to distribute electricity to customers. Figure 1 summarises this electricity supply chain to illustrate how electricity is generated, transmitted and distributed to customers. Connection points exist between generators, transmission networks, distribution networks, embedded generators and large customers. Electricity carried over Powerlink s network is delivered in bulk to substations that connect to overhead or underground sub-transmission feeders to supply zone substations. Zone substations connect to overhead or underground distribution feeders operating at 11 kv. Distribution feeders distribute electricity to transformers that supply low voltage lines at 415/240 volts for customers. Importantly, customers use the network to obtain electricity, and to export electricity when excess solar power is generated DAPR 2017/ /22

22 Figure 1 Typical Electricity Supply Chain 1.4 Peak Demand The capacity of a network is the amount of electricity it can carry to every customer at any point in time. Because electricity cannot be readily stored, the network must have sufficient capacity to deliver power to meet the needs of every customer at any point in time. The demand for electricity at the point in time when prevailing electricity use is at its highest is known as peak demand. Growth in peak demand is a critical part of what drives design and operation of the electricity system. Peak demand occurs at different times in different locations, and this has different implications at different voltage levels of the network. Transmission levels must contain sufficient capacity to carry enough electricity to meet the global peak demand for the region serviced. Whereas, distribution levels of the network must contain sufficient capacity to carry enough electricity to meet peak demand in every street. The points in time that peak demand occurs on assets in each street, is often different to the point in time DAPR 2017/ /22

23 the peak occurs for the whole region. Therefore, there are varying degrees of diversity in demand between the points in time that peaks occur across each street, and the points in time that peak demands occur on the backbone network. In a positive demand growth environment, increasing peak demand is a major driver of network costs. Energex must maintain sufficient capacity to supply every home and business on the day of the year when electricity demand is at its maximum, no matter where those customers are connected in the network. In addition, growth in peak demand may occur where new property developments are being established; whilst over the same period peak demand may be declining in areas where usage patterns are changing due to customer behaviour or from the impacts of alternative sources like solar PV and battery energy storage systems. This means that growth patterns of electricity demand may be flat on a global scale, but there may be pockets of insufficient network capacity emerging in local areas experiencing increasing peak demand or new development. The Energex system maximum native demand for 2016/17 was recorded at 4,814 MW on Wednesday 18 January 2017 at 4:30pm. This peak native demand exceeded the previous highest recorded demand by 49 MW (4,765 MW in 2009/10). 1.5 DAPR Enquiries In accordance with NER (e), Energex advises that all enquiries and feedback relating to this document are to be submitted by to the following address: DAPR_Enquiries@energex.com.au Energex welcomes feedback and any improvement opportunities identified by market participants and other stakeholders. 1.6 Changes from 2016 DAPR For consultation purposes, Energex is ensuring the DAPR remains relevant and evolves with ever changing market expectations. To this end, Energex has made a number of improvements in the 2017 DAPR, and a number of improvements are planned for future editions. Changes have been made to chapters 2, 3, 4, 5, 6, 7, 8, 11, 14 and information previously published in Volume 2 are now available in spreadsheet format accessible via links shown in Appendices D, E, F and G. These changes aim to make relevant information accessible and understood by all stakeholders, non-network providers and interested parties. Future improvements aim to provide more information about asset management activities pertaining to the implementation of the ISO standard DAPR 2017/ /22

24 The following changes have occurred as compared to the 2016 DAPR: A rule change for the DAPR came into effect 1 July 2017 requiring DNSPs to submit a Distribution System Limitation template (DAPR template); Energex is currently in the advanced stages of implementing the Queensland Government s electricity industry reform with the creation of Energy Queensland; Review and update of maximum demand forecasts over the next five years based on the ACIL Tasman model using three weather stations weighted data and the 2016/17 summer results; Economic growth was experienced in some areas of the Energex network, particularly where new property development is occurring; Under system normal conditions, there is one substation with load at risk in 2017/18; Under contingency conditions, there are seven zone substations with load at risk in 2017/18; Under contingency conditions, there are ten 33 kv feeders with load at risk in 2017/18; No potential RIT-D projects were identified to address emerging network limitations as there were no projects approved with credible options having an estimated cost of the augmentation component greater than $5 million; Energex s metering investment due to implementation of Power of Choice on 1 December 2017 and the AER reclassification of metering services from SCS to ACS; Energex s information and communication technology investment as detailed in Section 13.2; Following feedback the Energex 2017 DAPR has network capacity, load forecasts and reliability data available in spreadsheet format via the hyperlinks in the appendices and Energex website; Following feedback from customers, interactive maps are now available on the Energex website; Inclusion of solar PV heat map across Energex network based on zone substation supply areas in chapter 12; The first stage of the Market Based Battery Energy Storage Trial has commenced with the installation of the first 15 sites nearing completion; Australia s first local government 15 MW solar farm was connected onto the Energex 33 kv network in Sunshine Coast; Improvements to Asset Management Overview chapter relating to the implementation of the ISO 5500 standard. This transition is a significant undertaking and will span several years to ensure best practice Asset Management; Update of Asset Management Overview chapter to align with Energy Queensland Strategy; Update of Energex s Overview chapter to align with Energy Queensland vision, purpose and objectives; Update of Customer Insights chapter to align with customer interactions and engagement activities; and Review and update on Energex s demand side management policy, strategy and initiatives DAPR 2017/ /22

25 Chapter 2 Energex Overview Energex Corporate Overview Energex Electricity Distribution Network Network Operating Environment DAPR 2017/ /22

26 2 Energex Overview 2.1 Energex Corporate Overview Energex is a subsidiary of Energy Queensland Limited, a State government-owned corporation. Energy Queensland has been created through the merger of Energex, Ergon Energy and SPARQ Solutions on 30 June Vision The Energy Queensland vision is to energise Queensland communities. Energy Queensland provides an opportunity to deliver better outcomes for customers, employees and all Queenslanders. Energy Queensland will effectively manage Queensland s electricity network, and respond to the future needs of the energy market. In the current environment, the Energy Queensland vision underpins the provision of a safe, reliable and cost effective electricity distribution network Purpose To achieve the vision, Energy Queensland s purpose is to deliver secure, affordable and sustainable energy solutions with our communities and customers as shown in Figure 2. Figure 2 Energy Queensland Vision, Purpose and Values DAPR 2017/ /22

27 2.1.3 Energy Queensland Transformation Objectives To achieve the vision, Energy Queensland s objectives are as follows: Position Energy Queensland to support its local communities Be the preferred provider of energy services through maintaining strong community trust; Encourage energy efficiency and energy productivity; Remain an active employer in local communities; and Retain local resources and continue to be a leader in emergency response. Achieve sustainable price outcomes for consumers Drive network net savings of more than $562m through efficiency measures by 2020; Merger synergies: o Functional (indirect) cost improvements; and o Operational (direct) cost improvements. Meet or outperform spending allowances set by the independent regulator; and Undertake operational improvements to drive efficiency savings and better customer outcomes. Provide long term, sustainable returns to Government Energy Queensland will be self-funding; Reduce costs for Community Service Obligation payments; and Returns should be comparable to similar Australian and global businesses. Position Energy Queensland for growth and adaption to changes in electricity supply sector Establish new Energy Services business to: o Offer new products and services to households, businesses and communities in regional Queensland; and o Offer network benefits including peak demand reductions, better network optimisation, and modern and contemporary customer services. Drive cultural change to re-position Energy Queensland as a customer-oriented, efficient business Efficient and stable prices for customers; Customer choice (particularly in regional Queensland); High levels of safety, reliability and product excellence; Innovative asset management strategies to reduce business costs and government subsidies; and Innovative service delivery DAPR 2017/ /22

28 2.1.4 Business Function Energex s core business functions are to: Build, operate and maintain its electricity network to deliver safe, efficient, and reliable quality of supply; Engage the community and manage electricity supply relationships with end use customers and electricity retailers; Balance short term network management and long term network aspirations by improving network performance and emergency response; Progress towards the delivery of an intelligent connective network and the provision of leading practice energy solutions to customers; and Meet regulatory and shareholder requirements including sustainable and sound commercial operations evidenced by affordable expenditure levels, a strong balance sheet and delivery of shareholder value. 2.2 Energex Electricity Distribution Network Energex distributes electricity to over 1.4 million residential, commercial and industrial customers across a population base of around 3.4 million in SEQ. At the core of the business is a high performing network that consists of property, plant and equipment and assets valued at approximately $12 billion. The bulk of electricity distributed by Energex is carried by Powerlink to Energex connection points across large distances, because base-load generation is located remotely. However, Energex also enables connection of distributed generation, such as solar PV and embedded generators. The Energex network is characterised by: Connection to Powerlink s high voltage transmission network at 28 connection points; High Density / Central Business District (CBD) areas such as the Brisbane CBD, and the Gold Coast and Sunshine Coast city areas which are typically supplied by 110/11 kv, 110/33 kv, 132/33 kv, or 132/11 kv substations; Urban and Rural areas where 110/33 kv or 132/33 kv bulk supply substations are typically used to supply 33/11 kv zone substations; Inner suburban areas close to the CBD which have extensive older, meshed 33 kv underground cable networks that supply zone substations; Outer suburbs and growth areas to the north, south and west of Brisbane, which are supplied via modern indoor substations of modular design that enable further modules to be readily added; and New subdivisions in urban and suburban areas which are supplied by underground networks with padmount substations. Table 1 presents a summary of Energex s network and customer statistics over the past five years. Changes in asset numbers over this timeframe have occurred as a consequence of demands for electricity, residential, commercial and industrial developments DAPR 2017/ /22

29 Table 1 Summary of Network and Customer Statistics Assets 2012/ / / / /17 Total Overhead and Underground (km) 51,879 52,176 52,635 53,270 53,774 Lines Length of Overhead (km) Total 35,094 35,112 35, , ,120 LV (Low Voltage) 14,262 14,242 14,226 14,222 14, kv 17,529 17,541 17,553 17,571 17, kv 2,130 2,196 2,219 2,211 2, kv and 110 kv 1,173 1,173 1, , ,154 Cables Length of Underground (km) Total 16,785 17,064 17,464 18,093 18,654 LV 10,457 10,599 10,848 11,300 11, kv 5,290 5,421 5,547 5,754 5, kv kv and 110 kv Other Equipment (Quantity) Bulk Supply Substations Zone Substations Poles 1 658, , , , ,529 Distribution Transformers 47,436 47,875 48,436 49,093 49,781 Street Lights 2 345, , , , ,164 Customer Numbers Residential 1,235,740 1,250,326 1,271,644 1,297,106 1,323,876 Other 111, , , , ,592 Total 1,347,195 1,363,815 1,385,445 1,411,628 1,439, All poles including customer poles and streetlight poles held on record. All streetlights including rate 3 streetlights. Distance includes previously purchased 110 kv lines from Powerlink that are currently out of service. All information as at June 30 each year. Data siting in unknown feeder group has either been removed or allocated to correct feeder type. The large number of Energex assets is managed across six hubs centred on geographical regions. These hubs provide regional asset and resource management, and can respond promptly to local network outages. The geographical boundaries for each hub are shown in Figure DAPR 2017/ /22

30 Figure 3 Energex Distribution Hubs DAPR 2017/ /22

31 2.3 Network Operating Environment Key external drivers, associated industry impacts and safety and environmental commitments are presented in this section. Many of these have emerged from Energex s forward planning process which informs the identification of Energex s five year business objectives covering this forward planning period Physical Environment South East Queensland (SEQ) experiences challenging environmental conditions in which to operate an electricity network. Although located in a temperate zone, SEQ has some of Australia s highest incidences of lightning activity, with Darwin the only other Australian capital city with a higher exposure. The spring and summer season is generally accompanied by severe storms where heavy rain and wind gusts in excess of 80 km/h are a common occurrence. These weather extremes expose the network to damage from overhanging vegetation, flying debris, wind damage and lightning. Climate change projections indicate increased storm and rainfall intensity, increased temperature, significant sea level rise as well as the potential for an increase in tropical cyclones tracking southward. Other aspects of the region s climatic conditions impacting the distribution network are: High rainfall areas with rapid vegetation growth; Periods of sustained high temperatures and or high humidity; Salt spray in exposed coastal areas resulting in reduced life of assets due to corrosion; and Bushfires, flooding and storm surges. Performance of the network under these conditions is discussed further in section Economic Activity Average economic growth in SEQ is expected to be stronger over the next ten years than it has in the past two years. However, Energex has used NIEIR s low case economic forecast in the electricity modelling, to offset the impact of the large LNG exports on the economic growth figures as they are expected to have a relatively smaller material impact on SEQ. One of the key drivers for electricity is population growth, which has been subdued for the past 3 years, but is projected to increase modestly over the next few years, boosting new connections which are also set to benefit from a continued decline in persons-per-household. For further details please refer to sections and Rising electricity prices and government subsidies from 2011 have changed customers behaviour towards electricity costs with reduced consumption and solar PV systems being installed in large numbers in SEQ. Cost of living pressures remain a concern for most people, so customers are looking at the alternative ways, such as solar PV and battery storage options, for improving their financial position. Impacts Changes in demand The electricity sector continues to face significant challenges as residential customers and businesses respond to rising prices by reducing their energy purchases from the Energex network. With the DAPR 2017/ /22

32 increased uptake of solar PV in the residential sector and now the commercial sector, the likely uptake of battery storage, and the potential demand of electric vehicles, the historical relationship between economic growth and grid supplied electricity is continuing to change Social and Demographic Change The sustained low fertility and increasing life expectancy lead to ageing in the Australia population. According to the March 2017 ABS report, the proportion of Australia people aged 65 years and over increased from 11.9% to 15.3% between 1995 and As the population ages and older workers retire, the new generation of primary income earners will hold different electricity usage patterns than previous generations. This was partly confirmed by the 2015/16 Queensland Household Energy Survey, with the results showing that the TV ownership was down from 97% in 2013/14 to 93% in 2015/16, while the ownership of multiple tablet devices continues to rise steadily. Accordingly, electricity consumption in Information Technology (IT) and home entertainment have decreased from a high of 1,055 GWh p.a. in 2011 to 747 GWh pa in 2017 according to the Energy Consult Pty Ltd report. The changes of social and demographic features will continue to impact typical network investment and asset lifespans and enable to transit the Queensland electricity market more quickly from non-renewable to renewable energy in the future. Impacts Increasing energy dependency At work and at home, the range and volume of electrical and digital equipment continues to proliferate. E-commerce and the ability to work remotely or while on the move is now a lifestyle expectation, along with access to the internet and social media. The impact of power outages or poor power quality is therefore likely to be more acute than previous experience. Emerging Technologies such as solar PV, Battery Storage and Electric Vehicles Now that a significant volume of solar PV is connected to the network the community is considering battery storage and in some case the purchase of plug in Electric vehicles as further options to control their energy costs and reduce greenhouse emissions. The interplay of these technologies will affect the peak demand in different ways in different parts of the network. Energex is committed to ensuring that these technologies can be connected to the network. Community Response Securing permission to build infrastructure when and where it is required is an important element in maintaining a sustainable and cost effective supply of electricity to Queensland. Enhanced engagement with local councils and community groups is required with regard to infrastructure design, feeder route selection and the development of more efficient and consistent approval processes and timeframes Technological Change New technology is influencing the way residential, commercial, and industrial customers use and source electricity. Trends affecting future consumption from the grid include increasing energy efficiency of equipment, the introduction of load control devices for home appliances, the change to energy efficient street lighting and the adoption of alternative energy supplies (solar PV). Future technology trends that are being monitored include battery storage and electric vehicles as well as the DAPR 2017/ /22

33 proliferation of internet enabled digital equipment, particularly as the National Broadband Network is rolled out. The further development of internet delivered and enabled service is expected to allow more sophisticated energy management systems. Impacts Changing supply and demand relationship With the support of Government and regulatory policy, customers are seeking options to manage their electricity consumption and costs. In recent years this has been through improved energy efficiency, the adoption of solar PV, and the requirement for greater transparency and information on energy consumption. The net result is reduced consumption of electricity supplied from the grid and changes in the shape of network load profiles. Technologies with the potential to significantly affect future consumption patterns include battery storage, electric vehicle, internet enabled technologies and services, particularly when combined with solar PV Shareholder and Government Expectations Energex and Ergon Energy are currently in the advanced stages of implementing the Queensland Government s electricity industry reforms. The centrepiece of this reform has been the creation of Energy Queensland through the merger of Ergon Energy Corporation Limited, Energex Limited and SPARQ Solutions. Merging Queensland s electricity distribution assets places the Energy Queensland Group in the best position to adapt to industry changes as a customer-oriented, efficient business. These reforms aim to deliver positive price outcomes for the State s electricity consumers as well as sustainable business returns to the Queensland Government, and ultimately the people of Queensland. They also build on the significant pre-merger Energex and Ergon Energy joint working activities undertaken to date. The Queensland Government also continues with its policy commitment to increasing the contribution of renewable energy to Queensland s energy mix. This includes setting a target for one million rooftops or 3,000 MW of solar PV in Queensland by 2020, and a commitment to providing long-term financial support to parties installing large-scale solar generation. Similarly, with the support of the Queensland Government, the Energy Queensland Group is working on Battery Energy Storage System (BESS) trials investigating how this emerging technology can best benefit the State s power distribution network and wider community. The Energy Queensland Group is also working to implement further industry reforms driven by the Federal Government. The Power of Choice (PoC) program is being implemented in Queensland with the aim of providing power users with additional options in the way they use electricity, better access to power consumption data and to expand competition in metering and related services. Moving forward, the Energy Queensland Group will continue to work closely with Government from both a regulatory and network planning perspective to ensure beneficial price and customer service outcomes for the Queensland community DAPR 2017/ /22

34 2.3.6 Community Safety Safety is a high priority for Energex for our employees, our customers and our community. Safety is at the core of our network planning and investment decisions. Chapter 9 details how Energex s asset life cycle management achieves a focus and drive to ensure safety of staff and the community as they interact with Energex and its assets. For example, Energex is actively replacing overhead conductor to specific areas based on the age, type and condition to mitigate the safety risks related to breaking and falling conductors. The Energex Community Safety Plan also demonstrates our commitment to community safety and outlines the initiatives and actions we implement to deliver this commitment. The objectives of the Community Safety Plan are to: Maximise channels to increase electrical safety awareness and understanding in the community (including the Electrical Safety Office, Safety Commissioner and Workplace Health and Safety Queensland); Monitor community safety issues to provide targeted programs; and Encourage the community to regard Energex as a recognised expert, and the point of contact for electrical safety. Key activities include the continuation of the Look Up and Live campaign, engagement with the regulator and other entities, safety awareness presentations, Safety Heroes primary school education program and participation in major industry events and agricultural shows. In 2017 the Community Safety Think Tank was held bringing together key internal and external stakeholders to generate further ideas to reduce the risk of the community and industry inadvertently contacting our network. For further information or a copy of the plan, go to the Energex website ( Energex places high importance on the safety of the public and the community. The Energex Community Safety Plan demonstrates how the company is meeting its commitment to community safety by drawing together the safety strategies, programs and activities undertaken across the business. The objectives of the Community Safety Plan are to: Maximise channels to increase electrical safety awareness and understanding in the community (including the Electrical Safety Office, Safety Commissioner and Workplace Health and Safety Queensland); Monitor community safety issues to provide targeted programs; and Encourage the community to regard Energex as a recognised expert, and the point of contact for electrical safety. The various initiatives, publications and safety messaging can be found on the Energex website ( Environmental Commitments Energex s commitment to the environment is reflected in Energex s Environment Policy which recognises industry standards for Environment Management and Ecologically Sustainable Development. Energex s environmental strategy is to deliver a commercially sustainable environmental position through compliance and sound business practices that minimises harm to the environment. Energex seeks to continually improve its Environmental Management System (EMS) DAPR 2017/ /22

35 which is ISO accredited. Practices such as environmental offsets, waste management, biosecurity and Cultural Heritage initiatives provide community benefits. Through the Energex Community & Sustainability Fund, Energex s recycling program has already supported multiple community groups by providing funding for their local projects. Energex recognises and takes into account community expectations to minimise and mitigate the environmental impacts from business activities. Energex actively engages with industry, community and other stakeholders to promote positive environmental outcomes on a range of issues such as emerging technologies in renewable energy sources, energy storage and infrastructure development Legislative Compliance Following the restructure of the Queensland Government s ownership of electricity distribution businesses on 1 July 2016, Energex Limited is now a wholly owned subsidiary of Energy Queensland Limited which is a Queensland Government Owned Corporation (GOC). The two shareholding Ministers to whom Energy Queensland Limited s Board report under the Government Owned Corporations Act 1993, are the Premier and Minister for the Arts; and Minister for Main Roads, Road Safety and Ports and Minister for Energy, Biofuels and Water Supply. Energex operates in accordance with all relevant laws and regulations, including: Government Owned Corporations Act 1993; Electricity Act 1994; Electricity Distribution Network Code; Electricity National Scheme (Queensland) Act 1997; The National Electricity (Queensland) Law as set out in the schedule to the National Electricity (South Australia) Act 1996; The National Electricity (Queensland) Regulations under the National Electricity (South Australia) Act 1996; The National Electricity Rules and National Electricity Retail Rules; Electrical Safety Act 2002; Work Health and Safety Act 2011; The Electrical Safety Codes of Practice 2010 and 2013; and State and federal environment and planning laws, including the Environmental Protection and Biodiversity Act 1999 (Cth), Environmental Protection Act 1994 (Qld) and Sustainable Planning Act 2009 (Qld) Economic Regulatory Environment Energex is subject to economic regulation by the Australian Energy Regulator (AER) in accordance with the National Electricity Law and Rules. The AER sets the amount of revenue that Energex is allowed to recover from its customers (through network prices) over a regulatory control period (typically 5 years). Energex s current regulatory control period commenced on 1 July 2015 and ends on 30 June DAPR 2017/ /22

36 Under the current regulatory framework, the AER sets the allowed revenues using a building block approach, consisting of the following elements: Efficient operating costs; Asset depreciation; Estimated cost of corporate income tax; Revenue adjustments resulting from the application of incentive schemes and from the application of a control mechanism in the previous regulatory control period; Revenue decrements arising from the use of assets that provide both standard control services and unregulated services; and An allowed return on capital, representing the return necessary to achieve a fair and reasonable rate of return on the assets invested in the business. More information regarding Energex s allowed revenues and network prices can be found on the AER s website ( DAPR 2017/ /22

37 Chapter 3 Customer Insights Overview Connecting With You Energy Supply Performance Customer Insights DAPR customer engagement and insights DAPR 2017/ /22

38 3 Customer Insights 3.1 Overview Energex is committed to ongoing engagement with its customers and community. Meaningful interactions will enable Energex to deliver on its core purpose: to provide choice and affordability to meet our customers evolving energy needs and ensure the business delivers balanced commercial outcomes. To realise our customer driven future and deliver for our customers, Energex has implemented a Customer Strategy that focuses heavily on the underlying principles of our customer and community interactions to create positive relationships and experiences. This chapter outlines the expectations of customers, gained through Energex s customer engagement program Connecting with you ( the 2016 Queensland Household Energy Survey (QHES) and targeted engagement undertaken with customers on the DAPR and how these expectations will be further incorporated into the business. This chapter also focuses on the aforementioned Customer Strategy and its role in customer interactions. 3.2 Connecting With You Energex launched the Connecting with you program in This engagement program is designed to enable customers to register an interest in having input into key business decisions that impact them. Registered customers are contacted when Energex seeks customer feedback on relevant issues. Customers can register online at Energex s website ( to receive communications. To date Energex has approximately 550 customers registered with the Connecting with you program Customer Engagement Strategy To support the incorporation of customer views and expectations in operational planning and business processes, Energex developed its Customer Strategy. This strategy is supported by a best practice Customer Engagement Strategy that defines Energex s vision, values and objectives of ongoing customer interactions. This engagement strategy focuses on how customer interactions will be conducted and allows for the alignment of customer expectations with business practices and investment decisions, helping Energex provide choice and affordability to meet our customers evolving energy needs. Energex s Customer Engagement Strategy and information about current customer initiatives can be found at Energex s website ( DAPR 2017/ /22

39 3.3 Energy Supply Performance As part of our commitment to deliver quality services to our customers and positively engage with our community, Energex continually assesses our performance and customer perceptions of energy supply performance. This is measured monthly through independent external market research through 180 randomised customer surveys with key service indicators such as: Restoration of power and convenient/timely information to customers; Reliability of electricity supply services; and Levels of network investment to meet customer expectations. Energex s energy supply performance results are consistently rated high. Energex also has two corporate measures - Community Regard Index (CRI) and Service Performance Index (SPI) which are also assessed monthly with the overall performance highlighted in the Statement of Corporate Intent, the Annual Report and Energex Business Plan. The CRI measures community reputation perception through indicators such as community involvement (sponsorships, safety and education programs), environmental responsibility, ethical business dealings and public confidence. The SPI differs from the CRI measure in that it assesses actual service performance. A sample of customers who have had dealings with Energex in the previous month are surveyed regarding the initial contact, issue resolution and service efficiency through to timeliness, quality of work performed and staff presentation, skills and behaviour. Both the CRI and SPI measures remain well ahead of corporate business targets. 3.4 Customer Insights The customer insights in this section have been sourced from the 2016 QHES. This annual survey of residential customers is run in conjunction with Ergon Energy and Powerlink and covers several behavioural topics around energy efficiency, appliance saturation and energy use. Energex values customer views and expectations gained from the QHES in helping inform decision making. QHES Key Findings Customers are replacing appliances with newer technology and owning fewer of the same appliances. In the last five years the biggest ownership increases have been in LED or LED/LCD televisions, LED light bulbs, tablet computers, 3D televisions and instantaneous hot water systems. Over the same period, the largest decreases in ownership have been in desktop computers, stereos, compact fluorescent light bulbs, LCD televisions and electric heaters; Changes in the way customers use entertainment devices may shift electricity consumption away from the lounge room. Ownership of multiple tablet devices continues to increase while ownership of at least one television has decreased by 4% (to 93%) since 2013; DAPR 2017/ /22

40 Air-conditioner penetration has remained stable at 75%. This is forecast to increase only slightly to 81% by The use of split system air-conditioners in newer homes (less than five years old) is declining, although is steady at 64% in 2016, with ducted airconditioning systems gaining popularity, increasing from 25% in 2015 to 28% in The number of people purchasing portable systems remains steady at 3% in 2016; The level of concern about electricity costs has decreased in South East Queensland over the past twelve months, with only 33% of customers stating a high concern, down from 38% in Although bill concern is still relevant for many people, the findings also show that fewer customers are taking steps to reduce their energy consumption and mitigate the impact of high bill concern, with households performing fewer energy efficient behaviours; Customers are also purchasing fewer solar PV systems, with the number plateauing at 16% of South East Queensland respondents recording intention to install solar PV during the next two years. However, this figure is significantly higher in homes less than 5 years old, at 27%, up from 18% in This rate of uptake may change once battery storage becomes more widely available; and Customer knowledge and understanding of battery storage has increased significantly across South East Queensland, with approximately 56% of respondents indicating awareness (up significantly by 10% from 2015). The greatest motivation for the adoption of this new technology is the desire for self-sufficiency, which is closely followed by the storage of electricity for use in peak times. However, the upfront costs of battery storage are still prohibitive for many customers, with 50% of respondents indicating the purchase price is too expensive, up 15% from Purchase intent is likely to increase when the technology is more affordable, such as when battery storage costs are more in line with solar PV. Customers who intend to purchase battery storage expect to pay $5,400. This is a substantial increase on the 2015 expectation of $4,621, yet still an underestimation of current, substantially higher prices associated with battery storage systems. In addition to the QHES, Energex also collects ongoing customer insights through other engagement practices and channels centred on our program of work and other business activities. Energex also as a Customer and Community Council and Commerce and Industry Panel that meet periodically throughout the year to ensure the customer and community voice is heard on key strategic initiatives. 3.5 DAPR customer engagement and insights In early 2016, Energex sought targeted customer feedback to enhance customer useability of the DAPR by engaging with demand side proponent customers who are current users of the DAPR. Their feedback informed the development of improvement recommendations for the 2016 DAPR and future DAPR publications. In addition, Energex hosted the 2016/17 to 2020/21 DAPR Forum in November 2016 to provide these customers with an overview of the latest DAPR, its focus and why, what changed, acknowledging customer feedback and its incorporation, and the opportunity to provide and ask questions DAPR 2017/ /22

41 DAPR Forum Insights Need for greater focus on accommodating and planning for increased Solar PV on the network, as this was seen as the major area of continued future growth; Require better understanding of how customers will use Solar PV systems, particularly when they begin to integrate them with battery storage and home energy management systems; Consider the impact of demand management programs and how they can be used to mitigate voltage impacts from Solar PV systems; Require better understanding of the drivers for and likely uptake of commercial Solar PV systems which have the ability to have a major impact on the network and its revenue if they become more widespread; Consider programs or solutions to incentivise customers to hold on to or use energy generated from their Solar PV systems to reduce voltage impacts from large exports; and Consider smarter technology and data to better identify when assets are coming to the end of their life and are at risk of failure. DAPR Forum Engagement Outcomes Understand more about the challenges Energex faces in order to be able to develop viable, cost effective and mutually beneficial solutions; Have access to more detailed information about sub RIT-D projects, including feeder information and whether long term or short term solutions are required; Be provided with information identifying small projects (e.g. transformer replacements) that non-network projects may be viable for, and be provided with the data to work out if they can provide a cost effective solution; and Be more involved and form productive relationships with Energex to undertake joint projects, for example in the demand management space. Energex will continue engaging with targeted customers following publication of the 2017 DAPR to enhance the planning process for the 2018 DAPR DAPR 2017/ /22

42 Chapter 4 Asset Management Overview Best Practice Asset Management Asset Management Policy Strategic Asset Management Plan Asset Management System Network Investment Process DAPR 2017/ /22

43 4 Asset Management Overview Management of Energex s current and future assets is core business for Energex. Underpinning Energex s approach to asset management are a number of key principles, including making the network safe for employees and the community, delivering on customer promises, ensuring network performance meets required standards and maintaining a competitive cost structure. This section provides an overview of Energex's: Best Practice Asset Management; Asset Management Policy; Strategic Asset Management Plan (SAMP); Asset Management System; and Network Investment Process. 4.1 Best Practice Asset Management Energex recognises the importance of maximising value from assets as a key contributor to realising its strategic intent of achieving balanced commercial outcomes for a sustainable future. To deliver this, Energex s asset management practice must be effective in gaining optimal value from assets. Energex is continuing to reshape its Asset Management practice to align with the ISO standard. This transition is a significant undertaking and will span several years, so a phased approach has been initiated focused on building capability across all seven major categories covered by the standard (i.e. Organisational Context, Leadership, Planning, Support, Operation, Performance Evaluation and Improvement). 4.2 Asset Management Policy The asset management policy provides the direction and broad framework for the content and implementation of Energex s asset management strategies, objectives and plans. The policy directs Energex to undertake requirements associated with safety & people, meeting customer needs, and the commitment to ensure asset management enablers and decision making capability meets the current and future needs of Energex. This policy together with the strategic asset management plan are the primary documents in the asset management documentation hierarchy and influence subordinate asset management strategies, plans, standards and processes DAPR 2017/ /22

44 4.3 Strategic Asset Management Plan Energex s strategic asset management plan (SAMP) is the interface that articulates how organisational objectives are converted into asset management objectives as shown in Figure 4. The SAMP also sets the approach for developing asset management plans and the role of the asset management system in supporting achievement of the asset management objectives. Figure 4 SAMP translates Corporate Objectives to Asset Management Objectives Asset Management Key Objectives The Energex strategic agenda is translated into the Asset Management objectives via the Strategic Asset Management Plan. These objectives, as shown in Figure 5 establish the direction and desired outcomes that Asset Management strategies, plans and initiatives will target DAPR 2017/ /22

45 Figure 5 Asset Management Objectives Asset Management Plans and Initiatives As part of Energex s transition to align with ISO 55000, a suite of Asset Management strategies are now in place. These include strategies for Network Telecommunications, Metering, Power Quality and Demand Management. In addition Energex is further developing Asset Lifecycle Plans for key network assets (e.g. conductors, poles, transformers etc.) to enhance asset lifecycle management decision making and ultimately the value realised from assets. 4.4 Asset Management System The Asset Management system supports achievement of Energex s Asset Management objectives by ensuring the key system elements are operationalised as part of Energex s Asset Management practice. The system also ensures the Asset Management planning process, capabilities and decision making take into account the inter-relationships and interdependencies between the system elements. Effective integration of these elements ultimately determines the success with which Energex maximises value from its assets. The Asset Management system depicted in Figure 6, conceptualised by the Institute of Asset Management and adopted by Energex is a revised version of the system published in 2014/15 to ensure alignment with the ISO standard DAPR 2017/ /22

46 Figure 6 Energex s Asset Management System 4.5 Network Investment Process Corporate Governance Energex has a five-tier governance process to oversee future planning and expenditure on the distribution network as shown in Figure 7. Central to Energex s governance process is legislative compliance. The Government Owned Corporations (GOC) Act requires the submission of a Corporate Plan (CP) and Statement of Corporate Intent (SCI) while the NER requires preparation of the DAPR. The five tiers include: Asset Management Strategy & Policy: Alignment of future network development and operational management with Energy Queensland strategic direction and policy frameworks to deliver best practice asset management. This guides operational plans and work to implement the strategy; Program of Work (PoW) Strategy & Plan: High level expenditure targets and forecasts approved by the Board as part of the five year Corporate Plan and the Statement of Corporate Intent, required to deliver the Asset Management Objectives; DAPR 2017/ /22

47 Network Investment Portfolio: Development of five year rolling expenditure programs and a 12-month detailed program of work which is established through the annual planning review process; (including individual projects approved by the EQL Board). The Risk and Compliance Committee, a subcommittee of the Energy Queensland Board, oversees the fulfilment of Energex s compliance commitments and ensures the network risk profile is managed and aligned to the corporate risk appetite; Project and Program Approval: Network projects and programs are overseen by senior management and subject to an investment approval process, requiring business cases to be approved by an appropriate financial delegate. The development of programs and projects is undertaken by the PoW Development & Review Forum and is in compliance with the relevant EQL policy, protocols and standards; and PoW Performance Reporting: Energex has specific corporate Key Result Areas (KRA) to ensure the PoW is being effectively delivered and ensures performance standards and customer commitments are being met. The Network Operations and Steering Committee meets on a monthly basis to review operational and financial performance, and provides direction to resolve issues. Figure 7 Program of Work Governance Network Risk Management and Program Optimisation Management of risk is a crucial foundation for effective Asset Management and an integral part of best practice Asset Management under the ISO standard. Energex s network risk management framework was developed to provide a consistent approach to the assessment of network risks. It DAPR 2017/ /22

48 maintains consistency with AS/NZS ISO 31000:2009 Risk Management - Principles & Guidelines, and with the organisations enterprise risk management framework. The network risk is assessed by the following five risk categories: Safety; Environment; Legislated Requirements; Customer Impacts; and Business Impacts. Projects and programs are assessed against each of these risk categories as appropriate, with development of a credible scenario of events that lead to a chosen risk consequence, followed by estimation of the likelihood of occurrence of the scenario. Projects and programs of work are then considered and addressed on a priority basis when optimising the program of work to deliver tolerable risk outcomes. Energex optimises its five-year program of work to balance risk, cost and performance targets, by reviewing project drivers, cost (including Capex and Opex trade-offs) and the untreated risk of programs not proceeding Investment Guidance Energex prepares its expenditure programs in compliance with its obligations and its corporate objectives. The capital and operating expenditure and efficiency objectives that Energex must satisfy are defined in the NER, in particular clauses (a) and (a). Achieving the corporate objectives will require the balancing of cost, risk and performance outcomes to gain optimal value from assets, combined with new business models and investments in people, systems and processes. The following principles inform the approach for selecting the optimal solution: Enhance decision support systems to provide information that can be understood and used for Asset Management and operational decision making; Align standards with international best practice; Create network adaptability and analysis through greater investment and use of IT devices to complement the traditional backbone long-life asset strategies; Adopt advanced components and enable the adoption of evolving asset technologies that integrate into the network with existing assets; Adopt an integrated, seamless communications infrastructure that supports multiple platforms to deliver reliable, efficient and secure information exchange; Enhance real-time monitoring and control of the system to appropriately respond to events; and Facilitate demand side customer solutions through digital technology advances and information exchange. The efficient use of electrical infrastructure is key to Energex s prudent and efficient Asset Management practice and central to the assessment of expenditure options. The benefits that flow from prudent and efficient capital expenditure include minimising electricity cost, a safe network, modern assets with increased performance and low maintenance costs. These are assessed against the benefits of operational expenditure DAPR 2017/ /22

49 Energex considers the trade-off between capital and operating expenditure in the following ways: Design and maintenance standards the building block approach that Energex uses to develop its network is designed to minimise the whole of life cost of assets. Enhanced network outcomes are also achieved by the implementation of new equipment designs resulting from advances in technology; Renew, replace or maintain assets the decision to replace or maintain an asset is supported by the comprehensive Condition Based Risk Management (CBRM) methodology to assist in determining the optimum time to replace an asset; Equipment specification and purchasing a key objective when purchasing assets is to minimise whole of life costs. This assessment criterion is incorporated into Energex s procurement process for evaluating plant and equipment purchases; Investment in assets that will function in long term climate change scenarios (e.g. extreme wind and flood events,1:100 years); and Demand management in compliance with Clause of the NER. Energex s planning process will include application of the Regulatory Investment Test for Distribution (RIT-D). This test is an important planning and consultative tool that ensures non-network solutions are also considered. In addition, Energex identifies where targeted area based schemes can defer projects identified over the five to ten year planning horizon Asset Management Investment Process The Asset Management Investment Process considers the portfolio of projects and programs proposed for inclusion in the future Program of Work (PoW) on a consistent basis by: Reviewing programs and projects to assess the justification relative to drivers, risks, cost and performance targets; Reviewing the risks if the proposed programs and projects were not to proceed, and how the untreated risk could be otherwise managed to tolerable levels; and Optimising the portfolio of the PoW to deliver the appropriate balance between risk, resources (including cost), and achievement of performance targets. Outputs of this process include optimised network risk profiles across the capital and operating PoW. Figure 8 displays the overarching Network Investment and Implementation Process. The process captures Asset Management strategies, regulatory obligations and customer engagement objectives to provide a long-term strategic direction for managing network investment. The combined application of existing assets, new assets, enhanced assets, and new technologies are key features for implementing prudent network planning solutions. Importantly, prudent network planning activities rely on meeting set performance and service standards, which are a key input to this process DAPR 2017/ /22

50 Figure 8 Network Investment Process Program of Work Implementation Once a project or program is approved, it goes through the design, post-approval, construction and commissioning phases as part of program delivery. Depending on the extent of the scope, proposed projects range from minor projects to significant infrastructure works. Therefore, projects can take between one and three years (with some extending to 5-7 years) from approval to final commissioning. This can vary significantly depending upon jurisdictional (i.e. community consultation and environmental) approval processes DAPR 2017/ /22

51 Chapter 5 Forecasting Forecast Assumptions Electricity Delivered Forecasts Substation and Feeder Maximum Demand Forecasts System Maximum Demand Forecast DAPR 2017/ /22

52 5 Forecasting Forecasting peak demand and electricity delivered values for the next ten years has become a difficult and complex task. However it is essential to the planning and development of the electricity supply network. Energex has adopted a detailed and mathematically rigorous approach to forecasting of electricity delivered, demand, and customer numbers. The methods used by Energex are described in the following sections. Energex also undertakes regular audits and reviews by external forecasting specialists on the forecasting models and continues to improve the demand and electricity delivered forecasting methodologies. Energex s 10 year electricity delivered forecasts are prepared at the total system level, customer category levels and for each individual network tariffs. These forecasts are used to determine annual network losses and for establishing network tariff prices. The electricity delivered forecasts are developed using the latest economic, electricity consumption and technology trend data. Key assumptions used in the development of these forecasts are documented and updated regularly. In relation to demand, forecasts are not only undertaken at the system level, but are also calculated for all substations and feeders covering a period of 10 years. These forecasts are used to identify emerging network limitations, and identify network risks, that need to be addressed by either supply side or customer based solutions. The forecasts are then used as an input to the timing and scope of capital expenditure, or the timing required for demand reduction strategies to be established, or risk management plans to be put in place. Energex also prepares a separate forecast for customer numbers as a key contributor to its Program of Work. 5.1 Forecast Assumptions There are a number of drivers which influence Energex s forecasts of electricity delivered, demand and customer numbers. Assumptions used by Energex in the development of the demand and electricity delivered models are discussed in the following sections Customer Behaviour Customer behaviour is a primary driver of the electricity delivered and peak demand forecasts. There are several indicators of customer behaviour, including customer take up of solar PV and/or battery storage, take up of energy efficient appliances, the impact of higher electricity prices on customer response and the choices customers make about their use of electricity. Recent Household survey results indicate customers are undertaking less energy efficiency measures and are less concerned about electricity prices. Customer behaviour is challenging to model as it can vary substantially between customer groups and from year to year Solar PV Systems Connected Solar PV capacity continues to grow at a steady pace since the period of high growth up to 2013 when the feed in tariffs subsidies were reduced. Solar PV is now steadily increasing at about 1,300 to 1,600 connections per month. As at 30 June 2017, there were 331,197 (23% of all DAPR 2017/ /22

53 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 Load MW customers) solar PV systems connected across South East Queensland, with the total capacity (in terms of invertor size) of 1,225 MW. The total electricity exported to Energex is expected to be 758 GWh in the 2016/17 financial year. This value is the best assessment for the final electricity exported figure for 2016/17 and will be validated when all the quarterly metered accounts are read. The impact of increased solar PV penetration on domestic zone substation peaks and domestic feeders is minimal as the peak demand on these substations tends to occur after daylight hours in the early evening. Without battery storage systems, there is likely to be very little impact on residential substation peak demands as a direct result of solar PV. Similarly, the impacts on domestic peak demand for upstream assets have also tended to be negligible. There are now a growing number of solar PV installations located on commercial and industrial buildings which are attached to commercial and industrial day peaking substations and 11 kv feeders. These installations are of some benefit to Energex in reducing summer day peak demand, and may continue to increase driven by the Queensland Government s aspirational target of having the equivalent of one million rooftops or the equivalent of 3,000 megawatts of solar PV installed by The net result is that on a typical peak day, there may be an overall reduction in network peak demand as a result of solar PV. As shown in Figure 9 for 18 January 2017, the system peak occurred at 4.30 pm, and it was estimated that solar PV reduced the peak by more than 289 MW. It is expected that without battery storage, as more solar PV is connected to the network the summer peak will shift into the early evening (residential load peak). As battery storage becomes more affordable this trend will most likely to be reversed and the system will continue to peak during the late afternoon. Figure 9 Energex System Demand Solar PV Impact, 18 January ,500 Recorded Solar Total 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Load without solar PV Generation Load with solar PV Generation Solar PV Generation Time of Day DAPR 2017/ /22

54 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 Load MW Figure 10 shows the effects of solar PV on Brisbane North 11 kv feeder AHL12A on a peak day. Solar PV generation is estimated to have less than 1 MW impact on the peak demand for this feeder. Figure 10 Solar PV Impact on Arana Hills AHL 12A on the Peak Day Recorded Solar Total Load without solar PV Generation Load with solar PV Generation Solar PV Generation 0.0 Time of Day Similarly, Lota is a typical domestic substation located east of Brisbane with a significant quantity of residential solar PV systems and peak demand is unaffected by solar PV. This is demonstrated in Figure 11, where the impact on the half hourly demand for a peak day is shown DAPR 2017/ /22

55 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 Load MW Figure 11 Solar PV Impact on Lota Substation on a Peak Day 30.0 Recorded Solar Total Load without solar PV Generation 15.0 Load with solar PV Generation Solar PV Generation 0.0 Time of Day Importantly, solar PV capacity is expected to continue to grow at a lower but steady rate compared with the growth up to 2013 due to changed tariff incentives. This assumption has been built into Energex s future load forecasts Electric Vehicles Electric vehicles (EVs) and Plug in Hybrid electric vehicles (PHEVs) have the potential to increase electricity delivered and demand forecasts for Energex in the future. Currently, the take up rate of EVs and PHEVs has not been high due to the high initial cost and low availability of models and therefore the impact factored into the System Demand forecast has been relatively small. The expected impact of plug-in electric vehicles has been included into this latest forecast for residential zone substations Battery Storage Customer interest in battery storage capability is increasing with the number of known battery storage systems now at 250. Over the next 10 years this is likely to change with bundled solar PV and battery storage systems being promoted by the major retailers and solar PV installers. Energex has adopted a slow but steady reduction in peak demand due to the use of battery storage in the base case scenario forecasts for residential zone substations. The assessment used in the Energex model is based on the peak day profile and the most likely customer usage pattern. These assumptions will be refined over time as more customers adopt storage systems and the usage data becomes available DAPR 2017/ /22

56 2005/ / / / / / / / / / / /17 Number of Days Temperature Sensitive Load and Air-conditioning Growth One of the main drivers of the forecasts is the amount of temperature sensitive load, particularly from air-conditioning and refrigeration. On particularly hot days, this load can add significantly to levels of electricity consumption, and more importantly, peak demand Temperature sensitivity Data shows the continuing sensitivity of customer load to temperature, and Energex models this impact in its forecast. In SEQ, summer 2016/17 was warm and wet. As Figure 12 shows two nonworking days had an average temperature that exceeded the standard 50 PoE temperature of degrees at Amberley. Figure 12 Number of Days at Amberley > Standard Temperature (30.65 C) 6 5 Work Days Non Work Days Moreover, Figure 13 shows a comparison of hot days (maximum temperatures above 30 C) for the past 10 summers using Amberley temperature data DAPR 2017/ /22

57 2007/ / / / / / / / / /17 Number of Days Figure 13 Number of Days with Maximums > 30 C at Amberley December January February March Days 61 Days 51 Days 64 Days 60 Days 60 Days 71 Days Days 38 Days 39 Days Figure 13 indicates that the temperature over the past four summers is more typical (more than 60 days where max temp > 30 o C) than the mild summer of 2010/11. The temperature sensitivity is modelled by calculating a coefficient that compares system peak demand to average daily temperature at Amberley for each summer season. In 2016/17 the calculated coefficient was 202 MW/ C, compared with 193 MW/ C and 190 MW/ C for 2015/16 and 2014/15 respectively. The general trend in sensitivity has continued to increase since 2003/04 although it is starting to flatten out as shown in Figure 14. If the trend continues, it is anticipated that the temperature sensitivity of the Energex demand will be approximately 212 MW/ C for a normal summer in 2017/18. Figure 14 also shows the historical trend of the ratio between temperature sensitivity and the temperature corrected peak demand. Air-conditioner sales have been higher this summer indicating customers are more likely to update or add to the air-conditioning load in their homes in response to the hotter summer DAPR 2017/ /22

58 Sensitivity MW/ C Sensitivity as a % of Temp Adjust Peak Demand Figure 14 Summer Demand Temperature Sensitivity Sensitivity MW/ C Sensitivity as a Percentage of Temperature Adjusted Peak Demand 9.00% 8.00% 7.00% 6.00% 5.00% 4.00% 3.00% 2.00% 1.00% % Figure 15 illustrates the temperature sensitivity of Mango Hill zone substation by comparing the substation load profile on the day of system peak (18 January 2017) with that of one week later (25 January 2017). On the day of system peak demand, the peak temperature at Amberley was 36.8 degrees and 33.6 degrees one week later. Both days are outside the school holiday period. It can be seen that the Mango Hill zone substation peak demand is almost 8.9 MW higher for an Amberley temperature difference of 3.2 degrees DAPR 2017/ /22

59 00:00 01:00 02:00 03:00 04:00 05:00 06:00 07:00 08:00 09:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 Load MW Figure 15 Mango Hill Zone Substation Temperature Sensitivity Wednesday 25/01/2017 Wednesday 18/01/ o C peak at Amberley o C peak at Amberley Time of Day Energex has used three weather stations in this year s model and weighted the temperature impact on daily peak demand. The three weather stations were Amberley, Archerfield and Brisbane airport and these were selected to try to capture the impact of the sea breeze effect on total system peak demand. Figure 16 shows the daily system demand, and the daily temperature conditions measured at Amberley for the 2016/17 summer. The weekday system maximum demand for 2016/17 was recorded at 4,814 MW on Monday 18 January On this day, the maximum temperature at Amberley was 36.8 degrees. The 2016/17 summer forecast 50 PoE demand for the Energex system was 4,640 MW. In summary, the peak demand is highly correlated to temperature and the actual 50 PoE demand for the 2016/17 summer was 4,840 MW, which was 3% or 200 MW above the forecast of 4,640 MW DAPR 2017/ /22

60 1/12/2016 4/12/2016 7/12/ /12/ /12/ /12/ /12/ /12/ /12/ /12/ /12/2016 3/01/2017 6/01/2017 9/01/ /01/ /01/ /01/ /01/ /01/ /01/ /01/2017 2/02/2017 5/02/2017 8/02/ /02/ /02/ /02/ /02/ /02/ /02/2017 Degrees C Demand MW Figure 16 Peak Demand and Temperature Range at Amberley MinT MaxT AveT 90 POE AverageTemperature 50 POE Average Temperature 10 POE Average Temperature Load 50 POE Forecast Demand 10 POE Forecast Demand School Holidays 5,500 5,000 4,500 4, ,500 3,000 2,500 2,000 1,500 1, Figure 17 shows that in winter, there is a clear correlation between increasing temperature and decreasing load. In the shoulder seasons, where average temperature ranges between 16 degrees and 23.5 degrees, base load is relatively flat. For summer periods, where average temperature ranges upwards from about 24 degrees, there is a steady increase in demand on the Energex network, and this has become more pronounced over time relative to where it was 14 years ago DAPR 2017/ /22

61 Demand MW Figure 17 Energex System Demand Variations by Average Temperature and Season 5,750 5,500 5,250 5,000 4,750 4,500 4,250 4,000 3,750 3,500 3,250 3,000 2,750 2,500 2,250 2, Winter / 2016 Shoulder / 2017 Summer 2002 Winter / 2002 Shoulder / 2003 Summer Winter period Shoulder period Summer period Average Temperature o C In summary, there is a strong correlation between temperature and demand on the Energex network, which has increased over time due to increasing temperature sensitive loads. Energex continues to monitor the temperature sensitivity of demand at both the system level and the zone substation level and also the variables that influence this sensitivity such as appliance efficiency, price and customer behaviour. Air-Conditioning Air-conditioning load in SEQ is continuing to increase at a much slower rate than previous historical values as shown in Figure 18. Energex has used a base case air-conditioning forecast produced by consultants in the early testing of the latest system demand model. The air-conditioning load base case variable was used in the development of the peak demand forecast model DAPR 2017/ /22

62 2005/ / / / / / / / / / / / / / / / / / / / / / / /29 Load in MW Figure 18 Air-Conditioning Connected Load Forecast 5,000 4,500 Base Case Forecast Load 4,000 3,500 Historical Load 3,000 2,500 2,000 1,500 1, Note: The forecast air-conditioner load was considered as an input to the system demand forecast model. Not all air-conditioners in SEQ operate or draw full power at the same time. Due to this diversity, the data does not represent the net contribution of air-conditioner load to the system peak demand. Importantly, while air-conditioning load growth is beginning to flatten, the sensitivity of the significant latent air-conditioning load already on the network remains a challenge to manage. Whilst peak demand sensitivity to temperature is forecast to continue to increase at a slower rate, given normal hot summers, the temperature sensitive load will heavily influence the peak demand on the network Economic Growth A second major driver of the Energex forecasts is the level of economic growth. It can be seen from Figure 19 that the Queensland s economy slowed sharply over the 2014/15 and 2015/16 financial years, with growth rates of merely 1.2% and 2% respectively. This is well below the long term average of 4.1%, and was largely driven by the sharp declines in both private (e.g. mining) and Government investment, significant falls in global commodity prices and sluggish household spending. The general consensus view (from external forecasters) is that the Queensland economy will accelerate to around 2.5% in the 2016/17 year (note the final outcome for 2016/17 is not available from the ABS until November each year), boosted by the improved activities in the volume of exports, tourism, education services, housing, agriculture, and small manufacturing industries, as a result of a lower value of the Australian dollar and low interest rates. In the longer term, there is considerable divergence in forecasts around the strength of the state economy DAPR 2017/ /22

63 Figure 19 shows the forecasts of Queensland Gross State Product (GSP) developed by a range of forecasting organisations including National Institute of Economic and Industry Research (NIEIR), Deloitte, Queensland Treasury and St. George Bank. NIEIR and Deloittes (the only 10 year Queensland forecasts available to Energex) both expect the Queensland economy to grow more strongly over the next 10 years (NIEIR 2.7% p.a. average, Deloittes, 3.8%) than it has over the last 2 years (est. 1.6% average p.a.). However, Energex has used NIEIR s low case (Deloittes only has a base case) economic growth forecast in the peak demand forecast model. This is based on two assumptions: Firstly, GSP measures the aggregate economic activities throughout the whole rather than part of Queensland, yet the Energex maximum MW demand only applies to the South East corner of the state. The new LNG plants in North Queensland are pushing up the state economy but have limited impact on economic growth in the South East Queensland. Secondly, while GSP directly affects business firms, its influence on ordinary households is limited because electricity is a necessary good for them. The majority of the households, regardless of their income levels, will use more electricity in the peak time of a hot day, but won t use unnecessary extra amount if the temperatures are mild. Over 2017/18 and 2018/19 the Queensland economy is expected to grow by around 2.1% per annum before gradually slowing down to 1.5% over 2019/20 and 2020/21. It will re-gain the momentum of 1.8% in the 2021/22 and 2022/23 years, then stabilising at around 1.5% over the following 4 years. The above organisations are considered independent and authoritative sources. Figure 19 also shows a comparison of the forecasts for Queensland GSP over the next ten years. Figure 19 Queensland GSP Growth Forecasts Note: Economic data was sourced from ABS, Deloitte, NIEIR, Queensland Treasury and St George Bank DAPR 2017/ /22

64 1990/ / / / / / / / / / / / / / / / / / /27 Population ('000) Population Growth A third driver of the forecasts, closely tied to economic growth, is population growth. Queensland population growth has been subdued for the past three years as a direct result of the economic slowdown and the reduced employment opportunities in Queensland. For example, annual population only increased by 1.2% in both the 2014/15 and 2015/16 financial years, the lowest growth over the past 24 recorded years. This was dragged down by the very soft increases in Net Overseas Migration (NOM of 19,076 and 21,090 respectively the lowest over the past 15 recorded years), and the Net Interstate Migration (NIM, 6,417 and 6,998 respectively only marginally above the historical low of 5,753 recorded in the 2013/14 financial year). In terms of future population movements, the main economic institutions such as NIEIR, The Office of Economic and Statistical Research (OESR) and Deloittes, project that the population growth is expected to increase over the next few years, boosted by a rebound in the state economy (which in turn, will attract more inter-state migration NIM, and overseas migration NOM) as well as a relatively competitive Australia currency (which in turn, will attract more overseas students and tourist arrivals). Accordingly, Queensland population growth is expected to accelerate to 1.5% in the 2018/19, and more or less stabilise at that rate over the following 8 financial years. The majority of the Queensland population growth will occur in the South East corner (with 68.8% of state population as at the end of June 2016), with the major development areas such as south of Ipswich are growing strongly as areas like Ripley Valley are developed. Other growth areas include the northern Gold Coast, the southern Sunshine Coast, the Logan area including Yarrabilba and Flagstone, and the northern Brisbane gateway. Population growth continues to support the growth in commercial and industrial customers in terms of employment and support facilities (e.g. shopping centres, sporting facilities and schools). A summary of projected population by location is shown in Figure 20. Figure 20 Queensland Population Projections 6,000 5,000 QLD Population SEQ Population Forecast Period 4,000 3,000 2,000 1, DAPR 2017/ /22

65 1991/ / / / / / / / / / / / / / / / / / /28 Average Persons Per Household The ratio of SEQ population to customer numbers reflects the number of people per household. The number of people per household affects both electricity consumption and peak demand. Figure 21 shows Energex projected trend in number of persons per household in SEQ. Figure 21shows the historical movements, along with the Energex projected trend in number of persons per household in SEQ. The initial trend towards fewer persons per household, driven by an ageing population and an increase in single person households, had been expected to contribute to continued customer growth. However, this effect has been superseded since 2001 by the growth in stay at home young adults and the multicultural effect of older members of the family remaining in the family home due to high housing costs. The upward trend reached a high in the 2013/14 year, preceding a slight fall between the 2014/15 and 2016/17 years. Looking ahead, the number of persons per household in SEQ will remain stable largely stable over the forecast horizon. Figure 21 Average Number of Persons per Household in SEQ 2.8 Actual Forecast Forecast Period Note Energex forecast is based on Australian Bureau of Statistics data. In summary, population growth in Queensland will start to re-gain its momentum over the next few years. Customer numbers will continue to increase at a steady rate over the next ten years. Figure 22 illustrates the forecasted total new customer numbers to June Customer numbers at the end of the 2016/17 year were 1,439, DAPR 2017/ /22

66 1991/ / / / / / / / / / / / / / / / / / /28 New Customer Numbers Figure 22 New Metered Customer Number Growth 40,000 35,000 Actual Forecast Forecast Period 30,000 25,000 20,000 15,000 10,000 5, Electricity Delivered Forecasts Energex prepares new 10 year electricity delivered forecasts once each year using the latest electricity delivered figures, economic, demographic and weather data. The forecasts are based on customer categories and disaggregated into two major groups residential and non-residential. Nonresidential includes commercial, industrial and rural sectors. The forecasts are used to review and develop network prices for both Energex and Powerlink Electricity Delivered versus Electricity Consumption Electricity delivered represents the amount of electricity that Energex transports through its network, which is measured by customer meters. Whereas, electricity consumed is the amount of electricity actually used by customers within their premises, and therefore includes electricity supplied by other resources such as solar PV. Energex forecasts electricity delivered for use as a key input into the pricing process. Solar PV has, and will continue to have, a significant impact on Energex electricity delivered because consumers can use this alternative energy resource to partly offset the amount of electricity delivered by the Energex networks. However, it has little impact on households electricity consumption, since consumption is largely determined by different drivers such as household income, electricity prices and hot/cold temperatures rather than by different supply sources DAPR 2017/ /22

67 2007/ / / / / / / / / / / / / / /22 Number of solar PV Installations The number of solar PV connections had increased strongly over the 2009/10 to 2012/13 period, driven by escalation of electricity prices, solar feed in tariffs, environment issues and the price reductions in solar panels. However, the growth rate has tapered in the last few years, as a result of the removal of the subsidies offered by the federal Government and the policy change of the feed-in tariff at the state level. Looking ahead, new PV connections, as shown in Figure 23 are expected to continue to increase. It is also worth noting that the capacity size per new installation keeps growing mainly due to the cheaper solar panel unit prices. In addition, the new non-domestic installation numbers, along with their capacity sizes, will continue to increase as firms try to partly offset their electricity usage cost. The Queensland Government s has a keen focus on renewables, and they have a number of initiatives underway, including an aspirational target to have one million rooftops or the equivalent of 3,000 megawatts of solar PV installed by 2020, and Solar 150 which has a focus on encouraging new large-scale renewable energy projects in Queensland. The PV forecast is based on historical trends and projections of Energex s future share of PV with these initiatives. Figure 23 Number of Solar PV Installations 600,000 PV total installs Forecast Forecast Period 500, , , , ,000 0 Figure 24 shows the increasing avoided electricity delivered as a direct result of solar PV generation supplied to both residential and non-residential customers. It becomes clear that while electricity delivered will be flat over the next 6 years, electricity consumption (i.e. electricity delivered by Energex plus electricity generated and used internally) has started to stabilise and will continue to increase, propelled by the expanding population base, the increased household income, and the reduction in energy efficiency improvements in key electric equipment. Estimated electricity delivered for the 2016/17 year is expected to be 21,324 GWh, which is 0.87% above the 2015/16 value. This value is the best assessment for the final electricity delivered figure for 2016/17 and will be validated when all the quarterly metered accounts are read DAPR 2017/ /22

68 2007/ / / / / / / / / / / / / / /22 Solar PV Impacts on Electricity Delivered (GWh) Figure 24 Solar PV Impacts on Electricity Delivered Avoided Energy Usage Total Energy Delivered Total Consumpt Growth % Domestic Energy Delivered Growth % 25, % Forecast Period 4.0% 20, % 2.0% 15, % 0.0% 10, % -2.0% 5, % -4.0% 0-5.0% Electricity Delivered Forecast Methodology The adopted approach by Energex for forecasting electricity delivered is a combination of statistically based time series analysis, multifactor regression analysis, and the application of extensive customer knowledge and industry experience. Regression models and consultant reviews are used to substantiate the forecasts, which are separately formulated for each of the following sectors: Residential; Non-Residential; and Network Tariffs. For each of the sectors listed above, forecasts are produced for the total customer numbers and the amount of electricity usage per connection or customer. The forecasts of customer numbers and average usage per customer are then multiplied together to obtain total electricity consumption for each segment. Total system electricity delivered is the summation of each of the components. This is a market sector or bottom-up approach and provides a reasonable basis for constructing forecasts for total system electricity use. Each sector is affected by different underlying drivers for growth. For example, population and income growth are generally of greater significance in driving electricity use in the residential sector, whereas GSP growth is of more importance in the commercial sector. An understanding of these sensitivities gives Energex the flexibility to treat the different sectors independently, rather than taking a more generalised approach that results in some loss of useful information. This methodology results in a more robust forecast. Energex has recently developed electricity delivered forecasts based on network tariff classes to assist with electricity pricing decisions. This approach follows a similar methodology where average DAPR 2017/ /22

69 consumption is modelled and multiplied by the number of customers with that tariff. It involves using multiple regression techniques. The advantage of this approach is that weather, pricing and solar PV information drivers can be modelled separately giving greater insight into electricity delivered values. In addition Energex has also developed an econometric electricity purchases model that is used at a total system level. This forecast is used to review and compare the bottom up electricity delivered forecast after accounting for network losses Electricity Delivered History and Forecast In general, growth in electricity consumption lags demographic changes and economic activity by about 9 to 12 months. During 2014/15, electricity delivered grew by 1.6%, (as shown in Figure 25), the first increase over the past 5 years, but contracted by 0.2% in 2015/16, and is expected to increase by 0.87% in 2016/17. While, growth in consumption (i.e. electricity provided by both Energex and customer owned PV generation) increased by 1.8% and 0.2% in the 2014/15 and 2015/16 years respectively, and is expected to increase by 1.2% in 2016/17 demonstrating the relative robustness of consumption relative to electricity delivered. Looking ahead, electricity delivered is expected to be flat over the 2017/18 to 2019/20 years, as a result of solar PV installations and the continued reduction or a potential closing down of some industrial businesses, meeting with a rebound in population growth (driven by the gain of net overseas immigration) and more international tertiary students attracted by cheaper tuition fees (due to the lower Australian dollar). In the medium to long term however, the downward pressures will weigh on electricity delivered, as the new technologies, especially battery storage (which normally links to PV installation) will provide an alternative source for customers. Over the longer term, electricity delivered growth will also be tempered by the saturation in the penetration of air conditioners and reductions in consumption for low income households due to higher electricity prices, but be partly countered back by the potential increase in electric vehicle (EV) sales DAPR 2017/ /22

70 1996/ / / / / / / / / / / / / / / /27 Annual Growth of Total Electricity Delivered (%) Figure 25 Growth of Total Electricity Delivered 8% 6% Forecast Period 4% 2% 0% -2% -4% The increase in embedded generation of electricity by solar PV has had a twofold effect on electricity consumption. Although solar PV does not decrease consumption directly, it may have an impact on electricity usage as customers became more conscious of their consumption patterns, especially for those PV customers who lost the benefit of the 44 cents feed-in tariff. Conversely, it does directly affect electricity delivered from the network. Customers can reduce their purchases of electricity by using output generated directly in-house. As detailed in section 5.1.2, solar PV output occurs in daylight hours, so the drop in electricity consumption naturally occurs during the middle of the day. This reduces the load factor, and doesn t coincide with the peak demand for domestic customers that occurs in the early evening. In addition, economic growth is a major driver of electricity consumption. As noted earlier, there are a range of views regarding forecasts of Queensland GSP growth. In summary, while Queensland GSP only increased by 1.98% in 2015/16, it is expected to accelerate to 2.4% and 2.9% in the 2016/17 and 2017/18 years respectively based on NIEIR s latest (low case as explained above) forecasts. The forecast GSP figures are a key input into the forecasting process used by Energex for electricity forecasting. All of these factors have been modelled in determining a view on electricity delivered into the future. Based on these changing inputs, Energex anticipates electricity delivered will increase very slowly with an average annual growth rate of around 0.24% over the next 10 year horizon. Continuing increases in electricity prices and improving appliance efficiencies have changed the long term outlook for domestic electricity delivered. The annual average price elasticity for domestic electricity delivered is calculated over the four year period 2011/12 to 2015/16. Furthermore, electricity delivered for water heating has weakened for several reasons, including mild weather conditions, policies to reduce electric storage systems, and increases in energy efficiency measures in the construction of multi-unit DAPR 2017/ /22

71 2010/ / / / / / / / / / / / / / / / / /28 Electricity Delivered by Category (GWh) dwellings. Despite the withdrawal of a Government directive for solar, gas and heat pumps to replace electric hot water heating, the long term decline in controlled electric hot water installations is expected to continue with new developments incorporating gas, heat pumps or solar hot water heating. The contribution of solar PV is included in both the residential and non-residential electricity delivered forecasts. Electricity generated by solar PV but used internally, is estimated, and when combined with electricity delivered from the Energex network is the total electricity consumption. Excess solar PV generation exported to the Energex network is included in the total electricity purchases. The Energex solar PV forecast is continuing to grow but at a slower rate than seen in 2011/12 and 2012/13. Energex forecasts for non-residential customer consumption growth are related to expected changes in GSP and the trend in changing average consumption. Delivered electricity to non-residential customers is predicted to grow at an average of 0.4% p.a. over the next 10 years. Figure 26 provides a graphical representation of this electricity growth. It shows that annual electricity delivered to residential customers will be flat over the 10 year forecasting horizon. Non-residential electricity delivered growth will be relatively stable in the short term. In the long term however, the nonresidential component will continue to increase in line with the long term trend of the Queensland economy and the build-up in the infrastructure investment. Figure 26 Electricity Delivered by Category (GWh pa) 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 Residential Forecast Period Non-Residential Substation and Feeder Maximum Demand Forecasts To ensure security and reliability of supply, capital investment is driven by growth in demand for electricity creating emerging limitations at substations and on feeders. Importantly, no distribution network investment is directly driven by the total Energex peak demand. Hence individual substation DAPR 2017/ /22

72 Number of Zone Substations and feeder maximum demand forecasts are prepared to analyse and address limitations with prudent investment decisions. The forecasts produced post summer 2016/17 have provided a range of demand growth rates. Some substations supplying the outer regions of the major development areas such as south of Ipswich are growing strongly as areas like Ripley Valley are developed. Other growth areas include the northern Gold Coast, the southern Sunshine Coast, the Logan area including Yarrabilba and Flagstone, and the northern Brisbane gateway. Energex uses the forecasts to identify network limitations and then investigates the most cost effective solution which may include increased capacity, load transfers or Demand Management alternatives. The distribution of growth rate for zone substations is shown in Figure 27. Figure 27 Zone Substation Growth Distribution % -8% -6% -4% -2% 0% 2% 4% 6% 8% 10% Annual Compound Growth Rates While growth in demand continues to increase very slowly at a system level, there can be significant growth at a localised substation level. In the 2017/22 period approximately 16 per cent of substations have no average compound growth rate while 71 per cent of zone substations have 0.5 to 3.5 per cent average annual compound growth rate. 8.6 per cent of zone substations have an annual compound growth rate exceeding 3.5 per cent for the period 2017/22. Due to this growth, augmentation will be required to meet the additional demand on the network in these areas. Energex has incorporated demand management initiatives into the summer and winter substation forecasts. The initiatives include broad application of air-conditioning control, pool pump control and hot water control capability. Demand management is also being targeted at substations with capacity limitations in an effort to defer capital expenditure. The approach used is to target commercial and industrial customers with incentives to reduce peak demand through efficiency and power factor DAPR 2017/ /22

73 improvements. The resulting reductions are captured in the Energex Substation Investment Forecasting tool (SIFT) and in the 10 year peak demand forecasts. These forecasts underpin the detailed analysis provided in Appendices D, E and F of the DAPR. The 10 year substation peak demand forecasts are prepared at the end of summer and winter each year (for day and evening peaks), and are produced within a substation forecast modelling tool. To enable appropriate technical evaluation of network limitations, these forecasts are completed for both existing and proposed substations. Output from solar PV is generally coincident with Commercial and Industrial (C&I) peak demand. Although there are limited numbers installed at this time, increasing penetration of solar PV at C&I premises will provide benefits through reduced substation and feeder peak demands. Conversely, the impact of solar PV at residential premises is largely negligible due to the coincident peak demand on substations and 11 kv feeders occurring at around 6.30 pm or after the sun has set Substation Forecasting Methodology Energex employs a bottom up approach to develop the 10 year zone substation peak demand forecasts using validated historical peak demands and expected load growth based on demographic and appliance information in small area grids. Larger block loads are included separately after validation for size and timing by Asset Managers. The zone substation peak demand forecasts are then aggregated up to the 10 year bulk supply point and transmission connection point demand forecasts and take into account diversity of individual zone substation peak demands and network losses. This aggregated forecast is then reconciled with the independent system demand forecast and adjusted as required. The process used to develop the 10 year substation demand forecast is briefly described as follows: Validated uncompensated substation peak demands are determined for summer 2016/17; Minimum and maximum temperature at five BOM weather stations are regressed against substation daily maximum demand to assess the impact of each set of weather data on substation demand (Amberley, Archerfield airport, Coolangatta airport, Brisbane airport and Maroochydore airport). The best fit relationship is used to determine the temperature adjustment; Commercial and industrial substations tend not to be sensitive to temperature and the 50 PoE and 10 PoE adjustments are based solely on demand variation; Previous substation peak demand forecasts are reviewed against temperature adjusted results and causes of forecast error are identified; Starting values for MVA, MW and MVAr are calculated for four periods summer day, summer night, winter day and winter night; Demographic and population analysis is undertaken and customer load profiles are prepared for Energex; Expected impact and growth in solar PV, Battery Storage and plug in Electric Vehicles have been included at the substation level for the first time. Year-on-year peak demand growth rates are determined from the customer load profiles prepared for Energex, historical growth trends and local knowledge from Asset Managers using a panel review (Delphi) process; Size and timing of new block loads are reviewed and validated with Asset Managers before inclusion in the forecast; DAPR 2017/ /22

74 Size and timing of load transfers are also reviewed with Asset Managers before inclusion in the forecast; Timing and scope of proposed transmission projects are reviewed with development planners before inclusion in the forecast; The growth rates, block loads, transfers and transmission projects are applied to the starting values to determine the forecast demand for each of the 10 years starting from a coincident demand basis; Zone substation forecast peak demands are aggregated up to transmission connection point demands through the bulk supply substations using appropriate coincidence factors and losses; and Reconciliation of the total aggregated demand with the independently produced system demand forecast ensures consistency for the 10 year forecast period. Substation peak demand forecasts are reviewed each season and compared with previous forecasts. The relative error between recorded demand and the forecast is investigated for the most recent season. Energex has developed a tool to undertake this comparison, and this is applied to every zone substation. The substation forecast modelling tool can differentiate between approved and proposed projects in the process. However, to comply with the NER, the forecasts provided in the DAPR include approved projects only Transmission Feeder Forecasting Methodology Energex uses a simulation tool to model the 110 kv and 132 kv transmission network. The software was selected to align with tools used by Powerlink and the Australian Energy Market Operator (AEMO). Powerlink provides a base model to Energex on an annual basis. This base model is then refined to incorporate Energex s future project components using an application program interface, and is uploaded with peak forecast loads at each bulk supply and connection point zone substation from Energex s corporate database for substation load forecast (SIFT). Twenty models are created using this simulation tool, with each model representing the forecast for a particular season in a particular year. The models have five years of summer day 50 PoE and 10 PoE data and five years of winter night 50 PoE and 10 PoE data Sub-transmission Feeder Forecasting Methodology Energex uses a simulation tool to model the 33 kv sub-transmission network. The simulation tool has built-in support for network development which provides a variable simulation timeline that allows the modelling of future load and projects into a single model. Simulation models are created using the existing network data. Future projects are then modelled with timings and proposed network configurations based on future project proposals being included. Future projects are automatically activated depending on the network analysis dates selected. The forecast peak loads at each substation for all years within the planning period are uploaded into the model from SIFT. Eight models are produced, each containing forecast load for the different seasons. These include summer day, summer night, winter day and winter night, and with 10 PoE or 50 PoE peak load. This enables Energex to identify the worst case risk period for each season DAPR 2017/ /22

75 5.3.4 Distribution Feeder Forecasting Methodology Forecasting of 11 kv feeder loads is performed on a feeder by feeder basis. The forecast begins by establishing a feeder load starting point by undertaking bi-annual 50 PoE temperature corrected load assessments (post summer and post winter). This involves the analysis of daily peak loads for day and night to identify the load expected at a 50 PoE temperature after first identifying and removing any temporary (abnormal) loads and transfers. Using a statistical distribution, the 10 PoE load value is extrapolated by using 80% of the temperature sensitivity from the 50 PoE load assessment. The summer assessment covers the period from 1 December to early March, and the winter assessment from 1 June to 31 August. Growth rates are applied and specific known block loads are added and events associated with approved projects are also incorporated (such as load transfers and increased ratings) to develop the feeder forecast. In addition, the 10 PoE load forecast is used for determining voltage limitations. 5.4 System Maximum Demand Forecast Energex reviews and updates its 10 year 50 PoE and 10 PoE system summer peak demand forecasts after each summer season and each new forecast is used to identify emerging network limitations in the sub-transmission and distribution networks. For consistency, the system level peak demand forecast is reconciled with the bottom up substation peak demand forecast after allowances for network losses and diversity of peak loads. In recent years, there has been considerable volatility in Queensland economic conditions, weather patterns and customer behaviour which have affected total system peak demand. The influence of Queensland s moderate economic growth has had an impact on peak demand growth in SEQ. At the same time, weather patterns in SEQ have moved from extreme drought in 2009 to flooding and heavy rain to extended hot conditions over the past six summer periods. In the recent summer hotter conditions have prevailed resulting in a general increases in recorded peak demand. To complete the scenario, customer reaction to recent electricity price increases has started to wane resulting in customer load at the 50 PoE temperature conditions, above long term average trends. The amount of solar PV that has been connected to the network over recent years has continued to grow although at a much slower rate. Customer behaviour drivers are now incorporated into models used for system demand forecasting. The forecasts are developed using Australian Bureau of Statistics (ABS) data, Queensland Government data, the Australian Energy Market Operator (AEMO) data, the National Institute of Economic and Industry Research (NIEIR), an independently produced Queensland air-conditioning forecast, solar PV connection data and historical peak demand data System Demand Forecast Methodology The methodology used to develop the system demand forecast as recommended by consultants ACIL Tasman is as follows: Develop a multiple regression equation for the relationship between demand and GSP, weighted maximum temperature, weighted minimum temperature, total electricity price, Structural break, Three continuous hot days, Weekends, Fridays and Christmas period and December to February temperature data that excludes days with average temperature at Amberley < 23.5 degrees. Three weather stations were incorporated into the model through a DAPR 2017/ /22

76 weighting system to try to capture the influence of the sea breeze on peak demand. Statistical testing is applied to the model before its application to ensure that there is minimum bias in the model; A Monte Carlo process is then used to simulate a distribution of summer maximum demands using the latest 30 years of summer temperatures and an independent 10 year GSP forecast and an independent air-conditioning load forecast; Use the 30 summer peak maximum demands to produce a probability distribution of maximum demands to identify the 50 PoE and 10 PoE maximum demands; An error factor is applied to the simulated demands based on a random distribution of the multiple regression standard error. This process attempts to define the peak demand rather than the regression average demand; and Modify the calculated system peak demand forecasts by the reduction achieved through the application of demand management initiatives. An adjustment is also made in the forecast for solar PV, battery storage and the expected impact of electric vehicles. Comparison of the final forecast with NIEIR and AEMO / Powerlink demand forecasts is undertaken to confirm that the forecast is reasonable. Several alternative peak demand models were developed including a yearly peak demand model and a probabilistic model based on temperature at Amberley. These models are used for comparison with the independent demand forecast prepared by NIEIR each year. The latest system demand model incorporates economic, temperature and customer behavioural parameters in a multiple regression as follows: Demand MW = function of (Weekend, Xmas, Friday, weighted maximum, weighted minimum, total price, Qld GSP, Structural Break, three continuous hot days and a constant), In particular, the total price component incorporated into the latest model aims to capture the response of customers to the increasing price of electricity. The impact of price is based on the medium scenarios for the Queensland residential price index forecast prepared by NIEIR System Maximum Demand Forecasts. In applying the above methodology, Energex derives a system 10 year 50 PoE and 10 PoE maximum demand forecast. Energex also contracted NIEIR to produce an independent 10 year maximum demand forecast using NIEIR models in April The results of the two forecasts are compared in Figure 28. Demand management load reductions are included in both forecasts DAPR 2017/ /22

77 2001/ / / / / / / / / / / / / / / / / / / / / / / / / /27 Demand MW Figure 28 Energex Peak Demand Forecast Temperature Adjusted Peak Demand MW Apr 2017 NIEIR 10POE Base Case POE Demand Base Case Apr 2017 NIEIR 50POE Base Case POE Demand Base Case 6,000 5,500 5,000 4,500 4,000 3,500 3,000 2,500 2,000 Figure 29 shows the variation that has occurred over the past five years in the summer system peak demand forecast. In each of the past five years, the forecast growth has been progressively reduced. Energex summer peak demand has continued to increase over the last four years as a result of improving economic conditions, continued growth in population and significantly hotter summer conditions. Solar PV has also had a small but increasing influence in summer day peak system demand. Importantly, in comparison with prior years, decline in growth of peak demand has resulted in network limitations being deferred and this is reflected in the analysis contained in Appendices D, E and F. It has also resulted in reduced capital expenditure DAPR 2017/ /22

78 2001/ / / / / / / / / / / / / / / / / / / / / / / / / /27 Peak Demand MW Figure 29 Previous Demand Forecast Comparison 8,000 Recorded Native Demand MW 2008 Forecast 2009 Forecast 2010 Forecast 2011 Forecast 2012 Forecast 50POE Temperature Adjusted Peak Demand MW POE Demand Base Case NIEIR 50POE Apr Post Summer Forecast 50POE Base Case 50POE Base Case POE Base Case POE Base Case ,000 6,000 5,000 4,000 3,000 2,000 Year The weekday 2016/17 system peak demand was 4,814 MW, whereas the previous summer peak demand was 4,614 MW. The temperature corrected peak demand using the ACIL Tasman methodology for 2016/17 was 4,840 MW, an increase compared with the 2015/16 temperature corrected summer demand using three weather station temperatures. It is important to note that the potential for the system demand to meet or exceed the forecast demands is dependent on a range of key drivers including the summer temperatures and specifically, the behaviour of customers. For this reason, several hot summer days are always useful in allowing forecasting models to be recalibrated, and the magnitude of latent temperature sensitive loads to be calculated. The summer of 2016/17 had milder periods in December but extended hot periods in January and February. However, analysis also indicates that the growth in underlying load is relatively slow. This situation is hard to appreciate given that commercial building developments and customer numbers have continued to grow, albeit at a much slower rate than long term historic trends. Industrial load is continuing to slowly decline with gradual loss in the SEQ industrial sector. Table 2 summarises the actual and corrected (50% PoE) demands based on Amberley temperatures and associated maximum demand growths over the past five years. Each year the actual maximum demand recorded is corrected to a normalised or 50% PoE value by adjusting the demand up or down depending on the actual temperature recorded versus the standard temperature and economic conditions. The corrected demand for each of the last four summers has been derived through progressively improved ACIL Tasman models. Therefore, comparisons between the 50% PoE loads for these and previous years should be evaluated with care DAPR 2017/ /22

79 Table 2 Actual Maximum Demand Growth Demand 2012 / / / / / 17 Summer Actual (MW) 1 4,475 4,373 4,614 4,633 4,814 Growth (%) 0.25% -2.28% 5.51% 0.41% 3.91% Summer 50% PoE (MW) 4,590 4,372 4,506 4,615 4,840 Growth (%) -5.96% -4.75% 3.06% 2.42% 4.88% Winter Actual (MW) 3,814 3,568 3,535 3,893 3,657 Growth (%) -4.84% -6.45% -0.92% 10.13% -6.06% Winter 50% PoE (MW) 4,053 3,701 3,667 3,638 3,689 Growth (%) -1.43% -8.68% -0.92% -0.79% 1.4% 1 The Summer Actual Demand has been adjusted to take account of embedded generation operating at the time of System Peak Demand. Furthermore, Table 3 lists the maximum demand forecasts over the next five years based on the ACIL Tasman model using three weather stations weighted data and the 2016/17 summer results. This table is based on weekday maximum demands DAPR 2017/ /22

80 Table 3 Maximum Demand Forecast (MW) Forecast 1, / / / / / 22 Summer (50% PoE) 4,900 4,929 4,965 5,010 5,032 Growth (%) 1.24% 0.60% 0.73% 0.91% 0.44% Summer (10% PoE) 5,335 5,363 5,406 5,453 5,476 Growth (%) 0.40% 0.52% 0.76% 0.87% 0.42% Winter (50% PoE) 3,730 3,782 3,795 3,792 3,840 Growth (%) 1.11% 1.39% 0.34% -0.08% 1.27% Winter (10% PoE) 3,891 3,948 3,977 3,986 4,044 Growth (%) 1.35% 1.46% 0.73% 0.23% 1.46% 1 2 The five year demand forecast was developed using three weather station weighted data as recommended by ACIL Tasman and includes the impact of summer 2016/17. The demand forecasts include the impact of the forecast economic growth as assessed in April The forecast of solar PV used in this assessment for the future summer peak demand is adjusted outside the demand model and is shown below in Table 4. Solar PV will continue to grow slowly with Retailers providing options for customers to either bundle solar PV with battery storage or to purchase individual options. Table 4 Solar PV Contribution to Summer System Peak Demand Solar PV Capacity impact on System Peak Demand (MW) In preparing this forecast Energex has also included a small contribution from electric vehicle load. While it is anticipated that the take up of this technology will be slow, it has the potential to increase significantly if costs decline or Government incentives are introduced as occurred with solar PV. EV charging is expected to generally occur from the early evening onwards and will extend into the middle of the night (off peak). It is expected that the impact of electric vehicle charging on the system peak (afternoon period) will be negligible and is therefore excluded for the System Peak Demand. It has been included in residential zone substations where the effect would be more prominent. The EV impact on system demand forecast prepared by Energex is shown in Table DAPR 2017/ /22

81 Table 5 Electric Vehicle Contribution to Summer System Peak Demand Electric Vehicle Load impact on System Peak Demand (MW) Note This assessment assumes that home vehicle charging is on controlled tariffs. Electric Vehicle charging period is assumed to occur from 6pm to the early hours of the morning and will therefore not contribute to the afternoon peak demand. Energex has also developed a model for the adoption of battery storage with the impact on peak demand being driven by large solar PV customers with little or no feed in tariffs (FIT). There are an increasing number of solar PV customers with systems that provide more electricity than they can use internally during the day but are not receiving the 44 cents per kwh FIT. These customers are likely to be very interested in battery storage and are seen to be the early adopters. Table 6 lists the projected impact of battery storage systems on system peak demand. Table 6 Battery Storage Systems Impact on Summer System Peak Demand Battery Storage Systems Load impact on System Peak Demand (MW) Model is based on the assumption that battery storage will primarily be charged by solar PV and discharged over the late afternoon and early evening period between 4pm and 8pm and as result has a relatively small impact on the system peak demand DAPR 2017/ /22

82 Chapter 6 Planning Framework Background Joint Planning Distribution Network Planning Assessing System Limitations Project Approval and Implementation DAPR 2017/ /22

83 6 Planning Framework 6.1 Background The Energex distribution network services approximately 1.4 million customers. These customers connect to the network at voltage levels ranging from 240 V to 132 kv. Energex has a structured, coordinated network development planning framework to ensure solutions to address network limitations are optimal to meet both current and future requirements. To ensure that the objectives of network development planning are achieved, it is essential that it is undertaken in a structured, transparent and rigorous manner and makes best use of all relevant information available. The annual planning review systematically assesses the capability of the network to meet current and forecast customer demand requirements. There are several definitions essential to the understanding of Energex s planning philosophy. Reliability of supply is the probability of a system adequately performing under operating conditions. A reliable network that meets obligations is an important objective, and is dependent on two measures; adequacy and security. Adequacy is the capacity of the network and its components to supply the electricity demand within acceptable quality of supply limits. It includes requirements that network elements operate within their ratings whilst maintaining voltage within statutory limits. Security is the ability of the network to cope with faults on major plant and equipment without the uncontrolled loss of load. A secure network often factors in redundancy of major plant and equipment to tolerate the loss of single elements of the system. Since 2014, Energex has adopted a more modern planning standard which takes into account the value of customer reliability and an obligated customer safety net to alleviate the adverse outcomes of low probability, high consequence events. Energex plans network investment to meet the Customer Outcome Standard (COS) detailed in Appendix C. The security standard takes into account the following key factors: Feeders and substations are assigned a category according to criteria or the area (CBD, Urban, Rural); and the appropriate safety net is assigned to associated network elements; Plant and power line ratings depend upon their ability to discharge heat and are therefore appreciably affected by the weather, including ambient temperature and in the case of overhead lines, wind speed; A range of actions to defer or avoid investments such as non-network solutions, automated, remote and manual load transfer schemes and the deployment of a mobile substation and/or mobile generation increase utilisation of network assets; Value of customer reliability to optimise investment timing; and Specific security requirements of large customer connections that are stipulated under the relevant connection agreements. The application of the Customer Outcome Standard ensures that under system normal conditions the normal cyclic capacity of any network component must be greater than the forecast load (10 PoE). The capacity of the network is also assessed based on the failure of a single network component (transformers or power lines) and 50 PoE forecast load. This enables the load at risk under system DAPR 2017/ /22

84 normal (LARn) and the load at risk for contingency conditions (LARc) to be assessed as key inputs to investment planning against customer safety net targets. Where these assessments indicate that the network is not able to meet the required safety net, the resulting network limitation must be addressed to ensure customer service obligations are achieved. The Energex distribution network is also required to maintain voltage levels within legislative requirements and ensure safe operation under fault conditions. These requirements are addressed during the annual planning review. 6.2 Joint Planning Joint Planning Methodology The joint planning process ensures that different network owners operating contiguous networks work cooperatively to facilitate the identification, review and efficient resolution of options to address emerging network limitations from a whole of distribution and transmission network perspective. In the context of joint planning, geographical boundaries between transmission and distribution networks are not relevant. The National Electricity Objective (NEO) is to promote efficient investment in, and operation and use of, electricity services for the long term interests of customers. Joint planning ensures that the most efficient market outcomes for customers are implemented. This typically involves a combination of Transmission Network Service Provider (TNSP) and Distribution Network Service Provider (DNSP) augmentations. Energex conducts joint planning with distribution network service providers and transmission network service providers. Joint planning involves Essential Energy, Powerlink, TransGrid and Terranora Link in the vicinity of the NSW & Queensland border. Similarly, joint planning involves Powerlink in SEQ and Ergon near Toowoomba and north of Gympie. The early identification, consultation and monitoring of emerging network limitations and prospective network developments is specifically aimed at providing proponents of alternative solutions adequate time to prepare proposals. Once an emerging network limitation is identified, plausible options are assessed to address the emerging limit. However, some options are subsequently eliminated during the process following more detailed economic, environmental and technical analysis. The reasons why options have been eliminated are captured to satisfy market participants that the process has been undertaken without bias. In assessing options, any subsequent or future limitations are identified. This determines the impact of implementing various options, as well as the interaction between options and the sequencing of subsequent future stages. This means that future limits, and the cost to address them, are also taken into account in the planning analysis. Where the estimated cost of the options is similar, more information may be sought on scope and cost to inform the analysis. In addition, other relevant considerations are taken into account including the strategic and long-term development of the power system and the impact and timing on other developments and projects DAPR 2017/ /22

85 It is also prudent to take into account any plant and equipment that may be identified for retirement, replacement or refurbishment due to condition or age. This allows augmentation, retirement, replacement and refurbishment needs to be optimised for efficient expenditure outcomes Role of Energex in Joint Planning Joint planning often begins many years in advance of any investment decision to address a specific emerging network limitation. Timing is reviewed annually, with detailed planning and approval completed based on the forecasted need and the lead time to complete the project. In this process, there is a steady increase in the intensity of joint planning activities, which typically would lead to a regulatory investment test consultation (either RIT-T or RIT-D). Among other things, the scope and estimated cost of options (including anticipated and modelled projects) is provided in published regulatory investment test documents consistent with the National Electricity Rules. Through this process Energex is tasked with: Ensuring that its network is operated with sufficient capability, and augmented if necessary, to provide network services to customers; Conducting annual planning reviews with TNSPs and DNSPs whose networks are connected to Energex s network; Developing recommendations to address emerging network limitations through joint planning with DNSPs, TNSPs and consultation with Registered Participants and interested parties as defined by the National Electricity Rules. Net present value analysis is conducted to ensure cost-effective, prudent solutions are developed. Solutions may include network upgrades or non-network options, such as local generation and demand side management initiatives; Undertaking the role of the proponent for jointly planned distribution augmentations in SEQ; Advising Registered Participants and interested parties of emerging network limitations within the time required for action; and Ensuring that its network complies with technical and reliability standards contained in the NER and jurisdictional instruments Emerging Joint Planning Limitations For joint planning purposes, the primary focus is to ensure that network capacities are not exceeded. These limits relate to: Thermal plant and line ratings under normal and contingency conditions; Plant fault ratings during network faults; Network voltage to remain within acceptable operating thresholds; Replacement of ageing or unreliable assets; and Network stability to ensure consistency with relevant standards. Where forecasted power flows could exceed network capacity, Energex is required to notify market participants of these forecast emerging network limitations through the DAPR. If augmentation is necessary, joint planning investigations are carried out with DNSPs or TNSPs in accordance with Clause 5.14 of the National Electricity Rules, to identify the most cost effective network solution DAPR 2017/ /22

86 6.2.4 Network Connection Proposals The availability of easements and future substation sites are considered in the context of network developments under consideration. This is initially undertaken from a strategic planning perspective, consistent with good industry practice. This permits Energex to coordinate works in identified areas where forecasted plans by other relevant stakeholders are available. Stakeholders include the Queensland Government, Local Government and community consultations / engagement. New connections can result from joint planning with the relevant DNSP or TNSP, or be initiated by customers. Planning of new or augmented connections involves consultation between Energex and the connecting party, determination of technical requirements and completion of connection agreements that include operating protocols Joint Planning Activities and Interactions Effective joint planning is reliant on regular communication between network planning engineers employed by the relevant DNSPs, TNSPs, proponents, network service providers and interested parties, as summarised in Table 7. Table 7 Joint Planning Activities and Interactions Frequency Joint Planning Activity Sharing and validating information covering specific issues Day-to- Day Weekly Monthly Yearly Regulated Planning Cycle Sharing updates to network data and models Identifying emerging limitations Developing potential credible solutions Estimating respective network cost estimates Developing business cases Preparing relevant regulatory documents Sharing information for joint planning analysis Sharing information for respective budgets Sharing updates to demand forecasts Joint planning workshops DAPR 2017/ /22

87 Joint Planning Activity Day-to- Day Frequency Weekly Monthly Yearly Regulated Planning Cycle Sharing information for regulatory information notices Sharing planning and fault level reports Sharing annual planning reports Sharing information for AER revenue models Sharing information for the purposes of respective revenue submissions Joint Planning and Joint Implementation Register A register has been set up to capture all information relating to limitation identification, planning, consultation and subsequent project implementation between Energex and external parties. This ensures joint activities are tracked throughout the lifetime of a project, from the time a limitation is identified to final commissioning of the chosen solution. The register is shared with the respective TNSP or DNSP and is updated regularly. 6.3 Joint Planning Results Towards approval and implementation, there is often the potential for circumstances to change. Some of these changes may relate to: The emergence of new loads or limits which may impact upon the feasibility of existing options; A change in the load forecast as a result of economic, financial and other conditions; The identification of new or additional access or site constraints; and A more detailed consideration of the strategic direction of the joint planning entities and relevant State Government and/or Local Government requirements. A material change in circumstances will necessarily require that options be reassessed to ensure they remain feasible and appropriate. For example, one option may be ruled out on the basis that the easement acquisition is no longer considered plausible. As the planning analysis nears completion, the most appropriate option from a technical and high-level economic perspective emerges. A detailed estimate of this option is prepared, as well as more detailed estimates of the other potential credible options, to verify that it remains the most prudent option in light of economic and technical considerations. Having undertaken the iterative process described above of developing and considering options in light of sequencing, network impacts, coordination of works, costs and new information, a shortlist of DAPR 2017/ /22

88 options emerges. Further analysis is also undertaken to finalise the sequencing of options and subsequent future stages. The NERs require that consultation with customers and interested stakeholders be undertaken to demonstrate that, for reliability augmentations, the recommended option minimises the present value of costs in a majority of credible scenarios in line with the AER s Regulatory Investment Test. The outcomes of the joint planning process form the basis for public consultation under the AER s RIT-D and RIT-T. Submissions to the consultation process are assessed and incorporated into the planning process outcomes. Where material issues arise during the consultation process, further joint planning discussions and analysis may be undertaken to ensure that the final report has appropriately actioned the outcomes of the consultation process. All regulatory investment test documents are public, agreed and branded by all parties to the joint planning process Joint Planning with TNSP In the past 12 months Energex has actively engaged with Powerlink on the following joint planning studies. These projects have network drivers that have a notional target date in the forward planning period (2017/18 to 2021/22), as summarised in Table 8. Additional joint planning activities have occurred in the past 12 months for network drivers on the Energex, Ergon Energy and Powerlink networks that notionally occur beyond the forward planning period. Table 8 Joint Planning Activities Covering 2017/18 to 2021/22 Energex Works Estimated Cost ($ M) Project Description Indicative Timing 2016 DAPR Reported Timing Comparison 2016 DAPR Tennyson Upgrade secondary systems (Powerlink Project) Mudgeeraba 110 kv Replace primary plant and secondary systems (Powerlink Project) Ashgrove West 110 kv Replace primary plant and secondary systems (Powerlink Project) Sumner Upgrade 110/11/11 kv transformer protection (Energex Project) Molendinar Upgrade 110/11/11 kv transformer protection (Energex Project) Bundamba Upgrade 110/11/11 kv transformer protection (Energex Project) Mar 2018 Dec Deferred Oct 2017 Feb Advanced Oct 2019 Oct 2019 Jun 2019 New Project Jun 2019 New Project Jun 2019 New Project 4 6 Richlands Replace 33 kv circuit breakers (Energex Project) Dec 2018 New Project DAPR 2017/ /22

89 Energex Works Estimated Cost ($ M) Project Description Indicative Timing 2016 DAPR Reported Timing Comparison 2016 DAPR 1 2 Abermain Replace secondary systems (Powerlink Project) 1 2 Redbank Plains 110 kv Replace primary plant (Powerlink Project) 1 2 Retirement of Mudgeeraba 275/110 kv transformer (Powerlink Project) 1 2 Replacement of Belmont 275 kv secondary systems (Powerlink Project) Jun 2020 New Project Dec 2021 New Project Dec 2019 New Project Dec 2020 New Project 1 2 Line Refit Works on 110 kv Transmission Lines between: I. South Pine to Upper Kedron II. III. Sumner to West Darra Rocklea to Sumner (Powerlink Project) 1 2 Line Refit Works on 275 kv Transmission Lines between South Pine to Karana Tee (Powerlink Project) Dec 2021 New Project Dec 2022 New Project 1 Deferred by Powerlink Joint Planning with other DNSP There were no specific joint planning network investigations necessary between Energex and other DNSPs during 2016/17. Energex continues to work closely with Ergon through joint business practices. Energex continues to monitor emerging network limitations beyond the forward planning period on the southern Gold Coast and broader region, associated with Essential Energy, TransGrid, Powerlink and Terranora Link Further Information on Joint Planning Further information on Energex s joint planning and joint network investment can be obtained by submitting to the following address: DAPR_Enquiries@energex.com.au DAPR 2017/ /22

90 6.4 Distribution Network Planning Assessing System Limitations Overview of Methodology to Assess Limitations The methodology shown in Figure 30 is used in the preparation of the Distribution Annual Planning Report to identify and address network limitations, joint planning projects and RIT-D projects. Figure 30 Distribution Annual Planning Report Process INPUT PROCESS OPERATOR OUTPUT Demand Forecast Equipment Ratings Load transfer capacity Customer requirements TNSP network model Asset Condition Network capacity analysis substations and feeders DAPR substations & feeder forecast and capacity section Identify emerging network limitations DAPR limitations section Identify potential credible network options Quantify potential non-network options requirements Contact TNSP / other DNSP to initiate joint planning (where applicable) DAPR joint planning section DAPR potential options section Include project into program of work Commence detailed planning analysis Invite non-network providers to provide alternatives Undertake RIT-D and/ or joint planning (where applicable) RIT-D consultations Select preferred option Project approval report DAPR replacement project summary section DAPR RIT-D project summary section DAPR 2017/ /22

91 Following the assessment of emerging network limitations, network and non-network options are considered for addressing the prevailing network limitations. These recommendations then become candidate projects for inclusion in the Energex Program of Work (PoW), and are allocated with a risk score based on the Energex network risk based assessment framework for prioritisation purposes. The PoW also undergoes ongoing assessment to determine if targeted area demand management activities can defer or remove the need for particular projects or groups of projects. Remaining projects form the organisation s PoW for the next five years. Detailed planning is also done for each PoW project to complete a RIT-D consultation if required, and obtain project approvals for acquisitions, construction and implementation Key Assumptions Driving Investment Demand Forecast Accurate demand forecasting is essential to the planning and development of the electricity supply network. Energex has adopted a detailed and mathematically rigorous approach to forecasting of electricity delivered, demand, and customer numbers. These methods are described in detail in chapter 5. Energex also undertakes regular audits and reviews by external forecasting specialists on the forecasting models. Demand forecasts are not only undertaken at the system level, but are also calculated for all substations and feeders for the forward planning period. These forecasts are used to identify emerging network limitations, and identify network risks, that need to be addressed by either supply side or non-network based solutions. The forecasts are then used as an input to determine the timing and scope of capital expenditure, or the timing required for demand reduction strategies to be established, or risk management plans to be put in place. Plant Thermal Ratings Power transformers, switchgear and conductors are designed to operate within its thermal ratings. Plant thermal ratings are affected by the load cycle and ambient conditions such as air temperature, wind velocity and solar radiation. In general, Energex s plant thermal ratings are determined based on the following assumptions: Power transformers are rated in accordance with AS 2374; HV plant is rated based on maximum daily ambient temperatures; Overhead conductors are rated based on conditions listed in Table 9 and Table 10; and Underground cables are rated based on the conditions shown in Table DAPR 2017/ /22

92 Table 9 Standard Ambient Air Temperatures for Plant Ratings Time Period Standard Ambient Air Temperatures Summer Noon 35 C Summer Evening 25 C Winter Noon 20 C Winter Evening 15 C Table 10 Standard Atmospheric Conditions for Conductor Ratings Parameter Wind velocity Normal Wind velocity 2HR Emergency ( 33 kv only ) Wind yaw angle Value 1.0 m/sec 2.0 m/sec 90 to line Wind turbulence 0.1% Conductor emissivity 0.85 Conductor absorptivity 0.85 Albedo (reflectance from ground etc.) 0.2 Direct solar radiation intensity (day) 1000 W/m 2 Diffuse solar radiation intensity (day) 100 W/m 2 Solar altitude (day) 86 Degrees Atmospheric clearness number (day) 1.0 Table 11 Standard Environmental Conditions for Cable Ratings Summer Winter Ground Temperature: at cable depth 29 C 20 C Air Temperature: 40 C 25 C Soil Thermal Resistivity: 1.2 C.m/W Note: The parameters above are not applied universally. Specific site conditions may also apply DAPR 2017/ /22

93 Load Transfer Capability Energex s Customer Outcome Standard integrates the full use of load transfers between subtransmission systems and zone substations. These use the sub-transmission or distribution feeder networks to reduce the impact of an outage in the event of a major plant failure. Load transfer capabilities for each substation are calculated annually using load flow studies, taking into account the thermal ratings and voltage stability of the network. The load transfer capability at a substation level is calculated based on 75% of the sum of all available transfers on each of the supplied distribution feeder. The 75% factor is applied to account for diversity and to provide a margin of error for unforeseen circumstances such as protection coverage. The transfer amount applies throughout the forward planning period. In addition, more detailed load transfer studies are incorporated during individual project planning phases. Asset Age and Condition Energex has an extensive Asset Lifecycle Management program which is discussed in detail in section 9. An important output of this program is the identification of equipment which is nearing end of life due to condition and/or age. In the case of major plant items, such as power transformers, high voltage circuit breakers etc. the end of life information is considered within the planning process as a network limitation, just like any other (capacity) network limitation. Hence, the options to either refurbish, replace, or retire the plant item is considered in the context of network safety, security, and reliability standards Bulk and Zone Substation Analysis Methodology Assumptions Energex uses a software tool to assess emerging capacity limitations for all bulk supply and zone substations, taking into account information such as non-network, manual, remote and automated load transfers, circuit breaker/secondary system ratings, generator support and reference to the current security standards. All reviews are performed annually with comprehensive results included in Appendix E of the DAPR. All assessments are evaluated based on the current network security standards which are detailed in Appendix C. All calculations are based on the latest load forecasts which align with the forecast information provided in section Transmission Feeder Analysis Methodology Assumptions Based on the forecasting methodology described in section 5.3.2, using the simulation tool, load flow studies are performed to identify system limitations on the transmission network under system normal or contingency conditions. Contingency analysis is performed to identify all overloaded feeders for all credible contingency events. Contingency transfers are not included in this automated model, but are considered in subsequent analysis. The load flow results are then exported to Energex s analysis tools and reporting systems. The Energex 110 kv Feeder Analysis Tool is used to review and analyse load flow results. The tool uses additional data which is not contained in the models itself. This includes information such as nonnetwork alternatives, load transfer capacities (Manual, Remote and Automatic), circuit breaker/secondary system ratings, generator support and reference to the current security standards DAPR 2017/ /22

94 The tool is also used in conjunction with other supporting tools to assist with the upload process and provides another level of error checking capability. The outcome of the analysis would trigger further investigations and identification of potential solutions to address the limitations Sub-transmission Feeder Analysis Methodology Assumptions Based on the forecasting methodology described in section 5.3.3, using the simulation tool, load flow studies are performed to identify limitations on the sub-transmission feeder network under system normal or contingency conditions. Contingency analysis is performed to identify all overloaded feeders for all credible contingency events. Contingency transfers are not included in this automated model, but are considered in subsequent analysis. The load flow results are then exported to Energex s analysis tools and reporting systems. The Energex 33 kv Feeder Analysis Tool is used to review and analyse the load flow results. The tool uses additional data which is not contained in the models. This includes information such as nonnetwork alternatives, load transfer capacities (Manual, Remote and Automatic), circuit breaker/secondary system ratings, generator support and reference to the current security standards. The outcome of the analysis would trigger further investigations and identification of potential solutions to address the limitations Distribution Feeder Analysis Methodology Assumptions 11 kv feeder analysis is performed to assess feeder loads relative to NCC to establish feeder utilisation. The Target Maximum Utilisation (TMU) of each feeder takes into account the ability of generally transferring loads from four feeders into three feeders with some use of mobile generation to restore all loads in the event of a fault on the 11 kv network. This is to allow for operational flexibility and load transfers to restore load during a contingency event. The TMU will vary for feeders that are a dedicated customer supply or CBD meshed or radial networks. Analysis is conducted on feeder tie points to determine the feeder capacity to support loads of adjacent feeders during contingency situations. This involves determining the maximum transfer capacity using a block load at an open tie point with the following constraint categories: The voltage drop at the tie point being analysed is no greater than 7%; The voltage drop anywhere on the 11 kv feeder is less than 8%; and The thermal limit of the conductors is not exceeded. The contingencies can be categorised into two broad areas: Ties to support the loss of an adjacent feeder (intra and inter substation transfers); and Ties to support sub transmission or substation capacity (inter substation transfers only). Refer to sections 6.4.2, 6.4.3, 6.4.4, and for the application of manual load transfers for these asset classes. Analysis for the first category is incorporated in the Target Maximum Utilisation (TMU) of each feeder. This takes into account the ability of transferring loads from adjacent feeders. Analysis for the second category identifies limits transferring between substations on feeders, consistent with the COS DAPR 2017/ /22

95 6.4.7 Fault Level Analysis Methodology Assumptions Energex performs fault level analysis for switchgear at all 132 kv, 110 kv, 33 kv and 11 kv buses as well as 33 kv and 11 kv feeders. Both 3-phase and 1-phase to ground faults are simulated in the studies and the worst case is identified in accordance with AS 3851, (calculation of short-circuit currents in three-phase systems). The source impedances used in the model are provided by Powerlink. The Energex network model used is based on a system normal configuration. This means all normally open feeders and transformers remain on standby. Fault level contributions from generators that are connected directly to the Energex network are modelled. Known generators that run during peak times or run continuously are included in the model. Standby / backup generators are generally excluded from the calculations. All short circuit simulation results are stored in a database which is then validated and analysed. For meshed networks, additional analysis is carried out to identify the fault current contribution of individual circuits hence identifying the current which a breaker is subjected to under a fault condition. Equipment having a rated short circuit withstand below the observed fault level are then identified. For 33 kv and 11 kv feeders, the analysis first identifies those feeders with fault current exceeding any conductor s one second current carrying capacity. Additional analysis is then carried out on these feeders using protection setting data to determine the actual fault clearing time. Conductors having a fault current carrying capacity below the observed fault level are then identified. Fault level studies are carried out based on the following assumptions: Major network connected generators are assumed to be in operation; All transformers are fixed at nominal tap; and All loads and capacitors are switched out of service. For the 11 kv feeder fault analysis, the additional assumptions are as follows: The load flow analysis assumes only one source at the substation. Standby generation and solar PV fault level contributions are ignored (due to the characteristics of solar PV inverters); Individual fault levels are calculated for feeders with significant co-generation; and Fault levels are only calculated at nodes within the model with results showing individual line segments contribution to the fault. The fault levels are calculated in accordance with the Australian Standard AS 3851, except for a small variation in that a voltage factor (c) of 1.1 is used for all voltage levels. With the proliferation of embedded generation and solar PV installations on the 11 kv and LV networks, investigations are continuing to identify software packages that will be able to model the fault level contributions to the network from these devices. 6.5 Project Approval and Implementation Detailed Planning In order to address the forecast network limitations and ensure ongoing safe and reliable operation of the network, network augmentation and replacement projects are identified in the network development plan. With a typical outlook of 10 years, this information informs regulatory processes DAPR 2017/ /22

96 through Joint Planning, the DAPR, the revenue submission and regulatory information notices. This information also informs financial forecasting, easement and future substation acquisition activities. Based on the network requirement dates, and/or the target completion dates, each capital project is brought into the PoW and then investigated in detail for the preparation of comprehensive business cases, regulatory documents and project approval reports in accordance with the NER and Energex standard practices, procedures and policies. This process ensures the current and future adequacy of the Energex transmission, sub-transmission and distribution networks. The information informs regulatory processes through the Regulatory Investment Test for Distribution (RIT-D), joint planning and demand side engagement activities. The planning process involves the following major steps in a typical routine planning cycle: Validate load forecasts; Evaluate the capability of the existing system; Identify network risks/limitations in the system; Formulate network options to address these risks/limitations and identify any feasible nonnetwork solutions from prospective proponents; Compare options on the basis of technical and economic considerations; Select preferred development option; Undertake public consultation for the projects, and carry out detailed evaluation upon receipt of any alternative solutions from the registered participants/ proponents; and Initiate action to implement the preferred scheme through formal project approvals. Project planning and approvals are currently carried out in accordance with the RIT-D that came into effect from 1 January Currently, RIT-D is only applicable for the projects having credible options with more than $5 million augmentation component. However, the AEMC draft rule change proposes extending the application of RIT-D for the replacements projects as well effective from 01 July Consideration of Distribution Losses Under the RIT-D that came into effect from 1 January 2014, it is a requirement to take into account market benefits (including network losses) in an investment decision. Energex, as a RIT-D proponent, includes all classes of market benefits (including network losses) in its analysis that it considers to be material when applying a RIT-D. However, as per NER, the quantification of market benefits is optional for reliability driven projects. For projects that are not subject to RIT-D process (where credible options with more than $5 million are not available), there is no regulatory requirement for the network losses (and other market benefits) to be considered in the appraisal of investment options. However, Energex estimates the saving in network losses in detailed planning and project approval phases of the projects. The estimated loss saving is not used quantitatively in the investment comparison when comparing options, but considered qualitatively in the comparison of advantages and disadvantages of alternative options. Energex also takes into account network losses when specifying plant to meet the Minimum Energy Performance Standards (MEPS) DAPR 2017/ /22

97 Chapter 7 Overview of Network Limitations Network Limitations Adequacy and Security Network Limitations Voltage Network Limitations Fault Level Summary of Emerging Network Limitations Emerging Network Limitations Maps DAPR 2017/ /22

98 7 Overview of Network Limitations 7.1 Network Limitations Adequacy and Security Connection Point and Substation Limitations There are no limitations identified on the transmission-distribution connection points with the TNSPs covering the forward planning period. Energex conducts joint planning with TNSPs as described in section Limitations affecting either network will be investigated jointly and follow the RIT-T or RIT-D process to ensure prudent solutions are adopted. For each substation, a separate summary forecast of capacity and limitations has been produced for summer and winter based on Customer Outcome Standard. Bulk supply and zone substation reports are contained in Appendix E, respectively. Table 12 shows the projection of bulk supply and zone substation statistics out to 2021/22. It also provides the forecast number of bulk and zone substations with load at risk (LAR) under system normal conditions (LARn) and contingency conditions (LARc). Under system normal conditions, there is no bulk and one zone substation forecasts which have LAR based on the expected completion of committed projects. This is not expected to change over the forward planning period. Under contingency conditions, there is no bulk supply substation forecast with LARc to 2021/22 based on completion of committed projects. Under contingency conditions the forecast for zone substations with LARc in 2017/18 is seven, and decreases to six in 2021/ DAPR 2017/ /22

99 Table 12 Summary of Substation Limitations Substation Type Substation Condition 2017 / 18 Forecast 2018 / 19 Forecast 2019 / 20 Forecast 2020 / 21 Forecast 2021 / 22 Forecast Bulk Supply LARn > 0 MVA LARc > 0 MVA Total Substations Zone LARn > 0 MVA LARc > 0 MVA Total Substations Assessment based on 10 PoE forecast and Customer Outcome Standard. Assessment based on 50 PoE forecast and Customer Outcome Standard. The bulk supply substation total count includes Powerlink owned 33 kv connection points. The zone substation total count includes dedicated customer substations. Customer substation details are not included in this publication. All information as at 30 November of each year. Note: This table includes approved projects only. Proposed strategies to manage the limitations are contained in Appendix D. Substation limitations are also reported in the limitations tables contained in Appendix D. These tables also contain the approved or proposed strategy to manage the identified limitations, along with other related information. Maps of Energex s network showing the location of all Energex s bulk supply and zone substations are presented via the following link: These maps highlight which substations have limitations that have been identified through the process outlined in section Transmission Feeder Limitations For each 132 kv and 110 kv feeder, a separate summary of forecast, capacity and limitations has been produced for summer and winter based on Customer Outcome Standard. These reports are contained in Appendix F. Feeder limitations are identified using the simulation models and processes as described in section and section The analysis provides load at risk information under normal and contingency conditions and evaluates whether the transmission feeder meets its allocated security of supply standard. The outcome of this analysis would then potentially trigger the creation of new strategic projects which indirectly may or may not trigger an update of the forecast and re-run of the models DAPR 2017/ /22

100 The outlook for the 132 kv and 110 kv feeders over the next five years is summarised in Table 13. With no feeders currently exposed to Load at Risk under normal conditions (LARn), it is not anticipated that this figure will change based on current demand forecasts. Under contingency conditions there is one feeder forecast to have LARc. Table 13 Summary of 132 kv and 110 kv Transmission Limitations System Configuration 132 kv and 110 kv Feeder Condition 2017 / 18 Forecast 2018 / 19 Forecast 2019 / 20 Forecast 2020 / 21 Forecast 2021 / 22 Forecast Normal 10 PoE LARn > 0 MVA Contingency 50 PoE LARc > 0 MVA Total Feeders Assessment based on 10 PoE forecast and Customer Outcome Standard. Assessment based on 50 PoE forecast and Customer Outcome Standard. All information as at 30 November of each year. Note: This table includes approved projects only. Proposed strategies to manage the limitations are contained in Appendix D. Limitations identified for 132 kv and 110 kv sub-transmission feeders are also reported in the limitations tables contained in Appendix D. These tables outline the approved or proposed strategy to manage the emerging limitations, along with other related information. Maps of Energex s network showing the location of all Energex s bulk supply, zone substations and existing transmission feeders are presented via the following link: These maps highlight which transmission feeders have limitations that have been identified through the process outlined in section and section Sub-transmission Feeder Limitations For each 33 kv feeder, a separate summary of forecast, capacity, and limitations has been produced for summer and winter based on Customer Outcome Standard. These reports are contained in Appendix F. Feeder limitations are identified using the simulation models and processes as described in section and section The analysis provides load at risk information under normal and contingency conditions and evaluates whether the sub-transmission feeder meets its allocated security of supply standard. The outcome of this analysis would then trigger further investigations into potential solutions that may address limitations identified. For 33 kv feeders, there is no forecast LAR under normal conditions. Under contingency conditions the forecast number of feeders with LAR in 2017/18 is 10, increasing to 19 in 2021/ DAPR 2017/ /22

101 Table 14 Summary of 33 kv Sub-transmission Limitations System Configuration 33 kv Feeder Condition 2017 / 18 Forecast 2018 / 19 Forecast 2019 / 20 Forecast 2020 / 21 Forecast 2021 / 22 Forecast Normal 10 PoE LARn > 0 MVA Contingency 50 PoE LARc > 0 MVA Total Feeders Assessment based on 10 PoE forecast and Customer Outcome Standard. Assessment based on 50 PoE forecast and Customer Outcome Standard. All information as at 30 November of each year. Note: This table includes approved projects only. Proposed strategies to manage the limitations are contained in Appendix D. The limitations identified in the 33 kv sub-transmission feeders are also reported in the limitations tables contained in Appendix D. These tables also contain the approved or proposed strategy to manage the emerging limitations, along with other related information. Maps of Energex s network showing the location of all Energex s bulk supply, zone substations and existing sub-transmission feeders are presented via the following link: These maps highlight which of these sub-transmission feeders have limitations that have been identified through the process outlined in section kv Distribution Feeder Limitations Results from analysis of 11 kv feeder loads, capacity and utilisation forecasts for five years are contained in Appendix F. Table 15 provides a summary of the results of all the 11 kv feeder limitations analysis for 2017/ /19. Table 15 Summary 11 kv Feeders > TMU 11 kv Feeder Condition 2017 / / 19 Detailed Results Feeders with forecast TMU limitation Appendix F Total Number of Feeders 2,082 2,084 Note: Total number of feeders excludes dedicated customer connection assets. Maps of Energex s network showing the location of all Energex s bulk supply, zone substations and constrained 11 kv are presented via the following link: DAPR 2017/ /22

102 7.2 Network Limitations Voltage Voltage Levels The Energex s HV distribution network consists of 4 different voltage levels. Table 16 contains the system highest voltage that equipment is typically manufactured to operationally withstand, and as such the maximum voltage levels that can be imposed without damaging plant. Table 16 System Operating Voltages System Nominal Voltage System Maximum Voltage 132 kv 145 kv 110 kv 123 kv 33 kv 36 kv 11 kv 12 kv Maximum Customer Voltage The National Electricity Rules gives utilities the authority to specify the customer supply voltage range within the connection agreement for HV customers above 22 kv. The National Electricity Rules requires RMS phase voltages to remain between ±5% of the agreed target voltage (determined in consultation with AEMO), except for at times following a contingency event, where the supply voltage shall remain between ±10% of the system nominal RMS phase to phase voltage. In Queensland, for customers less than 22 kv, the Queensland Electricity Regulations (QER) specifies supply voltage ranges for LV and HV customers. Table 17 details the standard voltages and the maximum allowable variances for each voltage range from the relevant QER and National Electricity Rules. Table 17 Maximum Allowable Voltage Nominal Voltage <1000 V (240 V Phase to Neutral 415 V Phase to Phase) Maximum Allowable Variance Nominal voltage +/- 6% 1000 V 22,000 V Nominal voltage +/- 5% or as agreed >22,000 V Nominal voltage +/- 10% or as agreed The values in Table 17 assume a 10 minute aggregated value, and allow for 1% of values to be above this threshold, and 1% of values to be below this threshold DAPR 2017/ /22

103 Transmission and Sub-transmission Voltage Limits Target voltages on bulk supply substation busbars will be set in conjunction with Powerlink Queensland. In general, the sub-transmission busbars at Powerlink Connection Points are operated without Line Drop Compensation (LDC) and with a fixed voltage reference or automatic Volt Var Regulation (VVR) set point. Unless customers are supplied directly from the transmission or sub-transmission networks, the acceptable voltage regulation on these networks will be set by the ability to meet target voltages on the distribution busbars at the downstream zone substations, considering upstream equipment limitations, under both peak and light load scenarios. Where customers are supplied directly from these networks, supply voltages must meet the requirements shown in the previous section. Augmentation of the transmission and sub-transmission network generally occur when voltage limitations occur on the sub-transmission network under system normal conditions with 10 PoE forecast loads, or under N-1 conditions with 50 PoE forecast loads consistent with the Customer Outcome Standard. Where it can assist in meeting voltage limits, VVR should be applied on zone substation transformers to optimise the voltage regulation on the distribution network. In some instances, issues such as the distribution of load on individual feeders may mean that VVR is not a feasible solution Distribution Voltage Limits Target voltages on zone substation busbars are set by Energex as relevant. These zone substation busbars are operated with either Line Drop Compensation (LDC), or with a fixed voltage reference or automatic Volt Var Regulation (VVR) set points. Downstream voltage regulators may also be set with LDC or with a standard set point. For 11 kv distribution systems, the network is operated to supply voltage at a customer s point of connection, as described in Table 17, and considerations are also made to the variable impacts of the different Low Voltage network configurations on subsequent LV customers supply voltage. Augmentation of the distribution network generally occurs when voltage limitations occur on the distribution network under system normal conditions with 10 PoE forecast loads, or under N-1 conditions with 50 PoE forecast loads. Table 18 provides an indicative level of the maximum HV voltage drops in the distribution network, to ensure acceptable supply voltage to LV customers. The drop defined is from the zone substation bus to the feeder extremity, for steady state conditions or 10 minute aggregate values. Table 18 Steady State Maximum Voltage Drop Energex targets Maximum voltage drop no LDC Maximum voltage drop LDC Urban 4% 7% Short & Long Rural - 10% DAPR 2017/ /22

104 Low Voltage Limits Typically LV network voltage is managed by a combination of real time voltage control at the zone substation 11 kv busbar to control the voltage regulation along the 11 kv feeders in conjunction with distribution transformer off-load tap ratio settings. This approach makes it difficult to optimally manage voltage within LV limits at all times and all customer premises and is exacerbated by the intermittency of solar PV. To improve voltage management, Low Voltage Regulators (LVR) are being trialled and will enable finer and more optimal control of voltage regulation to customers. Augmentation of the low voltage network is generally required where rebalancing of customer loads and solar connections or resetting the distribution transformer taps is not sufficient to ensure voltages are within limits. In this case the augmentation solution is required to reduce the voltage drop through the transformer and LV circuits and will typically involve uprating or installing a new transformer and reconfiguring the LV network. There is a long-term plan to move the nominal supply voltage in Australia from 240 V to 230 V, and so distribution transformers, and low voltage network design, would incorporate this future change Sub-transmission Network Voltage Sub-transmission network configuration can impact the voltages on the downstream network. Energex maintains the voltages at the customers connection points according to connection agreements where the customers are supplied directly at the 132 kv, 110 kv or 33 kv levels. For all other situations, the sub-transmission network aims to maintain voltage levels at the substation low voltage buses within a target range. Energex utilises automatic schemes to control the voltages, accounting for the difference in voltage that can occur on the low voltage side of substations between periods of maximum demand and light load, and during single contingency outage conditions or high solar PV penetration. A voltage limitation occurs if a target bus voltage cannot be maintained. The target range depends on various factors such as the type and magnitude of load, customer category, and connection agreement. This is typically 11.3 kv in urban areas and 11.4 kv in rural areas during peak load times. Augmentation generally occurs when voltage limitations occur on the sub-transmission network under system normal conditions with 10 PoE forecast loads, or under N-1 conditions with 50 PoE forecast loads. These limitations are identified as part of the simulations carried out and described in section and are also reported in the limitations tables contained in Appendix D kv Distribution Network Assessment of the 11 kv feeder voltage level is performed using a load flow package with anticipated 10 PoE loads under system normal configuration. Currently this assessment does not take into consideration the influence of solar PV voltage support from the LV network. It has been identified that some feeders with high solar PV penetration on the LV network have reduced the daytime feeder loads to very low levels and approximately 10% of feeders in the 11 kv network are exporting back into the 11 kv bus during certain periods of the day and at certain times of year (cool days in spring or autumn with sunny/clear sky). Energex expects that this number will continue to increase with the addition of solar PV on the network. This situation is DAPR 2017/ /22

105 continuing to be monitored to ensure that the loads on these feeders do not adversely impact on network voltages. The effect on 11 kv feeder voltage levels as a result of embedded generation is evaluated on a case by case basis due to the small number of connections. In the main, the model assumes the following voltage levels at the substation at peak times: CBD Substations 102%; Urban Substations 103%; and Rural Substations 104%. The assessment identifies voltage drops anywhere on the 11 kv feeders, and prudent practices are applied to address areas that are outside the allowable limits. At present, there are nine 11 kv feeders with voltage constraints identified in the Energex distribution network model during system normal conditions. Operational measures have been identified to address these feeders where a project has not been justified Low Voltage Network There are over 45,000 Low voltage (LV) circuits in the Energex network. Design guidelines are available to determine transformer tap settings and the After Diversity Maximum Demands (ADMD) for customers. Energex is required to manage the voltage on these LV circuits within a tolerance range of 240 volts ± 6% (225 volts to 255 volts). There are many factors which impact the voltage present at the customer connection point, including voltage regulation settings at the zone substation, 11 kv and LV network planning and design practices as well as customer owned installations such as embedded generators. In particular, the influx of solar PV systems connected to the LV network has added a new level of complexity to voltage management. Energex has traditionally relied upon maximum demand indicators to identify limitations on distribution transformers. This approach is no longer adequate and Energex is now rolling out distribution transformer monitoring. These monitors, along with customer feedback, are now being used to identify areas of voltage non-compliance. Remedial works are being targeted initially to minimise the risk of damage to customer equipment from voltage excursions with high volts having the highest priority. Energex has explored a number of remediation works which include: Changes to the Line Drop Compensation (LDC) or Volt Var Regulation (VVR) settings at the zone substation; Resetting distribution transformer taps; Balancing of the low voltage network with an emphasis on the solar PV load; Upgrading of the transformer or installation of a new transformer (to reduce the lengths of LV circuits); Increasing the LV conductor size; and Installation of targeted transformer monitoring devices in response to network LV changes and PV installations. Energex is trialling changes to LDC/VVR settings on a small number of zone substations to establish appropriate distribution transformer taps. The trial seeks to establish the optimal LDC/VVR settings and distribution transformer tap settings. The objective is to identify potential solutions across the LV DAPR 2017/ /22

106 network based on a composite factor analysis, and to then carefully target solutions that are cost effective. Energex is investigating the introduction of the 230 volts Australian Standard proposal which specifies a tolerance range of 230 volts +10% to -6% (216 volts to 253 volts). With the additional allowable voltage drop within customer s installations of 5% according to the Wiring Rules (AS 3000), full implementation of the 230 volts standard will require careful consideration to ensure compatibility of any proposed voltage standard with customers equipment. The wider range would relax voltage management limits, especially in the highest priority areas discussed in section Energex and Ergon Energy are developing separate business plans to transition to the 230 volts standard and has begun discussions with the Department of Energy and Water Supply (DEWS). The introduction of this standard will require legislative changes in Queensland. 7.3 Network Limitations Fault Level Fault levels on the Energex network are affected by factors arising from within the Energex network or from externally, such as the TNSP s network, generators and customer connections. Fault level increases due to augmentation within the Energex network are managed by planning policies in place to ensure that augmentation work will maintain short circuit fault levels within allowable limits. Fault level increases due to external factors are monitored by annual fault level reporting, which estimate the prospective short circuit fault levels at each substation. The results are then compared to the maximum allowable short circuit fault level rating of the switchgear, plant and lines to identify if plant is operated within fault level ratings. Energex obtains upstream fault level information from TNSPs annually and changes throughout the year are communicated through joint planning activities as described in section New connections of distributed generation and embedded generations which increases fault levels are assessed for each new connection to ensure limits are not infringed. Known embedded generators are added to Energex s simulation models so that the impacts of these generators on the system fault levels are determined. Table 19 lists design fault level limits that apply at Energex installations. Table 19 Energex Fault Level Limits Voltage level (kv) Short circuit level (MVA) Short circuit level (ka) 132 kv 5,715 / 7,200 MVA 25 / 31.5 ka 110 kv 4,763 / 6,000 MVA 25 / 31.5 ka 33 kv 749 / 1,428 MVA 13.1 / 25 ka 11 kv 250 MVA 13.1 ka DAPR 2017/ /22

107 While Table 19 presents design fault ratings, new equipment typically has ratings higher than these figures, however, some old equipment may have lower ratings. Hence, site specific fault levels are considered in planning activities for network augmentations or non-network solutions to ensure the fault level does not exceed the ratings of the installed equipment. It should be noted that these fault levels are quoted with a 1 second duration, and a faster protection clearing time will be considered where appropriate. This can be further investigated when fault levels approach limits. Where fault levels are forecast to exceed the allowable fault level limits, then fault level mitigation projects are initiated. This year detailed analysis did not identify any additional switchgear fault rating limitations in comparison to the 2016 DAPR. A desktop review of 11 kv feeders exceeding the fault level rating identified approximately 8 projects to address fault level constraints. These projects are anticipated to be completed in the 2017/18 financial year kv Primary Overcurrent Protection Reach Limits Energex engaged with a consultant to undertake a review of the existing protection settings of 11 kv distribution feeders in determining whether a systematic protection issue exists within the network. As part of the report s recommendation, Energex conducted a review of its 11 kv feeder primary protection reach to further improve network safety and increase network transfer tie capabilities. Six percent of the total Energex 11 kv feeders have been identified for potential improvements and is currently being addressed through protection setting changes, installation of 11 kv pole mounted reclosers (PMR) and fuses, and 11 kv feeder reconductoring works. It is anticipated that these improvements would be completed by the end of Summary of Emerging Network Limitations Appendix D provides a summary of proposed committed works in the forward planning period and highlights the upcoming limitations for each bulk supply, zone substation, transmission feeder, sub-transmission and distribution feeders. Potential credible solutions are provided for limitations with no committed works DAPR 2017/ /22

108 7.5 Emerging Network Limitations Maps This section covers the requirements outlined in the NER under Schedule 5.8 (n), which includes providing maps of the distribution network, and maps of forecasted emerging network limitations. The extent of information shown on maps, using graphical formats, has been prepared to balance adequate viewing resolution against the number or incidences of maps that must be reported. In addition to system-wide maps, limiting network maps are broken up into groupings by voltage. For confidentiality purposes, where third party connections are directly involved, the connecting network is not shown. This information is provided to assist parties to identify elements of the network using geographical representation. Importantly, this does not show how the network is operated electrically. More importantly, this information should not be used beyond its intended purpose. Following feedback from customers, interactive maps are now available on the Energex website via the following link: The maps provide an overview of the Energex distribution network, including: Existing 132 kv, 110 kv and 33 kv feeders; Existing bulk supply and zone substations; Future bulk supply and zone substations approved in the five year forward planning period; Existing 132 kv, 110 kv and 33 kv feeders with identified security standard (COS) limitations within the five year forward planning period; Existing bulk supply and zone substations with identified security standard (COS) limitations within the five year forward planning period; and 11 kv feeders or feeder meshes with forecast limitations within the next two years of the forward planning period DAPR 2017/ /22

109 Chapter 8 Demand Management Activities Non-Network Options Considered in 2016/17 Key Issues Arising from Embedded Generation Applications Actions Promoting Non-Network Solutions Demand Management Results for 2016/17 Demand Management Programs for 2017/18 to 2021/22 Other Demand Side Participation Activities DAPR 2017/ /22

110 8 Demand Management Activities Energex has the largest Demand Management (DM) program in Australia, with the majority of its residential customers participating in some form of DM initiative. The DM initiatives provide benefits to customers (through reductions in their electricity bill or through direct incentive payments) and to Energex, by providing an alternative solution to expanding our electricity infrastructure through managing demand on the This highly successful DM program provides a suite of initiatives to encourage and incentivise customers to either reduce their consumption at peak times for the network, or shift their consumption to non-peak times. The DM program places Energex in an excellent position to respond to the changes being experienced by the network to accommodate two way flows of energy, peak demand, technology advancement, customer energy use and appliance growth. Demand growth is forecast to gradually increase over the medium term at a system level. Recently, demand on Energex s network reached a record peak, reinforcing the need for demand management. There is also localised and seasonal demand growth that requires careful management. Energex is well placed to build on its DM program to provide solutions for customers to manage peak demand. Given the lead times in securing demand under management, Energex will continue to pursue cost-efficient DM initiatives over the next five year period to ensure that it has a full range of integrated network and non-network solutions readily available to address demand growth as it arises. The Demand Management vision is: To create a sustainable network by delivering demand management solutions. Energex s Demand Management strategies for the next five years are shown in Table 20. Table 20 Demand Management Strategies Demand Management Strategies Optimise load control system Increase load control capability Support the connection of more distributed energy resources to the network Embed Demand Management into Network Planning Innovation Implement load control system improvements. Control of new appliances. Reward customers through incentives and tariffs. Increase awareness and availability of smart appliances. Development of Standards. Integration with load control system Match load to embedded generation. Implement non-network solutions. Develop solutions and frameworks to manage emerging drivers of demand and to develop emergent Demand Management solutions DAPR 2017/ /22

111 8.1 Non-Network Options Considered in 2016/17 Energex reviews all significant augmentation, refurbishment and replacement projects to determine if there are any viable non-network alternatives to the preferred network options. Non-network assessments examine the economics of viable non-network solutions compared to the preferred network investment option. Non-network solutions considered include a range of residential, commercial and industrial options covering: Permanent load reductions (such as energy efficiency improvements); Embedded generation; and Demand response, incorporating: Residential: controllable loads including air-conditioning, electric storage hot water systems or pool pumps; and Business: shifting of production times or shut down of processes. The non-network option identified as a credible alternative to an augmentation project at Peregian Zone Substation has progressed and is planned to be implemented for 2017/18 summer. 8.2 Key Issues Arising from Embedded Generation Applications Energex continues to experience a number of challenges with respect to connection enquiries and applications for embedded generators. The volume of solar PV applications has increased significantly compared to the previous year. Energex has been working to improve efficiency and deliver more satisfying customer experiences. Improvements of standards and processes together with additional training for technical staff facing customers have been pivotal to developing a more customer-centric approach. With regard to other large embedded generation some key issues are: The increasing number of larger solar PV installations in the range kw at commercial and industrial premises; The management of voltage on distribution feeders in situations where there is significant solar PV generation connected downstream of a step voltage regulator, which has required redesign of voltage regulation control, primary hardware and on-going monitoring; The management of fault level impacts, and increases in fault levels exceeding the rating of shared distribution assets located in the vicinity of embedded generator connections; and The on-going management of operational interface issues with an increasing number of embedded generators presenting challenges such as customers not advising Energex of changes to operating protocols, contact details or site access arrangements at their installations. The above issues present on-going challenges to Energex in terms of managing operational costs while also maintaining compliance, safety and quality of supply to the standards required by regulations DAPR 2017/ /22

112 8.3 Actions Promoting Non-Network Proposals Energex has been implementing DM initiatives as detailed in its Regulatory Proposal. Initiatives undertaken involved a range of commercial, industrial and residential customer programs, along with ongoing development of longer-term DM strategies. As per NER requirements, Energex has a Demand Side Engagement Facility ( the Facility ) to allow parties to register their interest in being notified of developments relating to distribution network planning and expansion projects. In addition, Energex s Demand Side Engagement Strategy (DSES) outlines key information to assist non-network providers in providing submissions for credible nonnetwork solutions as alternatives to network investment. The DSES has been developed in accordance with Clauses I, (g) and (h) of the NER. Both the Facility and DSES are available on the Energex website at ( As outlined in Energex s DSES, for long-term network limitations, i.e. greater than five years away, where Energex believes a project deferral can be achieved through peak demand management, a targeted demand management campaign is initiated. For these campaigns, non-network providers may act on behalf of a customer with incentives paid directly to the customer by Energex. Nonnetwork providers play an important role in promoting targeted demand management campaigns as they promote Energex incentives as a means of reducing the cost of energy conservation and demand management projects at customer sites. Targeted campaign proposals are evaluated against the following mandatory criteria: Location of customer site residing within a targeted area; Technical viability of each option identified; Customer payback period for each opportunity identified (where applicable); Energex maximum $/kva and/or $/kvar for the relevant targeted area; Ability of each option to be measured and verified; and Ability of the customer to achieve stated load reductions within required timeframes. If a proposal is accepted, Energex will enter into a contract with the customer. Energex will then work with either the customer or the customer s nominated non-network provider to ensure initiatives are undertaken and the load reductions measured and verified so that payments can be made to the customer, in accordance with the contract. Energex works with a range of standards and regulatory bodies to ensure that standards and regulations are developed in a way that assists the cost effective management of peak demand. During 2016/17 Energex continued to build on previous work with standards and regulatory bodies to influence demand management related standards and policies. One of the standards critical to the ongoing sustainability of Energex Demand Management is the suite of AS 4755 standards which outline demand response capabilities for residential appliances. Energex saw a need for standardisation of the demand response in electrical energy storage systems (batteries) after observing the developing fragmented market surrounding energy storage. This led Energex to champion the development of a new standard for the demand response in electrical energy storage systems (AS ). Energex began the development process by drafting a project proposal following liaising with many representatives across many industries. The AS obtained public comment phase within 8 months of starting the project with publication scheduled later DAPR 2017/ /22

113 in April AS/NZS speed for reaching the status publication testament to how Energex works with the market being manufacturers and suppliers of appliances. As a result a standard electrical energy storage system specification has been created to allow a plug-and-play approach between vendors and electricity network businesses or others who may wish to enable demand response in electrical energy storage systems. This approach has led to the development of new equipment and the capacity to unlock value from energy storage systems for all participants. 8.4 Demand Management Results for 2016/17 The DM Program operates as a fully integrated network management tool, with business-as-usual approach focusing on reducing the need for future network augmentation. The Program achieved 23.8 MVA of load under control, which exceeded the target of 22.4 MVA for 2016/17. In addition to the load under control further efficiencies were gained from load optimisation, delivering approximately 5 MVA. The highlights included: DM initiatives focused on the residential sector achieved 21.2 MVA of load under control through a range of solutions; Customers are offered incentives for load under control for PeakSmart air-conditioning, electric storage hot water systems and pool pumps. The incentives for air-conditioners are based on the size of the PeakSmart air-conditioner that is installed. Incentives for electric storage hot water systems and pool pumps are offered to customers connecting to a controlled load tariff; continued strong support from industry channels to promote and increase customer participation delivering the current scale of operations at reduced cost to serve; PeakSmart Air Conditioning program is the biggest program of its kind in Australia: - 21,756 PeakSmart air-conditioners were claimed in 2016/17; - A growing presence of major manufacturers (with 23) who continue to voluntarily apply AS/NZS4755 for new models over 750 demand response ready airconditioners models are eligible for connection to the program; - Expansion of program to enable participation by builders and developers has seen many of the top volume builders join the program; and - Expansion of PeakSmart Measurement and Verification Program to represent a more accurate reflection of PeakSmart installations in SEQ. Steady participation for new connections of electric storage hot water systems and pool pumps to controlled load; DM initiatives focused on the commercial and industrial sector achieved 2.6 MVA of load under control, through a range of solutions including: - Load reductions from energy efficiency initiatives; - Load reductions from power factor correction; - Load reductions for small to medium businesses; and - Incentives are offered to business customers to reduce network peak demand in targeted areas which are advertised on the Energex website) DAPR 2017/ /22

114 Load optimisation at 10 zone substations has reduced peak load by approximately 5 MVA. To achieve this, a modified switching program was development and deployed; Submission of the 2017/2018 Demand Management Plan to the Queensland State Government to meet compliance obligations under section 127 C of the Queensland Electricity Regulations with regard to development of Demand Management strategies, plans and reporting; and Demand Management and Innovation Allowance (DMIA) The DMIA of $5 million (during the regulatory period) is provided to explore emerging DM opportunities at Energex through a rigorous governance structure. Energex has utilised this funding to identify and investigate new opportunities for Demand Management. The DMIA projects undertaken in 2016/17 are included in Table 21. Table 21 DMIA projects undertaken in 2016/17 Project Battery Energy Storage Systems (BESS) Pilot Low Voltage Network Power System Static-Estimation Project Real Time Tariff Study Description The objectives of the pilot are focused on gaining a better understanding of the customer value proposition and expectations from the electricity network in take up battery energy storage systems. The proposed project is to develop a power system static state estimator for the low voltage network and to investigate and develop the algorithmic basis for a Low Voltage distribution network monitoring system, forming the basis for coordinating demand and Distributed Generation with respect to operational limits of each individual network segment. The proposed initiative is to research the impact of the new demand tariffs and complimentary load control tariffs on small low voltage customers Connection Enquiries Received Energex has established processes which apply to connection enquiries and applications for embedded generators. These processes comply with the requirements of the National Electricity Rules. In 2016/17 the number of connection enquiries received is shown in Table 22. For micro EG 30 kw or less (mainly solar PV), there is no connection enquiry phase i.e. all connection requests are processed as applications. Table 22 Embedded Generator Enquiries Connection Enquiries Embedded Generator (EG) Connection Enquiries Micro EG 30 kw or less Number 2016/17 Not applicable Embedded Generator Connection Enquiries Other (>30 kw) DAPR 2017/ /22

115 8.4.2 Applications to Connect Received In 2016/17 the number of applications to connect is shown in Table 23. Table 23 Embedded Generator Applications Connection Applications Number 2016/17 Embedded Generator Connection Applications Micro EG 30 kw or less 31,044 Embedded Generator Connection Applications Other (>30 kw) Average Time to Complete Connection In 2016/17 the number of applications received and connected took an average time to complete as shown in Table 24. Table 24 Embedded Generator Applications Average Time to Complete Connection Applications Embedded Generator Connection Applications Micro EG 30 kw or less Embedded Generator Connection Applications Other (>30 kw) Average time to complete 2016/17 5 business days 23 business days 8.5 Demand Management Programs for 2017/18 to 2021/22 Energex will continue to build on the successful existing Positive Payback Program, which has facilitated the development of a market for demand management products and services (including air conditioning and power factor correction). The Program will further grow the penetration of appliances under control on the network and complement the delivery of new demand tariffs. The strategy for coming years focuses on flexible load management to achieve grid balancing and enable response to localised peak demand. This will assist in the integration of distributed energy resources onto the network and further improve network utilisation. Improved utilisation increases the return on the asset for the asset owner, and at the same time lowers energy costs for customers. This scenario offers an economic incentive to both the distributor and customers DAPR 2017/ /22

116 The key principles guiding DM into the future are: Customer centric: Create awareness and understanding to empower customers to make informed decisions; and work with customers to meet their needs and expectations. Lowest cost: Deliver the lowest cost to serve and reduce customer electricity bills. Partner driven: Partner with industry channels to promote and increase customer participation. Standards based: Collaborate with stakeholders to influence regulatory bodies in development of standards for smart appliances. Demand Flexibility: Evolve and expand capability to enable greater integration of distributed energy resources into the network DM programs being proposed for the next five years Residential program this initiative offers customers incentives for the control of appliances such as air conditioning, electric hot water systems, pool pumps and batteries. Management of these flexible loads used by residential customers will be a key element to improve network utilisation. Controlling these loads enables Energex to reshape the load profile on the network in a way that has minimal impact on the customer by matching load to generation. These programs provide customers with options to manage their electricity costs and enable Energex to grid balance and respond to localised peak demand; Demand Management development this program encompasses the management and optimisation of the successful Load Control System, continued work into the coordination of load on the network, development of DM strategies and the reporting obligations to the Technical Regulator, Queensland Government and AER; Business program this initiative offers incentives for business and small to medium enterprise customers within targeted areas to reduce their demand. These targeted areas are identified where it is financially justified to invest in DM, in the years prior to a network constraint arising and the RIT-D process commencing. Options to build on the successful energy efficiency and power factor correction initiatives to enable management of commercial loads via demand response enabled devices in batteries and building management systems will be investigated; and Demand Management and Innovation Allowance (DMIA) The Australian electricity system is experiencing change on an unprecedented scale. Consumers are adopting new technologies, low carbon options and wanting greater choice and control. The DMIA is an important mechanism to fund investigation and development of initiatives which align with and enable Energex to be responsive to these changing demands. Future projects will be identified through continued surveillance of the international DM environment to identify and investigate new opportunities for Demand Management due to: New technologies such as batteries, Electric Vehicles (EVs), home energy management systems and smart appliances becoming more affordable; A greater array of energy services offered to consumers as market participants respond to increased market contestability; and Changes to legislative or regulatory requirements and pricing mechanisms DAPR 2017/ /22

117 8.6 Other Demand Side Participation Activities Energex has also maintained involvement and input to a range of market and industry consultations, forums and development of standards, and will continue to support the long-term development of DM capabilities. From a strategic perspective Energex has been an integral player from the inception, and through development, to the publishing of the Australian Standard AS 4755 suite of appliance demand response capabilities. This provides a national standardised platform for demand response interfaces and capabilities in key residential appliances, including air-conditioners, pool pumps, electric storage hot water systems, and electric vehicles. By extension of AS 4755, both independently and into AS 4777 (Grid Connected Inverter Technologies), this suite of standards will provide demand response capabilities in appliances such as batteries and solar PV. Energex was one of the first DNSPs nationally to trial DM in pools and air-conditioners and has used long running experience in considerable off-peak tariff control programs to work closely in conjunction with industry participants and Australian Standards to deliver the AS 4755 platform. To complement Energex s DM initiatives new tariffs have been developed that will allow customers to benefit further from demand response, incentivise behaviours that support sustainability and deliver cost reflectivity Regulatory Investment Test (RIT-D) Projects As there were no projects approved with credible options having an estimated cost of the augmentation component greater than $5 million, regulatory investment test for distribution in accordance with clause of the National Electricity Rules was not required to be applied. There are no potential RIT-D projects (having credible options with more than $5 million augmentation component) that have been identified for planning during the 2017/18 period. However, Energex will continually monitor emerging network limitations associated with Queens Wharf development, Powerlink projects and projects supplying key infrastructure including facilities associated with the 2018 Commonwealth Games on the Gold Coast and the proposed Maroochy Town Centre and CBD Cross-River Rail and Underground Bus and Train projects DAPR 2017/ /22

118 Chapter 9 Asset Life-Cycle Management Approach Safety and Compliance Asset Condition Management Methodology Replacement Programs Overhead Network Clearance Basement Fire Systems Protection Schemes Reactive Asset Replacement Secondary Systems Asset Replacement DAPR 2017/ /22

119 9 Asset Life-Cycle Management 9.1 Approach Energex s approach to asset management integrates several key objectives, including providing a safe workplace for staff and safe networks for the community, delivering customer service and network performance to meet the required standards, and maintaining an efficient and sustainable cost structure. Policies are developed and refined and plans are prepared to provide a safe, reliable network that delivers the quality of supply and legislative compliance requirements as well as optimum asset life. These policies and plans cover equipment installed in substations as well as the main components of overhead power lines, underground cables and the distribution network. They define inspection and maintenance requirements for each type of asset. Asset optimisation takes into consideration equipment degradation and failure modes as well as safety, environmental, operational and economic consequences. Potential equipment failures are addressed by a number of approaches depending on the nature of the equipment and failure modes. They include on-condition replacement, bulk replacement, risk based refurbishment/replacement and run to failure. The refurbishment and replacement strategies are proactive in nature and targeted at assets which pose a level of risk that cannot be cost effectively managed by maintenance activities. The use of a risk based approach allows the activities to be planned to achieve the desired levels of quality and reliability of supply, safety, while meeting environmental performance at the lowest whole of life equipment cost. Network refurbishment programs are developed to identify and restore or replace assets that are nearing the end of their lifecycle and are not otherwise being replaced during the course of network capacity upgrades. These programs factor in the benefits of future reductions in operating costs and are based on a technical assessment of the serviceability of the asset and the economic costs of replacement or refurbishment. Detailed programs are developed for key asset classes as follows: Bulk and zone substation transformers (power and station); Bulk and zone substation circuit breakers (both indoor and outdoor); Bulk and zone substation infrastructure ; 132 kv and 110 kv overhead lines; 110 kv underground cables; 33 kv overhead lines and underground cables; Distribution overhead (11 kv and low voltage including conductors, switches, reclosers, sectionalisers and regulators); Distribution underground (11 kv and low voltage); and Distribution substations (11 kv transformers, ring main units and low voltage boards). The safety and reliability performance of assets is monitored to identify emerging equipment performance issues. This information is analysed, along with the age, condition and obsolescence of assets, to develop maintenance programs. These activities also facilitate negotiated delivery commitments from service providers, and the prudent physical and financial delivery of programs DAPR 2017/ /22

120 9.2 Safety and Compliance Energex manages safety and compliance requirements through established risk based plans. A number of high profile risks are explained in the following sections Asset Inspections and Condition Based Maintenance Equipment is inspected at scheduled intervals for physical indications of degradation exceeding a threshold that is predictive of an ongoing failure mechanism. Typical examples of inspection and condition monitoring activities include: Analysis of power transformer oil to monitor for trace gases produced by internal faults; Inspection of service lines; Assessing the extent of decay in wood power poles to determine residual strength; and Inspection of timber cross-arms to detect visible signs of degradation. In particular, Energex has a well-established pole inspection program to meet regulatory (Code of Practice) requirements. All poles are inspected in a rolling five year inspection program. Remedial actions identified during pole inspections are managed using a priority code approach where a P1 coding requires rectification within 30 days and P2 requires completion within six months. This ensures the required actions are completed within the relevant regulatory periods. Energex has a three year rolling average in-service pole failure rate of 10 failures per annum based on 2014/15, 2015/16 and 2016/17 financial years, which is significantly below the regulated limit of 66 (representing 0.01% of the pole population) Vegetation Management Vegetation encroaching within minimum clearances of overhead power lines creates safety risks for the public and to Energex and contractor workers. Vegetation in the proximity of overhead power lines is also a major factor in network outages during storms and high winds. Energex maintains a comprehensive vegetation management program to reduce the community and field staff safety risk and provide the required network reliability. To manage this risk Energex currently employs the following strategies: A cyclic program, to cut vegetation on all overhead line routes. The cycle times are managed by Energex s vegetation contractors to ensure the clearance zone is kept clear at all times. Energex uses a suite of measures to ensure compliance of the contractors ; A maintenance program between cycles to ensure the clearance zone remains free of vegetation; and Reactive spot activities to address localised instances where vegetation is found to be within clearance requirements or has been reported for action by customers. From 1 September 2017, there will be a strategy change and warranty provisions in the cyclic program will cover the maintenance program and reactive spot activities. Energex works cooperatively with local Councils to reduce future conflict between trees and power lines. Initiatives include the development of tree planting agreements, specifying requirements for the selection of tree species for use near power lines and programs to remove existing unsuitable trees and replace with power line friendly trees DAPR 2017/ /22

121 9.3 Asset Condition Management Methodology Current asset information, engineering knowledge and practical experience is used to predict future asset condition, performance and risk of failure for network assets. Energex utilises a Condition Based Risk Management (CBRM) methodology for evaluating condition related risk except in the case of asset classes where the effort required to develop and maintain CBRM models is not warranted. In these cases a formal asset class risk assessment is conducted that documents the risks associated with asset failure and mitigation measures implemented. CBRM, implemented in a manner that is consistent with the principles of Energex s risk management framework, is a structured process that combines asset information, engineering knowledge and practical experience to define the current and future, condition and performance. The process has been progressively applied for those asset classes where sufficient information is available to produce a health index and probability of failure for an individual asset. The CBRM process derives a numeric representation of the condition of each asset in the form of a Health Index. Essentially, the Health Index of an asset is a means of combining information that relates to its age, environment, duty, and specific condition and performance information to give a comparable measure of condition for individual assets in terms of proximity to retirement age and probability of failure. The concept is illustrated schematically in Figure 31. Figure 31 Concepts of Health Indices Condition Health Index Remnant Life Bad 10 At retirement age (<5 years) Probability of Failure High Poor years Medium Fair years Low Good 0 >20 years Very low The health index represents the extent of degradation as follows: Low values (in the range 0 to 4) represent some observable or detectable deterioration at an early stage. This may be considered as normal ageing, that is the difference between a new asset and one that has been in service for some time but is still in good condition; Medium values of health index, in the range 4 to 7, represent significant deterioration, degradation processes starting to move from normal ageing to processes that potentially threaten failure; and High values of health index (>7) represent serious deterioration, advanced degradation processes now reaching the point that they actually threaten failure DAPR 2017/ /22

122 Probability of failure (P f ) The detail of the health index formulation is inevitably different for each asset group, reflecting the different information and the different types of degradation processes. There is, however, an underlying structure for all asset groups as outlined below: 1. For a specific asset, an initial age related health index is calculated using knowledge and experience of its performance and expected lifetime, taking account of factors such as original specification, manufacturer, operational experience and operating conditions (duty, proximity to coast). The resulting value of health index is capped at 5.5 since it is not the intention that the age of an asset alone should ever be sufficient to indicate end of life or retirement age. That is, end of life can only be achieved when there is condition related information indicating significant degradation; and 2. Where condition information relating to specific degradation processes can be used to identify potential end of life conditions or retirement age (e.g. oil test results for transformers), a separate factor is derived for each degradation process, calibrated by linking a defined condition to a specific health index value. This gives rise to a number of multipliers, one for each potential end of life condition. These are then combined to give a combined condition factor. The relationship between the CBRM health index and the condition related probability of failure is not linear. An asset can accommodate some level of degradation with very little effect on the risk of failure. However, once the degradation becomes significant or widespread, the risk of failure rapidly increases. This relationship is shown in Figure 32. Figure 32 CBRM Health Index and Probability of Asset Failure Health Index and Probability of Asset Failure Measurable deterioration but no significant increase in P (f) Significant deterioration small increase in P (f) Serious deterioration significant increase in P (f) Health Index The present health index profile of a group of assets provides a snapshot of the current condition of those assets. The CBRM methodology is then used to predict how these assets will behave in the future, or how the health index will change going forward based on the asset duty and operating DAPR 2017/ /22

123 environment. The ability to predict the change in health index over time enables the determination of future failure rates and development of appropriate intervention strategies. CBRM has been completed on the following asset classes: Power Transformers Circuit Breakers Underground Cable ( 33 kv) Instrument Transformers ( 110 kv) The outputs from CBRM, Health Indices, are used in conjunction with an engineering assessment to form the basis of the application of the risk based methodology. The risk based methodology allows Energex to rank projects based on their consequence of failure in addition to their probability of failure. The development of the asset investment plan and specific projects are based on the risk score in conjunction with the engineering assessment and optimised to derive the asset investment program. Figure 33 below provides a summary of the process for delivering network asset investment planning condition based risk management. Figure 33 Process to Create Asset Investment Plan CBRM Process Asset Data and Engineering Knowledge Current and Future Condition Risk Framework Asset Investment Plan Further details of the replacement projects are contained in the Limitations Tables in Appendix D DAPR 2017/ /22

124 9.4 Replacement Programs In addition to the replacement projects identified via CBRM, Energex has a number of specific programs to replace network assets where the requirement has been identified as a result of the inspection or condition monitoring programs. The following sections provide a summary of these programs Poles Pole replacement occurs through a combination of poles failing inspection, capital works (including augmentation projects), and proactive pole replacement where age, type, location, and network risk are considered. Proactive pole replacement programs are used to remove the highest risk poles from the network in order to manage safety and network risk and maintain a sustainable pole replacement rate. These poles are typically the oldest poles in the network and/or those where service life has already been extended by more than 18 years by nailing. Wherever possible, proactive pole replacement is undertaken in conjunction with reconductoring and other work for efficiency reasons. Figure 34 provides and overview of the various programs which replace poles in the network. Figure 34 - Pole Replacement and Nailing Contributions from all Programs Inspections Pole Inspection Program Identified Sites (Risk Based) Reinstatement Options Unserviceable Replacement Unserviceable Nailing Programs 33kV Unserviceable Pole Replacement LV Unserviceable Pole Replacement 33kV Unserviceable Pole Nailing LV Unserviceable Pole Nailing Aged Pole Replacement Program 110kV Unserviceable Pole Replacement 11kV Unserviceable Pole Replacement Risk Based Pole Nailing 11kV Unserviceable Pole Nailing Incidental Replacement (Other Programs) Overhead Conductor Conductor replacement programs are used to remove the highest risk conductor from the network to manage safety and network risk and maintain a sustainable conductor replacement rate. The programs are targeted to specific areas based on the age, type, and condition (presence of numerous joints and splices from previous failure) and the network risk associated with the conductor. These DAPR 2017/ /22

125 conductors are typically the oldest and of the lowest cross sectional area on the network or those exposed to more corrosive environments such as coastal regions. Wherever possible, reconductoring includes the proactive replacement of poles and crossarms which meet refurbishment criteria for efficiency reasons. In the case of LV reconductoring, open wire conductor is replaced with LV ABC to achieve the additional safety and reliability benefits associated with insulated conductor. This also removes wooden crossarms which have less than half of the service life of other overhead assets from the LV network providing long term operational cost savings Crossarms and Pole Top Structures Crossarm and pole top structure (e.g. wooden risers or transformer brackets) replacement occurs through a combination of failing inspection, capital works (including augmentation projects), and proactive replacement where age, type, condition, and network risk are considered. The vast majority of crossarm replacements on the Energex network are driven by the inspection process and treated as an operational cost. Relatively small volumes of crossarms are replaced proactively as a part of the reconductoring programs outlined in Section above where they either meet refurbishment criteria based on type, age and condition or are removed with the construction of LV ABC in lieu of open wire Customer Service Lines Customer service line replacement occurs through a combination of failing inspection, capital works (including augmentation projects), and proactive replacement where age, type, condition, and network risk are considered. The proactive replacement of customer service lines is currently focused on open wire and concentric neutral services, as well as a population of problematic XLPE services experiencing insulation degradation, as they have been assessed as presenting the highest safety risk. As these asset types are addressed, proactive service replacement will move towards the next highest priority with consideration of condition and population age. This includes PVC covered services (parallel web and twisted) and a portion of older XLPE insulated services Underground Cable Underground cable replacement occurs through a combination of equipment failure, capital works (including augmentation projects) and proactive replacements where age, type, condition and network risk are considered. Proactive replacement of underground cable is typically only undertaken at voltages of 33 kv (sub-transmission) and above due to the inherent network risk associated with failure and the lead time required to complete such projects. Energex uses the CBRM methodology discussed in Section 9.3 above to forecast the retirement of underground cables at 33 kv and above. These replacements are undertaken as individual projects on a feeder basis. Details of these projects are contained in the Limitations Tables in Appendix D. Underground cable replacement for voltages of 11 kv and below is completed predominately in response to asset failure or as a part of network augmentation. In addition to the condition based and reactive replacements, targeted replacement programs may be established in the event of risk based criteria being determined from the ongoing monitoring of asset failures and network issues. Energex has undertaken such a program in response to safety incidents arising from the deterioration of the neutral in a particular type of LV cable. The majority of targeted program for this particular LV cable has been completed, however small sections of such cable not previously identified in network data are occasionally found during the course of other work and programmed for replacement accordingly DAPR 2017/ /22

126 9.4.6 Distribution Plant The Energex distribution network includes various pieces of operational plant including Automatic Circuit Reclosers (ACRs or Reclosers), Sectionalisers, Step Voltage Regulators (SVR s), Distribution Transformers (pole and ground mounted), Distribution Substations (SD sites), Ring Main Units (RMU s) and Manual and Remote Controlled Switches. Plant of this nature is primarily replaced when identified to be in poor condition either via routine inspection processes or during the course of other network activities. In addition to the condition based replacement, targeted replacement programs may be established in the event of risk based criteria being determined from the ongoing monitoring of asset failures and network issues. Energex currently has targeted programs of replacement for Ring Main Units and 33 kv Air Break Switches. Details of these programs are covered below Air Break Switch Replacement Energex has experienced a series of failures of a specific type of 33 kv Air Break Switch manufactured between 1989 and Failures of this type of Air Break Switch have resulted in localised outages, potential safety incidents and network operating restrictions. An Energex investigation identified a total of 102 of this type of Air Break Switch installed at various bulk supply and zone substations on the Energex network. The root cause of failure is a manufacturing defect. Energex conducted risk assessments and issued a Safety Alert to the business and industry at this time. A program to replace the 33 kv Air Break Switch tops commenced in the 2015/16 financial year and is expected to be completed by Ring Main Unit (RMU) Replacement Energex has experienced approximately 20 in-service failures of a specific Ring Main Unit from 2009; with failures increasing in 2015 and The affected Ring Main Units which were manufactured between 1975 and 2007 are installed at various 11 kv Cubicle mount substation sites across the Energex network. The service life for 85% of the total population varies from 15 to 40 years with approximately 50% in the 25 to 40 years range. Due to inherent risks associated with the failure of these switches during operation and safety risks to the general public; a program to inspect and test the affected ring main units was initiated in 2016/17. This process identified approximately 140 ring main units that require replacement based on condition. These units are programmed for commissioning in 2017/18. An ongoing process of partial discharge testing on an 18 month cycle has been implemented to monitor the condition of the remaining population with replacements to occur based on condition Obsolete and Aged Protection Relays Energex has a number of obsolete protection relays which are installed on the network. The obsolete relays are considered to be at, or close to, the end of their functional or useful life and have identified performance defects, deficiencies, or safety implications that warrant their removal from service. Some of the relays may be classified as obsolete because of age, unacceptable failure rate, high maintenance demand, inability to source like-for-like replacement units or to repair, or unacceptable DAPR 2017/ /22

127 performance compared to current requirements. The obsolete relays will be removed from service either during planned maintenance, as a part of a network replacement project, or in response to an in-service failure. Energex has replaced approximately 1,550 obsolete relays since having embarked on a replacement program in The remaining approximately 100 obsolete relays will be removed in conjunction with other works at the various substations. As well as replacing obsolete relays, Energex has an ongoing program of replacement for relays that have reached the end of their useful life. Replacement is based on a combination of relay type, age, failure rate and risk associated with failure or maloperation. Wherever possible, protection relays are replaced in conjunction with other works for efficiency reasons. In circumstances where no other works are being undertaken at the site, a stand alone relay replacement project is raised Oil Filled Circuit Breakers A qualitative risk assessment for oil circuit breakers, particularly in high density areas under manual switching operations (no remote control), identified high risk plant. In 93 Commercial and Industrial (C&I) substations, existing 11 kv circuit breakers require an operator to trip or close. Several control measures have been put in place including scheduled maintenance programs, condition monitoring and capital replacement programs. A capital program is in place to replace these manually operated oil circuit breakers with current standard non-oil circuit breakers or ring main units where possible; or replace the rackable oil tank with a vacuum tank. Following a risk assessment process, substations with manual control circuit breakers have been prioritised and a program of replacement established to address the risk by 2019/20. These replacements are undertaken as individual projects on a site basis. Details of these projects are contained in the Limitations Tables in Appendix D Instrument Transformer Replacement Energex has experienced multiple catastrophic failures of 110 kv oil filled porcelain bushing voltage transformers. Catastrophic failure of these assets results in porcelain bushing projectiles as a result of explosive failure. This poses a high safety risk to field personnel and the public. Powerlink Queensland experienced multiple catastrophic failures of this type of Capacitor Voltage Transformers (CVTs) preceding An incident investigation undertaken by Powerlink in late 2012 recommended the replacement of this type of CVT at or above 20 years of age. Energex has adopted this criteria for the population of this type of CVT in its network and has a number of units approaching or beyond the retirement age recommended by Powerlink s failure incident investigation. These replacements are undertaken as individual projects on a site basis. Details of these projects are contained in the Limitations Tables in Appendix D Planned Battery Replacement Batteries are relied on in Energex substations for a combination of key purposes including substation control, substation and power line protection systems, communications equipment supply, and emergency lighting. The battery bank is critical to the operation of substations. During normal operation some electronic secondary systems cannot operate without batteries. Under fault conditions, no electronic systems will operate at all without batteries DAPR 2017/ /22

128 Batteries, by their construction, have an operating life span limited by chemical degradation of components during charging and discharging, necessitating periodic replacement. This lifespan is heavily affected by battery quality, mode of operation and the storage environment. Failure of a battery bank leads to inadequate protection resulting in potential safety consequences, a breach of requirements under the National Electricity Rules (NER), as well as a reduction in secondary systems security. Replacement of these end-of-life battery banks is required in order to mitigate potential safety and legislative compliance risk and maintain adequate secondary systems security Battery Charger Replacement Battery chargers are used to charge the substation battery banks which perform the functions outlined in Section above. Battery charger replacement occurs through a combination of chargers failing inspection, capital works (including augmentation projects), and proactive charger replacement where age, type, condition, and network risk are considered. Battery chargers typically have an expected life in the range of 30 to 40 years subject to manufacture type. Proactive battery charger replacement programs are used to remove the highest risk chargers from the network in order to manage safety and network risk. These chargers are typically the oldest units in the network and/or those which are problematic such as units where the AC ripple voltage has exceeded specification having a negative impact on the life of the batteries. Wherever possible, battery charger replacement is undertaken in conjunction with other capital works at a substation such as upgrades or relay replacements for efficiency reasons LV Service Fuse Holder Replacement Service fuses provide protection on overhead services that supply customer installations. With the introduction of XLPE service cable in the mid 1990 s, Energex used a grey coloured compact fuse holder up until 2007, at which point the supplier offered a newer and more robust design. The original grey fuse holders supplied to Energex are aged between 7 to 20 years. There has been an increase in failures of the original fuse holders in recent times. One mode of failure appears to be overload of the fuse holder, causing insulation to become hot and melt, and reduce clearances between phases and/or neutral that cause flashover. Tracking of the plastic insulation can also occur due to salt spray or air pollution, causing a flashover between phases or phase to neutral. This is exacerbated by cracks that may have been caused when the central mounting bolt onto the steel bracket was initially tightened, and moisture filling these voids, leading to tracking and discharge. The results of these failures can cause: Flashover at the fuse holder that can cause the local 11 kv/415 V supply transformer fuse to operate (area trouble); Flashover and melting insulation have known to cause wood pole fires. Incident of grass and fence fires have also been reported due to fallen melting plastics; and Tracking onto the metal bar that supports the fuse holder, may cause this bar to become energised, which presents a safety risk to field staff working around these assets DAPR 2017/ /22

129 Given the risk associated with the failure mode, this type of fuse holder has been recommended for removal from the network. Identification and removal of the fuse holders is being undertaken as a part of the 5 year cycle for pole inspection for efficiency and is expected to be completed by 2022/ Replace Ageing Cable Terminations Energex has a population of approximately 4,100 ageing cable terminations with cast iron pot heads. The deterioration of the dielectric material inside the chamber of ageing terminations eventually leads to failure of the cast iron pot head which is potentially catastrophic (explosive). To address the public safety risk associated with failure, problematic pot heads of all voltages will be replaced as a targeted replacement program. Cast iron pot heads located near high risk areas such as schools and high pedestrian areas will be replaced as a priority in the initial years of the program. It is proposed to replace all problematic cable terminations by the end of 2025 (10 year program). 9.5 Overhead Network Clearance Traditionally conductor clearance to ground and clearance to structure issues have been identified primarily during the asset inspection (poles) program. This program is cyclic in nature and is essentially 5 years for the Energex network. Criteria for non-conformance in regards to conductor clearance to ground or structure are based on legislative requirements dependent upon network voltage, land use below the conductor (road, trafficable area) and type of structure pertinent to ease of access by a person. Energex has undertaken a trial using Light Detection and Ranging (LiDAR) equipment mounted on a light aircraft to model its network for the first time in 2016/17. This technology and delivery model provides the ability to conduct analysis across the entire network, in a shorter timeframe (cycle) than traditional capability permitted. This provides knowledge of risks that otherwise would remain undetected for some time. The first use of this tool has reported a high number of potential non-conformances. While the LiDAR measurements are point in time (of flight pass) and there is a degree of dynamic movement in overhead conductors caused by electrical load, ambient temperature and wind, action is being taken on the potential non-conformances identified. Potential non-conformances have been risk assessed and prioritised. The risk assessment has considered specific high risk locations such as high traffic areas (e.g. vehicle, livestock and human movement/activity), high consequence of contact (e.g. schools), high likelihood of contact (e.g. adjacent to sheds, cultivated areas), voltage, and conductor type. The higher risk defects and locations are being programmed for completion prior to the end of 2017/18. The lower risk and more remotely located regional network sections are proposed for completion during 2018/ Basement Fire Systems Energex has identified the hazard of a fire in a zone or bulk supply substation cable basement as a potential high consequence, low likelihood event. In response, Energex is undertaking cable basement fire risk mitigation works at strategic locations on its network to reduce the customer and safety related DAPR 2017/ /22

130 risks resulting from cable basement fires. These locations include 14 substations which supply CBD areas, hospitals or significant commercial and industrial customers. Site specific risk assessments have been undertaken to manage cable basement fire risk to ALARP. Works are in progress and it is anticipated all works will be completed in Protection Schemes Effective protection systems for the high voltage network are a vital link in the provision of a safe and compliant network. Protection systems detect and disconnect faults from the power system, for example when electrical equipment fails or an incident occurs causing powerlines down on the ground. Reliable operation of protection schemes is vital to mitigating these risks, with failure of a protection system to do so resulting in unsafe conditions until the public or staff notify Energex of an incident and power is switched off. Energex have a program for replacement of obsolete protection schemes over the 2015/16 to 2019/20 period. The objectives of this program are to: Mitigate safety risks to staff and the community to As Low As Reasonably Practicable (ALARP); Provide for continued operation of the high voltage network in accordance with protection system requirements in the National Electricity Rules; and Minimise the likelihood of plant damage by improving capability for effective clearance of high voltage faults. Wherever possible, replacement of obsolete protection schemes is undertaken with other capital work such as primary plant replacement or augmentation for efficiency reasons. In circumstances where this is not possible, stand alone projects for replacement of the obsolete protection schemes are undertaken. Details of these projects are contained in the Limitations Tables in Appendix D. 9.8 Reactive Asset Replacement Where unanticipated failures of critical network assets occur, Energex must replace these assets to maintain safety or meet the guaranteed service levels required in its statutory distribution authority (security standard). Proactive asset replacement and maintenance programs are unable to prevent one hundred percent of critical failures. Energex has historically experienced early/mid-life failures on critical assets due to inherent defects or deficiencies in the design, materials selection or manufacturing process of the asset. Energex maintains an annual budget to ensure it is able to respond to urgent and unforeseen asset failures based on historical averages from the 2010/11 to 2014/15 period. 9.9 Secondary Systems Asset Replacement Secondary systems asset replacement is discussed in Chapter 15 Operational and Future Technology DAPR 2017/ /22

131 Chapter 10 Network Reliability Reliability Measures and Standards Service Target Performance Incentive Scheme (STPIS) High Impact Weather Events Guaranteed Service Levels (GSL) Worst Performing Feeders Safety Net Target Performance DAPR 2017/ /22

132 10 Network Reliability 10.1 Reliability Measures and Standards Energex s Distribution Authority DO7/98 (DA) details Minimum Service Standards (MSS) to be achieved for network reliability. The MSS are prescribed in the DA to provide a standard against which a distribution entity s feeder performance can be assessed across the network and from year to year. Two reliability measures are defined as follows: System Average Interruption Duration Index (SAIDI) limits; and System Average Interruption Frequency Index (SAIFI) limits. SAIDI indicates the total minutes, on average, that customers are without electricity during the relevant period. By contrast, SAIFI indicates the average number of occasions each customer s supply is interrupted during the relevant period. Both indices are inclusive of both planned and unplanned events. The DA prescribes that Energex must use all reasonable endeavours to ensure that it does not exceed the SAIDI and SAIFI limits set out in the DA for the relevant financial year. Circumstances beyond the distribution entity s control are generally excluded from the calculation of SAIDI and SAIFI metrics. In particular, the DA excludes the following events from the MSS calculations: An interruption of a duration of one minute or less (momentary); An interruption resulting from load shedding due to a shortfall in generation; An interruption resulting from a direction by AEMO, a system operator or any other body exercising a similar function under the Electricity Act, National Electricity Rules or National Electricity Law; An interruption resulting from automatic shedding of load under the control of underfrequency relays following the occurrence of a power system under-frequency condition described in the power system security and reliability standards; An interruption resulting from failure of the shared transmission grid (Powerlink); An interruption resulting from a direction by a police officer or another authorised person exercising powers in relation to public safety; An interruption to the supply of electricity which commences on a major event day; and An interruption caused by a customer s electrical installation or failure of that electrical installation. Under Energex s DA, exceedance of the same MSS limit in three consecutive financial years is considered a systemic failure and constitutes a breach of the DA. The MSS limits for 2017/18 and the regulatory period have been flat-lined and are presented in section , along with Energex s performance against these limits. The MSS limits are in accordance with Schedule 2 of the DA. Also under Energex s DA, Energex is required to monitor and report on the performance of 11 kv Worst Performing Feeders (WPF) and improve their reliability. A summary of the performance of Energex s 2017/18 WPF feeders is presented in section 10.5, and a full report is contained in Appendix G of the DAPR DAPR 2017/ /22

133 Although Energex s DA does not include requirements to report on momentary interruptions (MAIFI), the AER does include this measure in its annual RINs and in the measures that may be applied in the STPIS. However, there is currently no requirement for Energex to report momentary interruptions. Energex s preference is for reporting momentary interruptions by the momentary average interruption frequency index by event (MAIFIe) rather than MAIFI, as MAIFIe does not include reclose attempts of a protection device which immediately precede a lockout or a successful reclose. Reporting by MAIFIe is also consistent with reporting in other jurisdictions Reliability Performance in 2016/17 The normalised results in Table 25 highlight a favourable performance against MSS for all of Energex s network categories. Table 25 Performance Compared to MSS Normalised Reliability Performance 2016/17 Actual 2016/17 MSS MSS SAIDI (mins) CBD Urban Short Rural SAIFI CBD Urban Short Rural Energex s MSS is flat-lined for the current regulatory period Reliability Compliance Processes Due to inherent statistical variability in reliability performance from year to year, mainly due to adverse weather, simply aiming for the MSS would lead to regular non-compliances and breaches of Energex s DA. To minimise the risk of non-compliance to less than once in 10 years, Energex has set its internal target to 10-15% below the stated MSS. These targets are based on a Monte Carlo simulation of the past five years of SAIDI and SAIFI performance data. Under Energex s DA, these planning criteria will also ensure that the likelihood of a systemic breach of the MSS, defined to be an exceedance of the MSS limits in three consecutive years, is managed to a tolerable level of risk. A forecast of network performance for each category is carried out based on analysis of the three key components of planned outages, non-storm unplanned outages and storm unplanned outages. These forecasts are then adjusted to allow for both decreases in reliability (due to factors such as asset ageing), and expected improvements under Energex s existing capital and operating expenditure program. These adjusted forecasts are then compared to the internal reliability targets to determine if a gap exists where the forecast performance is unfavourable to any of the targets DAPR 2017/ /22

134 If gaps in performance prevail, further network analysis is undertaken and programs are implemented to target those areas where the maximum reliability benefit can be achieved for minimum capital expenditure. Historically, the majority of these reliability programs have been made up of reliability improvements to specific 11 kv feeders, as Energex s 11 kv network is the highest contributor to its SAIDI and SAIFI results. By creating projects around individual 11 kv feeders, the performance of each feeder can be analysed, and the improvement works can then be targeted to the specific issues on each feeder. This process is carried out once every five years as part of Energex s regulatory proposal which is submitted to the Australian Energy Regulator (AER). If it is determined that reliability works are required to be funded to achieve the minimum service standards, then the estimated Capex required is submitted to the AER for approval. However, for the five year regulatory control period commencing 1 July 2015, Energex s forecasts show that the risk of exceeding MSS is tolerable. Therefore, no capital expenditure is proposed for MSS compliance before In conjunction with carrying out reliability improvement works aimed at achieving MSS, Energex also has obligations to improve the performance of the 11 kv feeders that have the poorest individual performance. The works proposed under these projects will be targeted to address the specific issues on each feeder. Additional information on the worst performing feeders can be found in section 10.5 and Appendix G Reliability Non-Compliance Corrective Actions As shown in Table 25, Energex met its reliability targets during 2016/17. This was due to the majority of severe weather events being excluded under the Major Event Day criteria and the realisation of previously completed reliability projects targeting poorly performing assets. Energex is planning to remain fully compliant in future years by maintaining a focus on reliability especially on the worst performing sections of the network DAPR 2017/ /22

135 10.2 Service Target Performance Incentive Scheme (STPIS) The SAIDI and SAIFI unplanned performance results (after removal of excluded events) compared to the STPIS targets are shown in Table 26. Table /17 STPIS Results 2016/17 Actual 2016/17 Target SAIDI Unplanned (minutes) CBD Urban Short Rural SAIFI Unplanned (number pa) CBD Urban Short Rural Energex exceeded the capped revenue for 2016/17. A breakdown of the revenue by feeder category and SAIDI and SAIFI is shown in Table 27. The $42.82 M result is above the capped reward of 1.9% of revenue of $26.95 M which Energex is eligible to claim. Table /17 STPIS Uncapped Revenue STPIS Revenue (Uncapped) $ M SAIDI SAIFI Total CBD $0.13 $0.13 $0.26 Urban $10.06 $16.57 $26.63 Short Rural $6.79 $9.14 $15.93 Total $16.98 $25.84 $ STPIS Methodology The STPIS that Energex is operating under in this regulatory period includes six reliability targets, or SAIDI and SAIFI for each of the feeder categories of Urban, Rural and CBD. Due to the inherent variability in the network performance, the outcomes under STPIS are probabilistic in nature rather than deterministic. Each of the six STPIS reliability parameters has an underlying DAPR 2017/ /22

136 probability distribution. The intrinsic assumption in the forecast methodology is that the past variability will be a reasonably good predictor of the future variability. The forecast for Energex s CBD, Urban and Rural networks is based on their historical five year average normalised performance summarised in Table 28. The total performance is then compared with the STPIS targets, shown in Table 29 to determine the forecast gap in performance as shown in Table 30. A positive gap means the performance is favourable to target and negative unfavourable to target. A forecast of Energex s performance against the STPIS targets cannot be provided beyond 2019/20 as STPIS targets for the next regulatory period are yet to be determined. The targets for 2020/21 to 2024/25 will be determined as part of Energex s regulatory proposal for that period STPIS Results and Forecast STPIS results are shown below in Table 28 and Table 29. Table 28 STPIS SAIDI / SAIFI Forecast Year SAIDI (mins) SAIFI (Int) Urban Rural CBD Urban Rural CBD 2017/ / / Table 29 STPIS SAIDI / SAIFI Targets Year SAIDI (mins) SAIFI (Int) Urban Rural CBD Urban Rural CBD 2017/ / / Table 30 STPIS SAIDI / SAIFI Forecast Performance Comparison Year SAIDI (mins) SAIFI (Int) Urban Rural CBD Urban Rural CBD 2017/ / / DAPR 2017/ /22

137 2006/ / / / / / / / / / / / / /20 SAIFI (interruptions) 2006/ / / / / / / / / / / / / /20 SAIDI (minutes) As indicated in Table 30, Energex s results are all favourable to target for 2016/17. Energex is forecasting favourable results to all targets in the regulatory period Figure 35, Figure 36 and Figure 37 summarise the Urban, Rural and CBD historical performance and forecast compared to targets. Figure 35 STPIS Urban SAIDI / SAIFI Forecast F'cast Non-Storm Storm Target F'cast Non-Storm Storm Target DAPR 2017/ /22

138 2006/ / / / / / / / / / / / / /20 SAIFI (interruptions) 2006/ / / / / / / / / / / / / /20 SAIDI (minutes) Figure 36 STPIS Rural SAIDI / SAIFI Forecast 250 F'cast Non-Storm Storm Target F'cast Non-Storm Storm Target DAPR 2017/ /22

139 2006/ / / / / / / / / / / / / /20 SAIFI (interruptions) 2006/ / / / / / / / / / / / / /20 SAIDI (minutes) Figure 37 STPIS CBD SAIDI / SAIFI Forecast 12 F'cast Non-Storm Storm Target F'cast Non-Storm Storm Target DAPR 2017/ /22

140 10.3 High Impact Weather Events Section outlines the physical environment within which Energex operates its network and provides an overview of the weather conditions faced. As a consequence, Energex plans for the occurrence of extreme weather events and has developed the following Plans: Summer Preparedness Plan; Flood Risk Management Plan; and Bushfire Risk Management Plan. The current version of the Summer Preparedness Plan, Flood Risk Management Plan and Bushfire Risk Management Plan are available at The company policies and reports page and Network Plans section on Energex s website ( And-reports). Detailed below are some recent weather events that have had significant impact on the Energex network Bushfire Management Energex reviews and updates a Bushfire Risk Management Plan annually. The Plan is published in August each year and contains a list of programs and specific bushfire initiatives for the next bushfire season. Energex has on-going programs to replace aged conductors, install gas insulated switches in lieu of air break switches, replacement of sub optimal pole top constructions and utilises sparkless fuses in high bushfire risk areas. Energex also undertakes pre-summer inspections in bushfire risk areas and rectifies the high priority defects identified on the patrols. It also reports and investigates suspected asset related bushfires Flood Resilience Following the 2010/11 floods which impacted the regions of Brisbane, Ipswich, Gympie and the Lockyer Valley Energex updated its planning guidelines for installing infrastructure in flood prone areas and reviewed flood resilience measures. Flood resilient electrical infrastructure is important, not least because other essential services needed during and after a flood depend on electricity to operate. A number of flood resilience projects at CBD substations and several zone and bulk substations have been completed and operational plans incorporating the dispatch of generators and flood isolation switching have been reviewed and updated for the Brisbane, Bremer and Nerang River systems. In 2016, Energex developed revised operational plans based on new flood models obtained from Brisbane City Council for creeks in their council area. The effects of ex- Tropical Cyclone Debbie were felt throughout Queensland and impacted the South East of the State on 30 March 2017 for over a week. The severe weather system brought with it winds of more than 120 km/h and torrential rain causing significant flooding, landslides and affected power to 214,855 homes and business on the Energex network. Energex crews worked around the clock on vast sections of the network to repair more than 1,800 fallen powerlines and flooded affected equipment as a result of Debbie. Following the deluge from ex tropical cyclone Debbie in March 2017 which caused major flooding on the Albert and Logan rivers, Energex will be updating operational flood plans for these river systems. Energex is also developing a longer term climate adaption plan which will target key assets impacted DAPR 2017/ /22

141 by flood waters and storm surge. Measures include raising padmount transformers and upgrading overhead water crossings Guaranteed Service Levels (GSL) The Queensland Electricity Distribution Network Code (Code) clause 2.3 specifies a range of Guaranteed Service Levels (GSLs) that distribution entities must provide to their customers. Failure to meet these GSLs requires the payment of financial rebates to any customer whose service does not meet these GSLs. Whilst most of the GSLs are not network related, there are a number of reliability service levels as shown in Table 31. Depending on the type of feeder supplying a customer, limits are defined for acceptable outage durations and frequency of unplanned interruptions. Some specific exemptions to these requirements include planned interruptions and those unplanned interruptions which occur within a region currently affected by a natural disaster as defined in the Code. Table 31 Reliability GSLs Feeder Type Interruption Duration GSL (for each incident) Interruption Frequency GSL (Number per financial year) CBD > 8 hours 10 Urban > 18 hours 10 Short Rural > 18 hours Automated GSL Payment Since 1 July 2010, the Code requires that a distributor use its best endeavours to automatically remit a GSL payment to an eligible small customer. Customers will receive the payment for Interruption Duration GSLs within one month, whereas Interruption Frequency GSL payments will be paid to the currently known customer once the requisite number of interruptions has occurred. Table 32 shows the number of claims paid in 2016/17. Table 32 Reliability GSLs Claims Paid 2016/17 GSL Description Paid Claims Reliability Duration 2,415 Reliability Frequency 0 Total Reliability GSLs 2, DAPR 2017/ /22

142 10.5 Worst Performing Feeders The Minimum Service Standards represent a measure of the average performance of the network. However, this means that there are groups of customers receiving performance which is worse than the average. Some of these customers may be eligible for GSL payments if the network performance they are experiencing is greater than the duration and frequency thresholds outlined in the previous section. In accordance with Energex s Distribution Authority, Energex is required to monitor, improve and annually report on the Worst Performing Feeders (WPF) performance. Energex s previous 2016/17 Distribution Annual Planning Report defined kv feeders as its WPF, of which 49 were Urban and 87 were Rural. Table 33 and Table 34 compares the performance of this pool of feeders as reported last year with their current SAIDI and SAIFI performance. The performance of the feeders is measured by the normalised three year average feeder SAIDI and SAIFI and includes both planned and unplanned interruptions. Table 33 Worst Performing Feeder SAIDI Performance Comparison 2015/16 3 Year Average Feeder SAIDI (mins) 2016/17 3 Year Average Feeder SAIDI (mins) Minimum Average Maximum Minimum Average Maximum Urban ,002 Rural , ,047 Table 34 Worst Performing Feeder SAIFI Performance Comparison 2015/16 3 Year Average Feeder SAIFI (interruptions) 2016/17 3 Year Average Feeder SAIFI (interruptions) Minimum Average Maximum Minimum Average Maximum Urban Rural Table 33 shows that the three year average performance of the Urban WPF SAIDI has degraded by 0.3% and the average performance of the Rural WPF SAIDI has improved by 8.9%. Table 34 shows that the three year average performance of the Urban WPF SAIFI has improved by 14.3% and the average performance of the Rural WPF SAIFI has improved by 4.4%. Figure 38 and Figure 39 compare the number of outages by cause on the urban and rural worst performing feeders for the current year and the previous year. The comparisons are based on the normalised performance excluding major event days. Overall, the number of outages on urban worst performing feeders has improved for the majority of causes except for planned, Substation Equipment DAPR 2017/ /22

143 Accidental Environmental Equip Other Human Int No Cause Other O/H Equip Planned Substation Equip Protection U/G Equip Vegetation Weather Wildlife No. of Outages Accidental Environmental Equip Other Human Int No Cause Other O/H Equip Planned Substation Equip Protection U/G Equip Vegetation Weather Wildlife No. of Outages and Protection. On the Rural network there was an increase in outages for Equipment Other, No Cause, Planned and Wildlife with the other causes relatively constant. Figure 38 Normalised Count and Causes of Urban Outages / /17 0 Outage Causes Figure 39 Normalised Count and Causes of Rural Outages 1,400 1,200 1, / / Outage Causes Details of the 2016/17 Worst Performing Feeder is available is available in Appendix G. Under Energex s Distribution Authority, the method of classifying WPF is shown in Table 35 and includes a cap on the total number of feeders in the program and through the inclusion of SAIFI in DAPR 2017/ /22

144 addition to SAIDI measures, will give increased weighting to feeders with a high number of customer interruptions than if SAIFI were not included. This section provides information on the worst performing feeders for the urban and rural categories for 2017/18. Table 35 Worst Performing Feeder Performance Criteria WPF Criteria The worst performing 11 kv feeder program will apply to any 11 kv feeder which meets the following criteria: I. The 11 kv feeder performance based on: a. 3 year average feeder SAIDI in worst 10%; AND b. 3 year average feeder SAIDI 150% of the MSS SAIDI Limit for the applicable feeder category; OR II. The 11 kv feeder performance based on: a. 3 year average feeder SAIFI in worst 10%; AND b. 3 year average feeder SAIFI 150% of the MSS SAIFI Limit for the applicable feeder category; Based on the criteria, Energex has determined the feeders which will be classified as worst performing for the coming financial year and their current 2016/17 performance shown in Table 36. This includes 145 feeders of which 56 are Urban and 89 are Rural. As outlined in Table 35 above, these feeders can be defined as worst performing due to either SAIDI or SAIFI performance. Therefore, the details presented in Appendix G have been split to show SAIDI worst performing feeders and SAIFI worst performing feeders. However, there are a number of feeders which appear in both lists. Table /18 Worst Performing Feeder List Current Performance (2016/17) 3 Year Average Feeder SAIDI (mins) 3 Year Average Feeder SAIFI (int.) Minimum Average Maximum Minimum Average Maximum Urban , Rural , Note that the minimum and average SAIDI values are only for those worst performing feeders which have a SAIDI which is higher than the 150% SAIDI threshold. Similarly, the minimum and average SAIFI values are only for those feeders which have a SAIFI higher than the 150% SAIFI threshold DAPR 2017/ /22

145 Urban feeders The urban worst performing feeder list consists of 31 feeders in the SAIDI list, and 33 feeders in the SAIFI list. However, 10 of these feeders appear in both lists, resulting in 54 unique worst performing feeders. Interruptions on the low voltage network contributed an average of 11.5% to the performance of the worst performing urban SAIDI feeders. The contribution from interruptions on the sub-transmission network to the worst performing feeders is lower for the worst performing SAIDI feeders, with an overall average SAIDI contribution of 6.6%. However, this increases to 17.6% for the worst performing SAIFI feeders. The two highest contributors to the number of outages over the last three years were planned interruptions and Asset failures which in total made up 59% of all high voltage interruptions on the worst performing SAIDI feeders. Nine urban feeders identified on the SAIDI list have significantly improved their performance over the last two years, and have achieved a greater than 40% reduction when compared to the three year reported history. These feeders are unlikely to remain as worst performing feeders next year. Rural feeders The rural worst performing feeder list consists of 82 feeders in the SAIDI list, and 79 feeders in the SAIFI list. However, 73 of these feeders appear in both lists, resulting in 88 unique worst performing feeders. Interruptions on the low voltage network contributed an average of 5.1% to the performance of the worst performing rural SAIDI feeders. The contribution from interruptions on the sub-transmission network to the worst performing feeders is higher against the worst performing SAIDI feeders, with an overall average SAIDI contribution of 14.2%. However, this increases to 33.9% for the worst performing SAIFI feeders. The highest contributor to the number of outages over the last three years was planned interruptions, which made up 68.9% of all high voltage interruptions. A full report on Energex s 2017/18 Worst Performing 11 kv Feeders is available in Appendix G Safety Net Target Performance Energex s Distribution Authority DO7/98 (DA) details customer safety net performance reporting obligations for the purposes of reviewing network investment criteria. A detailed review of network events over the 2016/17 period was undertaken. The review investigated breaches of the customer safety net targets outlined in the Distribution Authority and described in Appendix C. Four events were shortlisted for detailed investigations. Investigations into each of these events revealed that all involved non-credible events for the purposes of planning and investment. Therefore there are no network events in the 2016/17 period where the customer safety net targets were breached DAPR 2017/ /22

146 Chapter 11 Power Quality Customer Experience Power Quality Supply Standards, Codes Standards and Guidelines Power Quality Performance in 2016/17 Power Quality Non-Compliance Corrective Actions Risk Assessment Power Quality Compliance Processes DAPR 2017/ /22

147 11 Power Quality 11.1 Customer Experience Energex traditionally tracks the customer experience by the number of power quality enquiries it receives. Figure 40 shows that the overall number of enquiries on a normalised basis per 10,000 customers per month varies significantly from month to month and displays some seasonality, being higher over the summer periods. However the overall long-term trend measured over the last 6 years is relatively stable. Figure 41 shows a breakdown of the enquiries received by the reported symptoms over the last 12 months, with the largest identifiable category, at 38%, related to solar PV issues. These are usually associated with customer installations where solar PV inverters could not export without raising voltages above statutory limits. Although inverters are designed to disconnect when voltage rises excessively, regular occurrences of this reduce the level of electricity exported and can often cause voltage fluctuations and customer complaints. Figure 42 shows the number of solar related voltage enquiries on a 12 month rolling basis over the last three years. This shows a relatively stable number since March 2015 averaging around 400 enquiries p.a. It has been observed that the months from January to June 2017 are showing gradual increases, this potential upward trend will be monitored. A revised connection standard for micro-embedded generating units within the range 0 30 kva was issued with an industry alert in May The new guidelines extend the power quality response mode introduced in October 2015 from a fixed 0.9 power factor lagging setting for inverters greater than 3 kva to an optional dynamic volt var response mode. The volt var response mode has a voltage range within which the generator is able to export its maximum real power at unity power factor, improving utilisation for the customer. For voltages outside this range there is a proportional increase in the reactive power supplied or absorbed by the inverters up to a set limit to help maintain network voltages. Solar PV customers are also advised to consider the benefits of installing 3-phase inverters over single-phase inverters for the same output capacity. Although 3-phase inverters are typically more expensive than single-phase inverters, spreading the inverter capacity across three phases can result in more stable operation, with less voltage and frequency swings and less nuisance tripping off DAPR 2017/ /22

148 Jul-11 Oct-11 Jan-12 Apr-12 Jul-12 Oct-12 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Enquiries per 10,000 Customers Figure 40 Power Quality Voltage Enquiries Figure 41 Power Quality Voltage Categories Solar PV related 38% Unknown 2% Low supply voltage 13% Voltage dips - minor or nuisance 15% Voltage dips - severe 1% Noises from appliances or lights 11% TV or radio interference 0% Waveform distortion or unbalance 3% Voltage spike 3% Voltage swell 14% DAPR 2017/ /22

149 Jun14 Sep14 Dec14 Mar15 Jun15 Sep15 Dec15 Mar16 Jun16 Sep16 Dec16 Mar17 Jun17 Quantity Figure 42 Solar Related Voltage Enquiries Power Quality Supply Standards, Codes Standards and Guidelines The Queensland Electricity Regulations and Schedule 5.1 of the NER lists a range of network performance requirements to be achieved by Network Service Providers (NSPs). Accordingly, Energex s planning policy takes these performance requirements into consideration when considering network developments. The tighter of the limits is applied where there is any overlap between the Regulations and the NER. Although the existing voltage standard in Queensland is 240 V, both Energex and Ergon Energy support a proposal to have the Electricity Regulations changed to 230 V to harmonise with the Australian Standard AS The Queensland Government Department of Energy and Water Supply (DEWS) have released a Regulatory Impact Statement on the proposal for public consultation. Further discussion on the proposal is outlined in Chapter 12 of the DAPR. Some of the requirements under the Regulations / Rules are listed below and further defined in Table 37, Table 38, Table 39 and Table 40. Magnitude of Power Frequency Voltage: During credible contingency events, supply voltages should not rise above the time dependent limits defined in Figure S5.1a.1 of the Rules. (For normal steady state conditions, a requirement of ±6% for low voltage and ±5% for high voltage of 22 kv or less is specified in the Electricity Regulations S13.); Voltage Fluctuations: A NSP must maintain voltage fluctuation (flicker) levels in accordance with the limits defined in Figure 1 of Australian Standard AS :1991. Although a DAPR 2017/ /22

150 superseded standard, it is specifically referenced under a Derogation of the Rules (S ) applicable to Queensland; Voltage Harmonic Distortion: A NSP must use reasonable endeavours to design and operate its network to ensure that the effective harmonic distortion at any point in the network is less than the compatibility levels defined in Table 1 of Australian Standard AS/NZS :2001; and Voltage Unbalance: A NSP has a responsibility to ensure that the average voltage unbalance measured at a connection point should not vary by more than the amount set out in Table S5.1a.1 of the Rules. Table 37 Allowable Variations from the Relevant Standard Nominal Voltages Voltage Levels Electricity Regulations NER Low voltage (less than 1 kv) ±6% 1 ±10% Medium voltage (1 kv to 22 kv) ±5% 1 ±10% High voltage (22 kv to 132 kv) As Agreed ±10% 1 Limit is only applicable at customer s terminals. Table 38 Allowable Planning Voltage Fluctuation (Flicker) Limits Voltage Levels Electricity Regulations NER Low voltage (less than 1 kv) Not Specified Pst = 1.0, Plt =0.8 (ΔV/V 5%) Medium voltage (11 kv and 33 kv) Not Specified Pst= 0.9, Plt=0.8, (ΔV/V 4%) High voltage (33 kv to 132 kv) Not Specified Pst= 0.8, Plt=0.6, (ΔV/V 3%) Table 39 Allowable Planning Voltage Total Harmonic Distortion Limits Voltage Levels Electricity Regulations NER Low voltage (less than 1 kv) Not Specified 7.3% Medium voltage (11 kv) Not Specified 6.6% Medium voltage (33 kv) Not Specified 4.4% High voltage (110 kv, 132 kv) Not Specified 3% DAPR 2017/ /22

151 Table 40 Allowable Voltage Unbalance Limits Voltage Levels Electricity Regulations NER Low voltage (less than 1 kv) Not Specified 2.5% Medium voltage (1 kv to 33 kv) Not Specified 2% High voltage (33 kv to 132 kv) Not Specified 1% Energex s Supply and Planning Manual is the main document describing its planning policy with respect to power quality. This applies to all supply and distribution planning activities associated with the network. It describes strategies that customers can adopt to improve voltage quality, particularly with respect to the installation of equipment that has the potential to reduce power quality Power Quality Performance in 2016/ Power Quality Performance Monitoring Processes for power quality monitoring have been developed from the requirements of the Queensland Electricity Regulation and the Rules. In the case of voltage sags (refer to section ), indices have been adopted that are consistent with proposals from the Australian Power Quality and Reliability Centre at the University of Wollongong. The introduction of a distribution transformer monitoring program in 2011/12 has provided a substantial source of data for analysis. This program involves the installation of remotely monitored electronic metering on distribution transformers installed throughout Energex s network and is providing an insight into power quality performance at the junction between the 11 kv and LV network. As of the end of June 2017, metering equipment had been commissioned at 16,317 sites. Data collected at these sites is analysed annually to generate the figures shown on the following pages. It is acknowledged that voltage is likely to be worse out along the LV circuit compared to at the distribution transformer for both peak load and light load conditions (or times of peak solar PV generation in high penetration areas). To address this limitation, Energex introduced a new program in 2016/17, consistent with its power quality strategic plan, to install three phase voltage only monitors at the end of LV circuits in areas assessed to have a higher risk of high voltage (e.g. high solar PV penetration areas with long lengths of overhead circuit). Energex also completed a pilot project to install power quality monitoring in up to 3,000 domestic customer premises in a relatively localised area of the network. Sufficient data from this program is now available for reporting for 2016/17. The expanded monitoring will enable Energex to further understand and quantify the power quality performance being delivered to customers and the impacts of solar PV DAPR 2017/ /22

152 Steady State Voltage Regulation Figure 43 is a histogram showing the distribution of all voltage measurements (10 minute intervals in accordance with Australian Standard AS ) recorded at the LV terminals of distribution transformers in the monitoring scheme in the last 12 months ending 30 June This standard classifies sites with more than 1% of measurements (100 minutes) outside limits during a full week, as being non-compliant. The volts upper limit on the graph is the maximum service voltage specified in the Queensland Electricity Regulation. The volts lower limit is specified in Energex s Supply and Planning Manual and is aimed at satisfying the customer s load forecast in new developments. It has been selected to provide a reasonable degree of confidence that the lowest voltage supplied to customers some distance from the transformer is above the volts service minimum. Figure 43 shows that 0.3% of all measurements are above the volts upper limit. By contrast 15% of all measurements from monitored transformers are below the nominal lower limit and indicates that some customers at the end of LV feeders could receive low volts for periods of time. In areas where there are low average customer peak demands or short LV feeders, the risk of low customer voltage is reduced. Further analysis of monitored transformers is continuing as more sites are fitted with electronic monitoring. This analysis is enhanced in 2016/17 with data progressively available from the rollout of 189 LV circuit monitors installed at the end of LV circuits on pole distribution transformers with high solar PV penetration and the domestic power quality trial at 3,000 customer premises. The take-up of solar PV is substantially greater in South East Queensland than in Southern states and as a result the requirement to monitor power quality is commensurately greater. Energex has completed a review of its voltage regulation standards for substation line drop compensation and distribution transformer tap settings to improve these out of limit measurements (refer section 11.4) DAPR 2017/ /22

153 Percentage of all Measurements Cumulative Percentage of all Measurements Figure Month Voltage Profile of Distribution Transformer Measurements 14.0% 100% 12.0% 10.0% 8.0% 6.0% 15% of measurements are below the lower voltage design limit of 0.3% of measurements are above the upper statutory voltage limit of V 90% 80% 70% 60% 50% 40% 4.0% 30% 20% 2.0% 10% 0.0% Voltage 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All phase to neutral measurements are included in the figure and no averaging of phase measurements are used. Note 3: Data is from 11,521 transformers for a 12 month period to 30 June Note 4: Statutory limit applies at consumer s terminal. Figure 44 shows a histogram of all voltage measurements (10 minute intervals) for the LV circuit monitors. Due to the monitoring site selection process, this set of measurement sample of sites provides insight into what voltages are experienced greater than 400 m from the transformer on overhead LV areas with higher levels of PV penetration. Figure 44 shows that the voltages observed at these locations are typically within the expected range. There are some limited excursions above this limit that are expected to be related to voltage rise as a consequence of solar exports. Figure 45 shows a histogram of all voltage measurements (10 minute intervals) for the customer premise monitors. The customer premise monitoring sites were selected to represent customers at various distances along networks where PV is installed in the area and overhead LV reticulation is used. Figure 45 shows that 0.1% of recordings at these sites are above the upper threshold. Figure 46, Figure 47 and Figure 48 shows the 99th, 50th and 1st percentile values repectively for all the monitored transformer sites. These graphs differ from Figure 43 in that they esentially depict the maximum (99th percentile), average (50th percentile) and minimum (1st percentile) voltages measured at each site over the 12 month period. These graphs shows that 8.4% of the monitored sites recorded a maximum voltage above the volts upper limit whilst 69.6% of sites had minimum voltage below the 242 volts design limit DAPR 2017/ /22

154 Percentage of all Measurements Cumulative Percentage of all Measurements Figure Month Voltage Profile of LV Circuit Monitors Measurements 10.0% 100% 9.0% 90% 8.0% 7.0% 6.0% 0.6% of measurements are above the upper statutory voltage limit of V 80% 70% 60% 5.0% 4.0% 3.0% 2.3% of measurements are below the lower design limit of 232 V 50% 40% 30% 2.0% 20% 1.0% 10% 0.0% Voltage 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All phase to neutral measurements are included in the figure and no averaging of phase measurements are used. Note 3: Data is from 189 pole top monitors for a 12 month period to 30 June Note 4: Statutory limit applies at consumer s terminal DAPR 2017/ /22

155 Percentage of all Measurements Cumulative Percentage of all Measurements Figure Month Voltage Profile of Customer Premise Monitors Measurements 10.0% 100% 9.0% 90% 8.0% 7.0% 6.0% 5.0% 0.3% of measurements are below the lower statutory voltage limit of V 0.1% of measurements are above the upper statutory voltage limit of V 80% 70% 60% 50% 4.0% 40% 3.0% 30% 2.0% 20% 1.0% 10% 0.0% Voltage 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All phase to neutral measurements are included in the figure and no averaging of phase measurements are used. Note 3: Data is from 2,009 customers for a 12 month period to 30 June Note 4: Statutory limit applies at consumer s terminal DAPR 2017/ /22

156 Percentage of Monitored Transformers Cumulative Percentage of Monitored Transformers Figure 46 99th Percentile Voltage Profile of all Monitored Transformers 16.0% 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 0.0% Voltage 8.4% of sites recorded maximum voltage above the upper statutory voltage limit of V 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All measurements are the percentile figures for the individual monitored transformer sites. Note 3: Data is from 11,487 transformers for a 12 month period to 30 June Note 4: Statutory limit applies at consumer s terminal DAPR 2017/ /22

157 Percentage of Monitored Transformers Cumulative Percentage of Monitored Transformers Figure 47 50th Percentile Voltage Profile of all Monitored Transformers 18.0% 100% 16.0% 90% 14.0% 12.0% 10.0% 8.0% 15.2% of sites recorded average voltage above the lower design voltage limit of 242 V 0.1% of sites recorded average voltage above the upper statutory voltage limit of V 80% 70% 60% 50% 40% 6.0% 30% 4.0% 20% 2.0% 10% 0.0% Voltage 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All measurements are the percentile figures for the individual monitored transformer sites. Note 3: Data is from 11,487 transformers for a 12 month period to 30 June Note 4: Statutory limit applies at consumer s terminal DAPR 2017/ /22

158 Percentage of Monitored Transformers Cumulative Percentage of Monitored Transformers Figure 48 1st Percentile Voltage Profile of all Monitored Transformers 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 69.6% of sites recorded minimum voltage below the lower voltage design limit of V 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0.0% Voltage 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All measurements are the percentile figures for the individual monitored transformer sites. Note 3: Data is from 11,487 transformers for a 12 month period to 30 June Note 4: Statutory limit applies at consumer s terminal. Figure 49, Figure 50 and Figure 51 shows the 99th, 50th and 1st percentile values respectively for all the monitored LV circuits. These graphs depict frequency distribution of the maximum (99th percentile), average (50th percentile) and minimum (1st percentile) voltages measured at each site over the 12 month period. These graphs show that 18.7% of the monitored sites recorded a maximum voltage above the volts upper limit whilst 52% of sites had minimum voltage below the 232 volts design limit. Figure 50 shows that the 50th percentile values for all LV monitored circuits are within the upper and lower limits DAPR 2017/ /22

159 Percentage of Monitored Transformers Cumulative Percentage of Monitored Transformers Figure 49 99th Percentile Voltage Profile of all monitored LV circuits 18.0% 16.0% 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 18.7% of site recorded maximum voltage above the upper statutory voltage limit of V 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0.0% % Voltage Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All measurements are the percentile figures for the individual monitored transformer sites. Note 3: Data is from 807 pole top monitors for a 12 month period to 30 June Note 4: Statutory limit applies at consumer s terminal DAPR 2017/ /22

160 Percentage of Monitored Transformers Cumulative Percentage of Monitored Transformers Figure 50 50th Percentile Voltage Profile of all monitored LV circuits 16.0% 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 0.0% Voltage 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All measurements are the percentile figures for the individual monitored transformer sites. Note 3: Data is from 807 pole top monitors for a 12 month period to 30 June Note 4: Statutory limit applies at consumer s terminal DAPR 2017/ /22

161 Percentage of Monitored Transformers Cumulative Percentage of Monitored Transformers Figure 51 1st Percentile Voltage Profile of all monitored LV circuits 9.0% 8.0% 7.0% 6.0% 5.0% 4.0% 3.0% 2.0% 1.0% 0.0% 52% of site recorded minimum voltage below the lower voltage design limit of 232 V Voltage 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All measurements are the percentile figures for the individual monitored transformer sites. Note 3: Data is from 807 pole top monitors for a 12 month period to 30 June Note 4: Statutory limit applies at consumer s terminal. Figure 52, Figure 53 and Figure 54 shows the 99th, 50th and 1st percentile values repectively for all the monitored customers. These graphs depict frequency distribution of the maximum (99th percentile), average (50th percentile) and minimum (1st percentile) voltages measured at each site over the 12 month period. These graphs show that 1% of the monitored sites recorded a maximum voltage above the volts upper limit whilst 2.6% of sites had minimum voltage below the volts design limit. Figure 53 shows that the 50th percentile values for all monitored customers are within the upper and lower limits. Energex is addressing high voltage exceedance through a range of capital and operating solutions. In conjunction with this, low voltage exceedance will be addressed through the future introduction of the 230 volts standard, which will provide an additional 4% range. This should give greater flexibility to manage voltage and help to mitigate the growth in voltage related issues once distribution transformers have been adjusted to their optimal tap settings. The adoption of the 230 volts standard in conjunction with resetting of voltage profiles and LV remedial works is further discussed in section DAPR 2017/ /22

162 Percentage of Monitored Transformers Cumulative Percentage of Monitored Transformers Figure 52 99th Percentile Voltage Profile of all monitored customers 16.0% 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 1.0% of site recorded maximum voltage above the upper statutory voltage limit of V 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0.0% % Voltage Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All measurements are the percentile figures for the individual monitored transformer sites. Note 3: Data is from 2,938 customer monitors for a 12 month period to 30 June DAPR 2017/ /22

163 Percentage of Monitored Transformers Cumulative Percentage of Monitored Transformers Figure 53 50th Percentile Voltage Profile of all monitored customers 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 0.0% Voltage 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All measurements are the percentile figures for the individual monitored transformer sites. Note 3: Data is from 2,938 customer monitors for a 12 month period to 30 June DAPR 2017/ /22

164 Percentage of Monitored Transformers Cumulative Percentage of Monitored Transformers Figure 54 1st Percentile Voltage Profile of all monitored customers 10.0% 9.0% 8.0% 7.0% 6.0% 100% 90% 80% 70% 60% 5.0% 4.0% 3.0% 2.0% 1.0% 2.6% of site recorded minimum voltage below the lower voltage statutory limit of V 50% 40% 30% 20% 10% 0.0% Voltage 0% Note 1: Columns show the percentage of values within 1 volt intervals. Note 2: Measurements are treated on a per phase basis. All measurements are the percentile figures for the individual monitored transformer sites. Note 3: Data is from 2,938 customer monitors for a 12 month period to 30 June Voltage Unbalance Figure 55 is a histogram displaying the distribution of voltage unbalance measurements taken from all monitored transformers and a cumulative count of that distribution in the last 12 months ending June Similar to the voltage distribution curves above, it displays the percentage of unbalance measurements that are above the 2.5% maximum acceptable threshold specified in the Rules. The graph shows that 0.06% of measurements are above the rules requirement DAPR 2017/ /22

165 Percentage of all Unbalance Measurements Cumulative % of all Unbalance Measurements Figure 55 Voltage Unbalance Factor Profile of Distribution Transformer Measurements 18.0% 16.0% 100% 90% 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 0.06% of measurements exhibited VUFs above the 2.5% limit 80% 70% 60% 50% 40% 30% 20% 10% 0.0% 0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.1% 3.7% Voltage Unbalance Factor (%) 0% Note 1: Columns show the percentage of values within 0.1% intervals. Note 2: Data is from the equivalent of 11,487 transformers for a 12 month period to 30 June Note 3: Statutory limit applies at consumer s terminal Harmonic Distortion Total harmonic distortion (THD) is a measure of the impurity of the supply voltage and in an ideal scenario would be negligible. Data from monitored distribution transformers was analysed for THD and this is displayed in Figure 56 as a histogram alongside the cumulative distribution of all measurements over the last 12 months ending 30 June The graph shows that the levels of THD are well below the 8% threshold stipulated in Australian Standard AS :2001 (electromagnetic compatibility limits). Typical sources of distortion include electronic equipment incorporating switch mode power supplies, modern air-conditioners with variable speed drive inverters and solar PV inverters DAPR 2017/ /22

166 Percentage of all THD Measurements Cumulative % of all THD Measurements Figure 56 Total Harmonic Distortion Profile of Distribution Transformer Measurements 10.0% 100% 9.0% 90% 8.0% 7.0% 6.0% 5.0% 4.0% 3.0% 2.0% 1.0% 0.1% of measurements exhibited THD above the 8% limit. 80% 70% 60% 50% 40% 30% 20% 10% 0.0% 0% 0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 6.0% 7.0% 8.0% 9.0% Percent Total Harmonic Distortion Note 1: Columns show the percentage of values within 0.1% intervals. Note 2: Measurements are treated on a per phase basis. All phase to neutral measurements are included in the figure and no averaging of phase measurements are used. Note 3: Data is for a 12 month period to 30 June Voltage Sags Sags are a temporary reduction in voltage and are sometimes associated with the temporary dimming of incandescent lights or slowdown in electric motors. They have two components. These are the level to which the voltage drops and the duration of the voltage excursion. The University of Wollongong has devised a methodology which takes both of these factors into consideration to produce a single unit of measure called a Sag Severity Indicator (SSI). An SSI of less than 1 is desirable and approximates the threshold defined by the Computer and Business Equipment Manufacturers Association (CBEMA) as being acceptable to electronic equipment. Energex s use of the SSI is to highlight potential impacts to a generalised class of sensitive equipment. The impact is usually triggered by disruption to the sensitive equipment (e.g. OV or UV trip, malfunction, damage) with consequential impacts depending on the class of customer and their processes; for commercial and industrial customers, disruption to the sensitive equipment may cause an uncontrolled shutdown of a process, resulting in possible damage to primary plant or lost production, wastage and downtime. It is important to note that an SSI limit of 1 is only a guide and not a compliance limit. Figure 57 shows the results of the SSI analysis of data collected from the distribution transformer monitoring program. About 73.8% of sag events have a SSI of greater than 1, which exceeds the limits DAPR 2017/ /22

167 Percentage of all SSI Values Cumulative Percentage of all SSI Values defined by the CBEMA curve. The SSI limit is a guide value, and above this level customers with sensitive equipment may have impacts. With 97,354 sag events in about 11,521 transformer years of data, the overall sag frequency for the period was approximately 8 sags per year per transformer. Energex is in the early stages of gathering this data. Analysis of the data is ongoing to determine what actions are required. Figure 57 Sag Severity Indicator Profile of Distribution Transformer Measurements 6.0% 120% 5.0% 4.0% 73.8% of sags have SSI >1 and effectively exceeds the CBEMA curve 100% 80% 3.0% 60% 2.0% 40% 1.0% 20% 0.0% Sag Severity Indicator 0% Note 1: Columns show the percentage of values within SSI intervals of 0.1. Note 2: Events are treated on a per phase basis so that those affecting more than one phase simultaneously are treated as multiple events. Note 3: Time aggregation where further processing is applied to events less than 60 sec apart has not been implemented. Note 4: Data is for a 12 month period to 30 June 2017 during which time 11,521 transformers experienced sag events Power Quality Non-Compliance Corrective Actions Energex s voltage management strategy focusses on the impacts on low voltage customers. It considers the changing network configurations, increasing customer peak demands, the high penetration of solar PV and its continued growth and the prospect of battery energy storage systems. Energex has commenced to implement the strategy through a number of programs and initiatives. Based on Energex s models and measurements, the number of areas forecast to have issues requiring an augmentation solution was determined for solar PV penetration levels exceeding 40% of DAPR 2017/ /22

168 the local transformer rating and where Energex LV circuit lengths exceed 400 m (LV circuit lengths to the customer can add a further 400 m). The number of impacted areas identified by these criteria in 2016/17 is 1,449. As a proportion of the total transformer population this is still a relatively small impact representing less than 3% of total transformers and 1.1% of customers but increases to 7% of transformers and 2.3% of customers which have solar PV penetration above 30% and where circuit length exceeds 400 m. Although the selection criteria used by Energex are based on simplified models, evidence suggests that the assumptions made are reasonable and prudent. To address the key drivers, a range of capital program initiatives are shown in Table 41. Some of the initiatives are a continuation or expansion of existing programs and some are new, being required to address the emerging issues, e.g. high transformer neutral currents due to the influence of solar PV. This capital program will be supported by operating initiatives that include company initiated investigations addressing solar issues, rebalancing of the LV phase connections and resetting of distribution transformer taps. The monitoring program will allow Energex to manage voltage within prescribed limits of 240 V ±6% at customer terminals. It will also address safety risks in targeted areas by being able to monitor potential deterioration in asset performance such as loss of neutral and be able to respond proactively to avoid high safety consequences such as equipment damage and house fires. Longer-term better analytics will assist Energex to lower overall capital costs of managing voltage across the network, support the introduction of the proposed 230 V standard, proactively improve power quality to customers to achieve legislative compliance and reduce organisational risk. The level of Augex spend on monitoring and remediation works is well targeted to areas expected to be impacted on the basis of measurements and modelling and will produce financial savings that would otherwise result in further increases in reactive expenditures DAPR 2017/ /22

169 Table 41 Summary of Power Quality 2017/18 Initiatives Initiative Title 2016/17 units 2017/18 Proposed units Monitoring / Reporting & Data Analytics Distribution Transformer monitoring (<100 kva) Pole Distribution Transformer monitoring 2,706 1,300 ( 100 kva) Pole 1 Distribution Transformer monitoring Padmount LV Circuit monitoring Customer monitoring 1,000 Nil Rectification Works Uprate & Reconfigure LV Network (OH) Uprate & Reconfigure LV Network (UG) Nil Nil 1 Power Quality meters are installed as part of an LV fuse installation program. With regard to remediation measures that address the impacts of high levels of solar PV penetration, Energex has considered the practical range of network options shown in Table 42. In general, as the solar PV penetration level rises, so does the cost of remedial work. Table 42 Network Solutions for Varying Levels of solar PV Penetration Solar PV Penetration Level From 30% to 70% From 40% to 100% Network Solutions 1. Balance of PV load 2. Change transformer tap 3. 1 and 2 above 4. Upgrade transformer 5. Additional transformer (incl. reconfigure LV area) 6. Re-conductor mains From 100% to 200% 7. 1 to 6 above 8. New technology (On load tap transformer, LV regulator, Regformer, Statcom) As part of its Opex program, Energex will carry out targeted transformer tap adjustment programs and rebalancing programs to address voltage issues in areas with PV penetration exceeding 30%. This is DAPR 2017/ /22

170 supported by data showing significant numbers of distribution transformer tap settings on non-optimal settings and unbalance of voltages at distribution transformer LV terminals Risk Assessment Energex is managing the risks associated with high solar PV penetration and voltage rise on the LV network through the Power Quality (PQ) Strategy and the Strategic initiative to invest in fit for purpose smart technologies. The PQ strategy will provide enhanced LV visibility by rolling out PQ data monitors across the LV network and will ultimately be coupled into real-time State Estimation algorithms as part of the intelligent grid transformation. The most recent initiative extends monitoring from the LV distribution transformer terminals to the end of LV circuits and within customer switchboards. Based on the monitoring data and predictive models developed, Energex identifies and prioritise areas for PQ improvement. Compliance risks are also being managed through the revised connection standards for solar PV inverters / batteries and the future adoption of the 230 V standards Power Quality Compliance Processes Energex responds to customer voltage enquiries / complaints by carrying out a voltage investigation which may include the installation of temporary voltage monitoring equipment on the network and at customers premises and remediating as necessary. Due to the complexity of the network and the large number of sites involved, the management of voltage presents many challenges. To address these challenges, a proactive and systematic approach shown in Figure 58 is being adopted. This involves: Establishing suitable data acquisition (monitoring) and reporting systems to identify problem areas; Establishing objective measures and supporting systems for prioritising remedial works; Developing network models down to the LV that allow problem areas to be predicted; Implementing and tracking improvements from remediation programs; and Measuring results to refine the network model and remediation options. Figure 58 Systematic Approach to Voltage Management DAPR 2017/ /22

171 Energex has developed a series of reports from the Distribution Monitoring Analytics (DMA) platform to identify and prioritise power quality issues. The DMA platform also enables the large volume of power quality time series data captured from the monitoring devices to be more easily analysed with possible drivers such as solar PV penetration and network topology (e.g. length of LV circuit from transformer to customer) DAPR 2017/ /22

172 Chapter 12 Emerging Network Challenges Solar PV 230 V Low Voltage Standard Revised 0-30 kva Solar PV Connection Standard Electric Vehicles Battery Energy Storage Systems Land and Easement Acquisition Impact of Climate Change on the Network DAPR 2017/ /22

173 12 Emerging Network Challenges Energex faces a number of specific network challenges relating to balancing customer service and cost. These include the impact of solar PV, energy storage systems, electric vehicles and land and easement acquisition Solar PV Solar PV Emerging Issue and Statistics Energex has one of the highest capacity per-capita of residential rooftop solar PV in the world. One in every three detached homes in South East Queensland now have a solar PV system installed with over 45% of systems having an installed capacity of 3.5 kw or more.the overall growth in solar PV has trended upwards in applications in the last 12 months with around 1,663 new systems with capacity of around 11 MW connected per month. Part of the upward trend is likely to be associated with increasing use of solar leasing financial products (usually no or minimal upfront costs) and the increasing incidence of a solar PV systems being a standard inclusion in new homes. Energex now has a total of 331,197 (at June 2017) systems connected with an installed capacity of 1,225 MW, the majority of which are installed on residential rooftops. Figure 59 shows the increase in installed capacity associated with solar PV. This is leading to a large number of distribution transformers with high solar PV penetration, 11 kv feeders with very little load during the middle of the day and in some cases, 11 kv feeders experiencing reverse power flow. Traditionally, distribution networks around the world were designed to accommodate voltage drops arising from the flow of power from the high voltage systems through to the low voltage system. With the connection of embedded generation on the distribution network, particularly the large number of connections of rooftop solar PV to LV systems, in some areas power flows in the reverse direction from the LV to HV have occurred at times of peak solar generation. This reverse power flow is less predictable and leads to both voltage rise and voltage drop along the feeding network having to be managed to ensure voltage at customer terminals stays within statutory voltage limits. Energex is managing the risks associated with high solar PV penetration and voltage rise on the LV network through the Power Quality (PQ) Strategy and the Strategic initiative to invest in fit for purpose smart technologies. The PQ strategy will provide enhanced LV visibility by rolling out PQ data monitors across the LV network improving knowledge and decision making capability. The most recent initiative extends monitoring from the LV distribution transformer terminals to the end of LV circuits and within customer switchboards. Based on the monitoring data and predictive models developed, Energex identifies and prioritise areas for PQ improvement. Energex s proposed LV monitoring and remediation program, discussed in section 11.4 will address the community safety risks and meet legislative compliance. Energex introduced changes in October 2015 to the solar PV connection guideline to require AS 4777 compliant reactive controlled inverters to minimise voltage rise and is supporting the proposed change to the Electricity Regulations to introduce the 230 volt standard that will provide greater regulating voltage range. This is discussed further in section 12.2 and section DAPR 2017/ /22

174 The connection guidelines have been further updated to extend the reactive control mode from a fixed 0.9 power factor lagging setting for inverters greater than 3 kva to an optional dynamic volt var response mode. The volt var response mode has a voltage range within which the generator is able to export its maximum real power at unity power factor. For voltages outside this range there is a proportional increase in the reactive power supplied or absorbed by the inverters up to a set limit to help maintain network voltages. Solar PV customers are also advised to consider the benefits of installing 3-phase inverters over single-phase inverters for the same output capacity. Although 3-phase inverters are typically more expensive than single-phase inverters, spreading the inverter capacity across three phases can result in more stable operation, with less voltage and frequency swings and less nuisance tripping off. To help explain these benefits to customers, Energex is developing new web-based information explaining 3-phase inverter benefits in simple language so you can direct interested customers to it. Figure 59 Grid Connected solar PV System Capacity by Tariff Figure 60 shows the daily load pattern on a residential feeder out of Currimundi zone substation on the Sunshine Coast for four consecutive years as the penetration of solar PV systems on this feeder has grown. Despite the day shown having reduced solar radiation, the trend of increasing reduction of load on the feeder during daylight hours is apparent. There also appears to be some evidence of load being shifted away from daylight hours with higher loads in the pre-dawn and evening hours in the latter years. This may be as a result of customer s changing behaviour to maximise the benefit of the renewable feed in tariffs which are based on net rather than gross solar PV generation. However, there does not appear to be any change to the evening peak in the example shown DAPR 2017/ /22

175 0:00 1:30 3:00 4:30 6:00 7:30 9:00 10:30 12:00 13:30 15:00 16:30 18:00 19:30 21:00 22:30 Load (11 kv Amps) Figure 60 Impacts of Solar PV on Currimundi CMD15A (2nd Tuesday in November) /11/ /11/ /11/2015 8/11/ Time of Day Figure 61 shows how the number of transformers with high solar PV penetration connected has increased by 13% in the last 12 months, now representing around 19% of the total population of distribution transformers (based on 49,781 ground, padmount and pole transformers). Figure 62 reveals what impact this high penetration has on 11 kv distribution feeders, with an increase for the same period of 11%. Also the proportion of the population of 11 kv feeders with an excess of 1 MW of connected solar PV is around 27% (based on 1,740 urban and rural feeders with greater than zero customers and greater than one distribution transformer connected). Energex has obligations to maintain the low voltage at customer terminals of 240 V ±6% (225.6 V to V). Energex typically sets its transformer taps in the range of 242 V to 250 V in order to allow for voltage drop caused by peak load. The scope for voltage rise is in the range of 2% (5 V) to 5% (12 V) before regulated high voltage limits are reached. Generally networks can only tolerate solar PV penetration levels up to 30% and stay within the maximum voltage. Based on current Solar PV growth rates, Energex expects around transformers to reach this threshold each month. Although penetration levels above 30% are expected to cause problems, Energex has set its capital remediation program at a level above this in recognition that a range of Opex solutions will be in place to manage more moderate safety and legislative compliance issues. The level is currently set at 40% penetration and LV circuit lengths greater than 400 metres to the furthest customers in overhead networks DAPR 2017/ /22

176 Quantity Quantity Figure 61 Distribution Transformers with Solar PV Penetration > 25% of Nameplate Rating 10,000 9,800 9,600 9,400 9,255 9,339 9,466 9,592 9,680 9,781 9,895 9,200 9,120 9,000 8,800 8,600 8,652 8,733 8,832 8,951 8,400 8,200 8,000 Jul16 Aug16 Sep16 Oct16 Nov16 Dec16 Jan17 Feb17 Mar17 Apr17 May17 Jun17 Connected Figure 62 Distribution Feeders with Solar PV Penetration > 1000 kva Jul16 Aug16 Sep16 Oct16 Nov16 Dec16 Jan17 Feb17 Mar17 Apr17 May17 Jun17 Connected DAPR 2017/ /22

177 Figure 63 and Figure 64 shows the uptake of solar PV across the Energex network based on zone substation supply areas. Figure 63 indicates the total number of customers in each zone who have solar PV installed, and Figure 64 indicates the total installed capacity in the same areas. The five zone substation areas with the highest numbers have been highlighted on each map. Figure 63 Number of customers with Solar PV by Zone Substation DAPR 2017/ /22

178 Figure 64 Installed Capacity of Solar PV by Zone Substation DAPR 2017/ /22

179 Future Impacts of Solar PV on Asset Ratings The monitoring of NCC, ECC, and 2HR ratings of Energex switchgear and transformers continues as an on-going process due to the ever changing load profiles resulting from the connection of solar PV systems to the network. The Domestic / Mixed / Industrial / Continuous methodology of plant ratings continues to show a drift from Mixed to Domestic ratings due to new solar PV connections. In years gone by, the rate of solar PV connections was as high as 3,500+ connections per month; however, the current rate of connections over the last 12 months has stabilised to about 2,000 connections per month. Even with this reduction in connection rates, the impact of the new connections over the last 12 months has: 1. Continued to contribute to further lowering the load factors on many distribution transformers, zone transformers, and 11 kv feeders to below 0.5 on a regular basis; 2. At least 7 zone transformers (with a NCC rating up to 30 MVA) are now exporting back into the 33 kv network on multiple occasions, especially in autumn and spring shoulder conditions; 3. Over 30 zone substations have daytime loads of less than 1 MW for durations of up to 6 hours; 4. An additional 5 substations have had their load profile changed from Mixed to Domestic over the last 12 months; and 5. The increase of total network substation capacity, as a result of profile changes over the last 12 months, has risen from MVA to MVA. Of the 246 Energex substations under review, the following summary identifies the current categories of rating classifications of substations as: Continuous (8); Industrial (47); Mixed (43); and Domestic (148). Monitoring of network load profiles in the future is expected to realise a continuing trend of reducing load factors and transfer of plant from Mixed to Domestic classifications V Low Voltage Standard The high solar PV penetration is contributing to voltages on the low voltage network being outside of the regulated 240 volts ±6% range. Energex has assessed the impacts and considered the benefits for the introduction of the national 230 volts standard, which can provide an increased regulation range of +10% and -6%. Energex s proposed power quality programs are based on the current regulatory requirement to maintain statutory voltages within the range 240 V ±6% and will mainly target worst areas emerging from the existing high penetration of solar PV on the network. The introduction of the 230 V standard will not avoid these investments but should give greater flexibility to manage voltage and help to mitigate the growth in voltage related issues. The cost of this transition program (which will involve distribution transformer tap changes and modifications to Line Drop Compensation at the zone substation) over a realistic timeframe will be considered in future funding proposals DAPR 2017/ /22

180 Energex and Ergon Energy have contributed to a Regulatory Impact Statement (RIS) for the transition to the 230 volts standard which has been prepared by the Department of Energy and Water Supply (DEWS). The RIS contains a number of options and timeframes to transition to the 230 V standard Revised 0-30 kva Solar PV Connection Standard Energex has pro-actively engaged with customers and the solar PV industry and has developed streamlined processes and information to guide customers and solar PV installers. Energex has over the years developed and revised joint connection standards with Ergon Energy for solar PV systems up to 30 kva. With the publication of the new AS4777 standard (in September 2015) the current connection standard for Energex requires inverters greater than 3 kva single phase to have reactive power control Systems less than 3 kva will still have automatic approval with constant power factor. The current connection standard will also allow automatic approval for 3 phase PV systems with reactive power control up to 15 kva. These changes have streamlined the connection processes and offer customers greater choice leading to improved outcomes for the customer, solar industry and distributor. The options will also promote increased equity by increasing solar PV hosting capacity. Energex and Ergon Energy have recently conducted a further review of the connection standard and will be publishing this in Energex and Ergon Energy have also embarked on a revision of the connection standards for embedded generation including inverter systems greater than 30 kva. A previous update for inverter energy systems (IES) eliminated the requirement for Neutral Voltage Displacement (NVD) protection on the 11 kv network for IES systems up to 200 kva. This protection was to ensure these low voltage connected embedded generators disconnected in the event of a fault on the 11 kv network, and was costly for the proponent to install. There was also a relaxation of the requirement for having a Registered Professional Engineer of Queensland (RPEQ) test and commission these installations and provide a report to Energex if they have passed the initial Stage 1 power quality assessment. The current review for embedded generators greater than 30 kw will separate the embedded generators into 2 types of connections; low voltage and high voltage. There are likely to be relaxed requirements for the protection of low voltage connected generators Electric Vehicles Plug in Hybrid Electric Vehicles (PHEVs) and pure Electric Vehicles (EVs) are a new class of electrical load that could have significant impact on the low voltage electricity network. Battery capacity of currently available PHEVs and EVs is in the range of 16 kwh (Mitsubishi) to 90 kwh (Tesla Model S). Tesla fast EV charging station (known as Supercharger) is 120 kw and capable of charging the Model S battery in just 40 minutes to 80% full capacity. Currently, EV uptake in Australia is amongst the lowest in the Organization for Economic Cooperation and Development (OECD) countries. In 2017, EVs account for only 0.01% of registered cars in Queensland. The uptake rate of EVs in near future is expected to stay steady due to factors such as DAPR 2017/ /22

181 0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 Per unit lack of national supporting policies and public EV charging infrastructure, high capital cost and distance anxiety. However, rapid development of lithium-ion battery technology could be a game changer. Energex has been monitoring the development of EVs and battery storage technology to better understand the impact of these emerging technologies on the distribution network. Energex has adopted a scenario-based approach for long term planning studies to deal with the uncertainty and forecast demand considering high penetration of emerging technologies. The aggregated impact of EVs on the high voltage network is not as significant as local capacity constraints on the low voltage distribution network. Uncontrolled EV charging refers to coincidence charging of multiple EVs from a traditional LV feeder (which was designed originally to supply residential customers). Under this scenario or with high penetration of EV s, significant network augmentation (such as transformer and feeder upgrades) will be required; this may consequently lead to higher electricity prices. However, intelligent EV charging in coordination with local network constraints known as controlled EV charging may avoid network augmentation and could generate energy sales revenue for distribution utilities and increase asset utilisation. Moreover, provided that electricity to charge the EVs is supplied from a renewable source, EVs provide environmental benefits to the society. Figure 65 Impact of Controlled and Uncontrolled EV Charging on a Residential Feeder Without EV Uncontrolled EV Charging Controlled EV Charging Time of day Figure 65 simulates the impact of controlled and uncontrolled EV charging on a typical residential feeder load curve with relatively high penetration of PV rooftops. This illustrates how charging EVs during off-peak and shoulder hours (where there is excess PV generation) could improve the utilisation factor without increasing the peak demand. Conversely, uncontrolled charging increases the peak demand significantly DAPR 2017/ /22

182 12.5 Battery Energy Storage Systems The awareness and intent to purchase Battery Energy Storage Systems (BESS) again increased among Energex customers with solar PV. Energex anticipates that this will continue as the technology matures and costs reduce. Many customers see BESS as a way to improve supply reliability, rather than reduce bill size, and very few Queensland households intend to go off grid in the near future. The uptake of BESS has the potential to provide benefits to both the customers and the distribution network, if coordinated. From the network perspective, BESS could be called upon to support assets during peak demand periods or to mitigate power quality issues during high solar PV generation periods. It is clear that customers expectations of the network are changing and Energex must accommodate these changes. A key challenge for Energex is identifying strategies to coordinate BESS to optimise benefits to the network and therefore reduce the cost to serve. These challenges include: Integration with existing control & operational systems; Limited engineering data measured on the low voltage network, where the majority of residential BESS will be installed; and Conflicting support requirements between customers, the network and even between different parts of the network. Once BESS reaches significant penetration levels, further challenges will include identifying how these systems can be incorporated into planning and forecasting functions. In order to meet and overcome some of these challenges, Energex has commissioned a range of projects under the Battery Energy Storage Systems Trial. The Energex BESS trials continue to explore the effects of BESS on peak demand and power quality. This is part of Energex s commitment to integrate renewable energy into South East Queensland s network and to provide customers more choice and control over their energy use and minimise expenditure on the network. The BESS trials will be conducted in two parts: Pilot demonstrations of residential and commercial BESS installations at different sites; and Market Based Battery Trial in conjunction with BESS manufacturers. The residential BESS demonstration site at Rocklea continues to draw interest from industry and customer stakeholder groups, including the Electrical Safety Office (ESO) and Emergency Services. The installation of the commercial BESS pilot site has commenced and continues to identify both the technical and non-technical challenges associated with connecting large scale systems/ The first stage of the Market Based Battery Trial has commenced with the installation of the first 15 sites nearing completion. Monitoring devices were installed in all participating homes to allow data to be remotely collected. The learnings from these trials will be used to extend the trial for the second stage. At the 2016 Ekka Royal Queensland Show, Energex and Ergon launched the Smart Energy Education House which was fitted with Solar PV, a residential battery system and a home energy management system. Over 50,000 show-goers visited the stand over the course of the show to be informed of emerging technologies and effective integration with the network. The key messages for DAPR 2017/ /22

183 customers were around safety guidelines and standards, particularly AS/NZS and the forthcoming AS/NZS Land and Easement Acquisition One of the key difficulties for large community infrastructure projects is the ability to locate infrastructure over large distances and across several communities. Without the land and property acquired in advance, there can be no design, construction or connection of new electricity infrastructure or non-network solutions to meet the increasing electricity demands within a region. Community expectations have risen over the years by increased calls for input and participation into these projects, which Energex must now consider for future works, while ensuring that statutory requirements are met regarding social, technical and environmental disciplines, all with the intent of providing a value for money outcome for all. Corridor easement acquisition projects often span over more than one regulatory period and there is increasing evidence that further upfront community engagement, planning and investigation will improve the ability of Energex to construct these corridors in a more timely fashion, once community and key stakeholders have predominantly endorsed the specific route determined for the new lines. Other changes that need to be assessed and addressed include: Changes to State planning policies or statutory compliance changes during project delivery; Time and costs associated with not gaining a community s input and endorsement for the location of such infrastructure, through the current consultation approach outlined within Community Infrastructure Designation guidelines; and Changes to Federal and State Acts and Legislation, including Environment Protection and Biodiversity Conservation (EPBC) Act, which now includes koalas (from May 2012) over the life of the project. In order to address these concerns, it has been identified that property and corridor projects need to commence up to five to six years in advance of the actual requirement date for new lines to be commissioned. A key risk with this requirement involves the likelihood of different, or non-network, solutions emerging when Regulatory Consultations are undertaken following shorter timeframes outlined in the NER. This will require further key resources and personnel and a dedicated budget to address planning, community collaboration and education as well as investigation of various routes in order to ensure the corridor selected meets the requirement of both statutory, key stakeholder and community expectations. These objectives must be met whilst also meeting Energex s internal requirements for value for money, technical, environment and socially responsible outcome Impact of Climate Change on the Network Climate change projections indicate increased storm and rainfall intensity, significant sea level rise as well as the potential for an increase in tropical cyclones tracking southward. This suggests that the likelihood of inundation of low lying Energex assets will increase which can result in customer outages, increased asset maintenance and reduced asset life DAPR 2017/ /22

184 Energex partners with various Queensland Government bodies (such as Queensland Climate Adaption Strategy Partners, Queensland Climate Resilient Council and Queensland Reconstruction Authority) to develop strategies dealing with climate change and to build more disaster resilient electrical infrastructure. Energex proposes to address the impacts of climate change by the following measures: Keep abreast of new storm surge and flood layers produced by Councils Undertake flood planning studies on network assets which are likely to be impacted by storm surges and flooding; and Upgrade overhead water crossings to the new flood standard. Energex has a program to adapt network assets to mitigate the risks of flood and bushfire events and has a proposed budget of approximately $2 million annually to continue that work. This is discussed further in section DAPR 2017/ /22

185 Chapter 13 Information and Communication Technology (ICT) ICT Investments 2016/17 Forward ICT Program DAPR 2017/ /22

186 13 Information and Communication Technology (ICT) 13.1 ICT Investments 2016/17 Table 43 contains a summary of ICT investments undertaken in 2016/17. These include projects which commenced prior to this year and investments which will not be completed until after 2016/17. As noted below, several projects have been deferred by a year or longer following the Queensland industry merger between Energex and Ergon Energy into Energy Queensland. Table 43 ICT Investments 2016/17 Description Cost $ M actual Geographic Information System (GIS) Replacement 8.25 Continuous Improvement & Minor Applications 7.70 Infrastructure & Communications (Including End User Devices) 6.81 Power Of Choice Program 2.91 ERP & EAM Transformation Program (Procurement Phase) 2.26 Customer and Market Systems Program 1.93 Total Note: Actuals noted include ICT Managed Capex and Opex investment only (i.e. does not include ICT investment funded through other portfolios already identified in other sections of this report). GIS Replacement Phase 1 Phase 1 of the program will finalise the replacement Energex s ageing master asset register and network model that has reached both technical and financial obsolescence. This phase of the replacement will incorporate a contemporary, flexible Geographic Information System (GIS) and will provide Energex with a single data source for its connectivity model catering for utility specific information needs (e.g. associating electrical characteristics to the model). Replacement of the master asset register will later be incorporated as part of the Energy Queensland Enterprise Digital Initiatives Program from 2017/18 onwards. Continuous Improvement & Minor Applications This included minor improvements and updates to work force automation, asset management, market systems, network operations systems, knowledge management systems, ERP system and customer service systems which support the operations of the Energex business. This also consists of minor ICT initiatives, including initiative expenditure carried over from 2015/ DAPR 2017/ /22

187 Infrastructure & Communications The renewal of Energex s ICT infrastructure assets is delivered in accordance with Energex s ICT Infrastructure Asset Renewal Guidelines. As ICT infrastructure and technology software assets age they become obsolete. To sustain the reliability and support of the ICT environment, an ongoing program is required to maintain these assets. Assets covered by the program include PC fleet (Desktops, Laptops), Windows Server equipment, Unix Server equipment, corporate data network equipment, Energex property works infrastructure, server storage infrastructure renewal and growth, asset renewal of ICT peripheral equipment including printers and mobile phones. The program also includes infrastructure software renewal of ICT technologies such as Exchange , integration technologies and database environments. This included the replacement of the existing Unified Communication and Collaboration (UCC) platform which had reached the end of its useful asset life. Power of Choice Program This program will deliver the ICT changes required to support substantial reforms to the National Electricity Market (NEM) following recommendations to the state and federal Governments by the AEMC s Power of Choice review which will provide consumers more options in the way they use electricity. This includes the sub-program for the Market Systems Modernisation to update many of Energex s Market Systems. The existing suite of Market Systems are being primarily enhanced or upgraded to meet the Power of Choice requirements. This program incorporates the current Customer Information System (CIS), service order management system, meter data management and Business to Business (B2B) systems. ERP/EAM Transformation Program Commencement of the planning and procurement phase for the replacement of Energex s Enterprise Resource Planning (ERP) and Enterprise Asset Management (EAM) systems began in 2016/17. Energex s core ERP/EAM system reached both technical and financial obsolescence in mid Renewal of the ERP and EAM systems with contemporary systems will provide an opportunity for Energex to consolidate satellite applications and migrate administrative business processes to accepted industry standards. This program will now be delivered as part of the Energy Queensland Enterprise Digital Initiatives Program. Customer and Market Systems Program This program focuses on customer-centric initiatives that improves the customer s end user experience and is inclusive of the Business Improvements & Automate Systems programs which will deliver contemporary digital capability for customer interactions DAPR 2017/ /22

188 13.2 Forward ICT Program With the recent merger of Energex and Ergon Energy, the ICT strategic vision has been reviewed and updated. The revised strategic vision is to create an information enabled enterprise that will efficiently support the transformation to a being a Digital Utility. The ICT strategy will be delivered by the following strategic themes: Business aligned ICT change This includes planning and development of change programs to support business transformation while optimising ICT system efficiency and effectiveness. This is in response to rapid growth in technology and the need to manage complexity in order to minimise cost and risk in the future; IT as a Service This will drive greater use of commodity ICT services, alternate sourcing approaches and modernisation of the applications portfolio. This strategy is in response to the growth in commodity ICT and cloud computing; and Managed Information This will drive operational efficiency through technology and information enablement, unlocking future value through broad access to secure information. This strategy is in response to emerging technologies including big data, mobility and social media. Forward investment for the ICT Portfolio will be focused around a key set of Digital Building Blocks focused on transitioning Energex into a Digital Utility. Figure 66 provides a breakdown of the Digital Building Blocks. Figure 66 Digital Building Blocks DAPR 2017/ /22